Adopted Rules Title 30

TITLE 30. ENVIRONMENTAL QUALITY

Part 1. TEXAS COMMISSION ON ENVIRONMENTAL QUALITY

Chapter 114. CONTROL OF AIR POLLUTION FROM MOTOR VEHICLES

The Texas Commission on Environmental Quality (commission or TCEQ) adopts amendments to §114.6 and §114.319. Sections 114.6 and 114.319 are adopted without changes to the proposed text as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10521) and will not be republished.

The amendments will be submitted to the United States Environmental Protection Agency (EPA) as a revision to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

On June 15, 2004, the Houston-Galveston-Brazoria (HGB) ozone nonattainment area was classified as a moderate nonattainment area under the eight-hour national ambient air quality standard (NAAQS) under the Federal Clean Air Act (FCAA) Amendments of 1990 (42 United States Code (USC), §§7401 et seq.). For the HGB area, defined by Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties, the TCEQ has developed this eight-hour ozone SIP revision in accordance with 42 USC, §7410. Hence, this rulemaking and HGB SIP revision is part of the first step in addressing the eight-hour ozone standard for the area.

The one-hour ozone NAAQS, which preceded the eight-hour ozone standard, was revoked June 15, 2005 (69 FR 23951). However, the one-hour ozone control strategies in the HGB area will remain in place. This set of strategies is extensive and will continue to reduce the amount of ozone precursors and ozone in the HGB airshed. On September 6, 2006 (71 FR 52656), EPA published approval of the HGB nonattainment area's one-hour ozone attainment demonstration and associated rules. The approval was published in six parts, covering the rules for the control of highly-reactive volatile organic compounds (HRVOC), the HRVOC emission cap and trade (HECT) program, the mass emission cap and trade (MECT) program for nitrogen oxides (NO _X ), the one-hour ozone attainment plan, the emissions credit banking and trading program, and the discrete emission credit banking and trading program. For a more complete background on the one-hour ozone SIP revisions please see Chapter 1 of the eight-hour ozone SIP revision that has been submitted for adoption concurrent with this rule package (Project Number 2006-027-SIP-NR).

In this rulemaking, the commission is adopting a revision to the definition of diesel fuel in §114.6(7) and §114.319 concerning affected counties and compliance dates as they are used in Subchapter H (relating to Low Emission Fuels). These revisions require that any fuel that is commonly or commercially known, sold, or represented as Marine Distillate fuel X (DMX), Marine Distillate fuel A (DMA), or Marine Gas Oil (MGO) that may ultimately be used to power a diesel-fueled compression-ignition engine located on a marine vessel in any of the counties listed in §114.319(b)(2), specifically: Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties, meet the low emission diesel fuel (LED) requirements. The commission has been made aware that certain owners or operators of marine vessels have been switching from regulated Grade No. 1-D and Grade No. 2-D diesel fuel (LED-compliant fuels) to diesel fuels commonly known as DMX, DMA, or MGO to avoid the LED regulations of Chapter 114. By regulating these marine fuels, the commission will be able to reduce NO _X by an estimated 0.9 tons per day (tpd) in the HGB nonattainment counties as listed in §114.319(b)(2).

DMX, DMA, Grade No. 1-D, and Grade No. 2-D diesel fuels are all light distillates that share many fuel parameters. Therefore, the commission does not anticipate major difficulties in the process of either changing vessel fuels back to LED-compliant Grade No. 1-D or Grade No. 2-D or having DMX or DMA marine fuels use approved additives as tested and approved under the methods of §114.315.

The grades of marine fuel that are included in this adoption are normally only used by harbor craft vessels (e.g., crew and supply boats, charter fishing vessels, commercial fishing vessels, ferry or excursion vessels, pilot vessels, towboats or push boats, tug boats, and work boats). Ocean-going vessels will not be included in these regulations because they typically use heavier marine residual fuels such as Marine Distillate fuel B (DMB), Marine Distillate fuel C (DMC), or other marine residual fuels that have a higher viscosity; therefore, they do not share the characteristics of lighter 1-D and 2-D diesel fuels.

The TCEQ participated in a Houston-Galveston Area Council (HGAC) stakeholder meeting in March 2006 to discuss potential control strategies. The TCEQ also conducted an informational meeting October 5, 2006, to present the rule concepts and answer questions.

SECTION BY SECTION DISCUSSION

The adopted change to §114.6 amends the definition of diesel fuel to include marine grades of fuel commonly known as DMX, DMA, or MGO in accordance with the active version of International Organization for Standardization (ISO) 8217. Currently, the definition only refers to Grade No. 1-D and Grade No. 2-D diesel fuels. This change in definition, along with the change to §114.319 concerning affected counties, will require DMX, DMA, or MGO grades of marine fuel to be compliant with the LED regulations in the eight-county HGB area. By including these fuels in the LED regulation, the commission will reduce NO _X and other emissions in the HGB ozone nonattainment area. These reductions will help this area make positive progress towards attainment of the ozone NAAQS.

The adopted change to §114.319 adds a new subsection (d) to include a compliance schedule for the introduction of LED-compliant diesel fuels commonly known as DMX, DMA, or MGO to the HGB area. The compliance schedule provides sufficient time for refiners to make modifications that may be necessary to produce a compliant LED fuel and provides sufficient time for facilities downstream of the refiner to deplete existing inventories of noncompliant fuels. Compliance is phased in to ensure adequate supply of compliant fuels will be available at the retail level by January 1, 2008. A revision is also made to subsection (a) to refer to the schedule as added in subsection (d).

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking considering the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking does not meet the definition of a "major environmental rule." A major environmental rule means a rule, the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure, and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The specific purpose of the adopted amendments to §114.6 and §114.319 is to subject certain grades of marine fuels used in the HGB nonattainment counties to the LED program requirements. These grades of marine fuels have been added as part of the strategy to reduce emissions of NO _X . This adopted rulemaking is anticipated to positively affect human health and the environment by reducing NO _X emissions that help form ozone and not adversely affect the economy or productivity in any material manner. Moreover, the adopted rules would make positive progress towards attainment of the federally established eight-hour ozone standard in the HGB area. Therefore, the adopted rulemaking does not constitute a major environmental rule and thus is not subject to a formal regulatory analysis.

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

Specifically, this rulemaking action, which is designed to reduce NO_X emissions from marine vessels in the HGB area that have not been included in the LED program previously, does not exceed an express requirement under state or federal law. Furthermore, there is no contract or delegation agreement that covers the topic that is the subject of this action. Finally, this rulemaking action was not developed solely under the general powers of the agency, but is authorized by specific sections of Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act), and the Texas Water Code, which are cited in the STATUTORY AUTHORITY section of this preamble, including Texas Health and Safety Code, §§382.012, 382.017, and 382.202. Therefore, the adopted rulemaking does not exceed a standard set by federal law, exceed an express requirement of state law, exceed a requirement of a delegation agreement, nor is adopted solely under the general powers of the agency.

Based on the foregoing, this rulemaking action is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b). The commission solicited comments on the Regulatory Impact Analysis Determination during the public comment period, but did not receive any comments during the public comment period.

TAKINGS IMPACT ASSESSMENT

Under Texas Government Code, §2007.002(5), "taking" means 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 §17 or §19, Article I, Texas Constitution; or a governmental action that affects an 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, determined by comparing the market value of the property as if the governmental action is not in effect and the market value of the property determined as if the governmental action is in effect.

The commission completed a takings impact assessment for the adopted rulemaking action under Texas Government Code, §2007.043. The specific purpose of these revisions is to achieve reductions of NO _X emissions from marine vessels to reduce ozone formation in the HGB nonattainment area and thus help bring this area into compliance with the air quality standards established under federal law as NAAQS for ozone. As adopted, the amendment to §114.6 adds certain grades of marine fuels to the definition of diesel fuel, thus subjecting the fuels used in the HGB counties to LED requirements according to the schedule adopted in §114.319. These amendments will not place a burden on private, real property in a manner that would require compensation to private real property owners under the United States Constitution or the Texas Constitution because this action does not require an investment in the permanent installation of new refinery processing equipment. The adoption also will not affect private real 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. Therefore, the adopted amendments will not cause a taking under Texas Government Code, Chapter 2007.

The commission solicited comments on the Takings Impact Assessment during the public comment period. One comment was received and is addressed in the Response to Comments section.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

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

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

PUBLIC COMMENT

The public hearings for this rulemaking were held on: January 29, 2007, 2:00 p.m. and 6:00 p.m., Houston-Galveston Area Council, 3555 Timmons Lane, Houston; January 31, 2007, 7:00 p.m., J. Erik Jonsson Central Library Auditorium, 1515 Young Street, Dallas; February 1, 2007, 2:00 p.m., Arlington City Hall Council Chambers, 101 W. Abrams Street, Arlington; February 1, 2007, 6:00 p.m., Midlothian Conference Center, 1 Community Circle, Midlothian; February 6, 2007, 2:00 p.m., Longview Public Library, 222 W. Cotton Street, Longview; and February 8, 2007, 2:00 p.m., Texas Commission on Environmental Quality, Building E, Room 201S, 12100 Park 35 Circle, Austin.

Energy Business Inc. (EBI), EPA, Harris County Public Health and Environmental Services (Harris County), Houston Sierra Club (HSC), and ORYXE Energy International, Inc. (ORYXE) submitted written or oral comment in support of the rulemaking. EBI, Galveston-Houston Association for Smog Prevention (GHASP), Kirby Inland Marine, LP (Kirby), Port of Houston Authority (Port Authority), and one individual expressed concerns and/or suggested changes to the proposal. The 8-Hour Ozone SIP Coalition (Coalition), Engine Manufacturers Association (EMA), Eternal Springs Wellness, Representative Jessica Farrar, Representative Ana E. Hernandez, one individual, and Mothers for Clean Air in Houston submitted written or oral comment not directly related to the LED marine rulemaking.

RESPONSE TO COMMENTS

Support of Rule

EPA, Harris County, and HSC commented that they support the changes proposed to Chapter 114, thereby ensuring more NO _X reductions. Mothers for Clean Air also commented that they do not oppose extending the use of low emission diesel to marine vessels.

The commission appreciates the support for changes in this rule.

ORYXE commented that they support the proposal to bring marine fuels under the requirements of the low emission diesel program to improve air quality in Texas. ORYXE supports the compliance deadlines and believes the timeline provides more than ample time to phase in the new rule. ORYXE also comments that there should be adequate supply of TxLED fuel, including fuel treated with an additive, available in the market by the proposed deadline.

The commission appreciates the support for changes in this rule and the statement that adequate supplies of LED and/or additives will be available.

In a letter concerning the Dallas-Fort Worth (DFW) SIP, the EPA commented that they support including the TxLED initiative in the SIP.

The commission appreciates the support for the LED program but would like to clarify that the LED marine regulations are only applicable to the marine diesel fuel that may ultimately be used to power a diesel-fueled compression-ignition engine located on a marine vessel in any of the eight counties of the HGB ozone nonattainment area. The LED regulations do not apply to marine diesel used in the DFW nonattainment counties.

EBI commented that they approve of adding harbor craft vessels and the DMA and DMX fuels to the regulations.

The commission appreciates the support for changes in this rule.

Locomotive Reductions

EPA commented that locomotive switcher engine NO _X emission reductions from TxLED were not included in the modeling for the DFW SIP. EPA Region 6 requested that the estimated emission reductions be provided.

The comment does not relate to the proposed LED marine rulemaking, and no changes to the rule have been made in response to it. The comment is related to the DFW Attainment Demonstration SIP (Project 2006-013-SIP-NR). A response to EPA's comment can be found in the DFW Attainment Demonstration SIP response to comments section.

Takings Impact Assessment

EBI commented that they do not agree with the Takings Impact Assessment and also find it inapplicable. EBI points out that a taking can be a taking of real, personal, or intangible property and that no real property is involved. However, EBI comments that they agree with the conclusion that establishment of regulations for harbor class marine vessels do not create a regulatory imposition on real property because a harbor class marine vessel is not real property.

The commission disagrees with the commenter that a Takings Impact Assessment is inapplicable. According to Texas Government Code, §2007.043(a), a governmental entity shall prepare a written takings impact assessment of a proposed governmental action. Part of this assessment is a determination by the agency as to whether the governmental action will constitute a taking. A rulemaking is defined as a "governmental action." The Takings Impact Assessment contained in this rulemaking fulfills this statutory requirement. The commission appreciates the commenter's agreement with the conclusion that this rulemaking does not constitute taking of private real property. However, the Texas Government Code's requirement to conduct this assessment remains regardless of whether real property is affected.

Expanding Affected Counties

The Port Authority commented that they believe restricting the applicability to only the eight-county nonattainment area of HGB limits the NO _X -reducing benefit and real world effectiveness of the proposed revision. The Port Authority also commented that limiting the counties to HGB would create an economic incentive for owner/operators of vessels to purchase fuel from areas outside the HGB area that are not subject to TxLED regulations and recommended expanding the applicability of the proposed revision to the remainder of the 110 counties, which will also keep the implementation of the rule simple for diesel fuel producers and distributors. Kirby commented that they strongly object to revising the TxLED regulations solely within the HGB nonattainment counties. Kirby stated that this action will create market forces that will lead other marine operators that operate in and through the HGB area to fuel vessels outside the HGB area in order to save up to $0.04 per gallon. Kirby, who will continue to use TxLED-compliant fuel, will be disadvantaged by this regulation on an annualized basis of $384,000. Kirby commented that the rulemaking as proposed undermines the emissions reduction from TxLED use. Kirby commented that they support the proposed revision only if TCEQ contemporaneously revises the areas affected to include all 110 TxLED counties. GHASP commented that the TxLED rules should be applied to the entire state.

The commission disagrees with the comments for applying the amended LED rules to the marine fuels used in all 110 counties. The commission considers the applicability of the rule to certain marine fuels in the eight-county HGB ozone nonattainment area to be sufficient at this time. This rule revision is part of the SIP strategy that is the first step in addressing the eight-hour ozone standard in the HGB area. The TCEQ is committed to attaining the standard as expeditiously as practicable. As a part of developing the HGB Eight-Hour Ozone Attainment Demonstration SIP revision, the TCEQ will determine the most cost-effective and feasible strategies to obtain the needed emission reductions of NO _X and/or volatile organic compounds (VOC).

Fuel Grade Expansion

GHASP commented that they welcome the expansion of low emissions diesel fuels, but believe the TCEQ could do more to reduce harmful fuel emissions. GHASP commented that they are concerned that owners and operators will switch to marine fuels not included in the proposed revised definition. GHASP recommended applying this standard to any ocean-going vessel and stated that having one fuel standard would facilitate implementation and inspection.

Most ocean-going vessels use fuels of a different grade called residual fuels that do not share many properties of distillate fuels covered under the LED regulations. Since the fuel properties are not similar, the emission reductions from applying the LED requirements to residual fuels cannot be estimated. The commission made no changes as a result of this comment.

One individual commented that with the opening of the Bayport container facility, there are more ships burning low grade diesel fuel adding pollution to our air.

The focus of this rule revision is to reduce emissions from vessels that use certain marine diesel fuels. Some of the vessels impacted by this regulation will be using the Bayport container facility and will be subject to using LED fuel. The commission made no changes as a result of this comment.

Non-LED Comments

The Coalition, EMA, Eternal Springs Wellness, Representative Farrar, Representative Hernandez, one individual, and Mothers for Clean Air in Houston commented on various air quality issues and the lack of controls in the Houston area.

The Coalition commented that they support the process that the TCEQ has used to select the control strategies associated with this SIP revision and the conclusions reached. Individual Coalition members and other industry groups provided technical comments on the specific point source measures. Subject to those technical comments, the Coalition supports the proposal and believes that these control strategies, combined with reductions from federal rules, will effectively move the HGB region towards attainment.

EMA submitted comments regarding the proposed rule changes affecting stationary internal combustion engines. EMA commented that they support the adoption of feasible and cost-effective emission standards for stationary engines when necessary to achieve ambient air quality standards.

Representative Farrar and Representative Hernandez commented that the TCEQ should take another look at the measures that have been suggested and develop a plan to obtain compliance by 2010. Representative Hernandez and Representative Farrar also commented that they are pleased with the progress that has been made in reduction emissions and the apparent trend of fewer ozone exceedances of both the one-hour and eight-hour standards.

Eternal Springs Wellness, one individual, and Mothers for Clean Air commented that they oppose delaying the plan until 2018 and would like to see cleaner air now. Eternal Springs Wellness commented that they would like to see the implementation of California standards and VOC storage tank/degassing regulations strengthened and implemented by January 1, 2009.

The commission appreciates the commenters' interest in air quality. The comments do not relate to the proposed LED marine rulemaking, and no changes to the rule have been made in response to them. The comments have been considered together with other comments on the Chapter 117 rulemaking, published in this issue of the Texas Register, or HGB SIP and a response can be found in the corresponding preamble or SIP document.

Subchapter A. DEFINITIONS

30 TAC §114.6

STATUTORY AUTHORITY

The amendment is adopted under Texas Water Code, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. The amendment is also adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which establishes the commission's purpose to safeguard the state's air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, which authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, which authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.017, concerning Rules, which authorizes the commission to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; and §382.202, concerning Vehicle Emissions Inspection and Maintenance Program, which authorizes the commission to establish vehicle fuel content standards after January 1, 2004, as long as distribution of LED as described in the SIP is not required prior to February 1, 2005. The amendment is adopted under federal mandates contained in 42 United States Code, §7410, that require states to introduce pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted amendment implements Texas Water Code, §5.103 and §5.105, and Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.017, and 382.202.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702032

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-1966

Subchapter H. LOW EMISSION FUELS

Division 2. LOW EMISSION DIESEL

30 TAC §114.319

STATUTORY AUTHORITY

The adopted amendment implements Texas Water Code, §5.103 and §5.105, and Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.017, and 382.202.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702033

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-1966

Chapter 115. CONTROL OF AIR POLLUTION FROM VOLATILE ORGANIC COMPOUNDS

The Texas Commission on Environmental Quality (TCEQ or commission) adopts new §115.110 and amendments to §§115.112 - 115.117, 115.119, 115.541 - 115.547, and 115.549. New §115.110 and amendments to §§115.112, 115.115 - 115.117, 115.119, and 115.541 - 115.547 are adopted with changes to the proposed text as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10525). Amendments to §§115.113, 115.114, and 115.549 are adopted without changes and will not be republished.

The amendments will be submitted to the United States Environmental Protection Agency (EPA) as a revision to the state implementation plan (SIP).

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

The one-hour ozone NAAQS, which preceded the eight-hour ozone standard, was revoked June 15, 2005 (69 FR 23951). However, the one-hour ozone control strategies in the HGB area will remain in place. This set of strategies will continue to reduce the amount of ozone precursors and ozone in the HGB airshed. On September 6, 2006 (71 FR 52656), EPA published approval of the HGB nonattainment area's one-hour ozone attainment demonstration and associated rules. The approval was published in six parts, covering the rules for the control of highly-reactive volatile organic compounds (HRVOC), the HRVOC emission cap and trade (HECT) program, the mass emission cap and trade (MECT) program for nitrogen oxides (NO _X ), the one-hour ozone attainment plan, the emissions credit banking and trading program, and the discrete emission credit banking and trading program. For a more complete background on the one-hour ozone SIP revisions please refer to Chapter 1 of the eight-hour SIP revision that has been submitted for adoption concurrent with this rule package (Project Number 2006-027-SIP-NR).

The rulemaking subjects owners or operators of volatile organic compound (VOC) storage tanks, transport vessels, and marine vessels located in the HGB eight-hour ozone nonattainment area to more stringent control, monitoring, testing, recordkeeping, and reporting requirements. The revised requirements have been developed to reduce VOC emissions that have previously been underreported in emissions inventories (EI).

The first Texas Air Quality Study (TexAQS 2000) measured ambient VOC concentrations in the Houston Ship Channel to be in greater proportions to NO _X emissions than what would be expected based on the reported point source emissions inventories. Therefore, when TCEQ and its research partners began TexAQS II in May 2005, one of the study's primary goals was to identify VOC emission sources that have been historically unreported or underreported in the EI and could potentially be contributing to the discrepancy between measured ambient concentrations and reported point source emissions.

TexAQS II remote sensing VOC project results indicate that certain types of storage tank emissions, including degassing, flash, and floating roof landing loss emissions, generally have been unreported in the EI. Recent data analysis, a floating roof landing loss emissions survey, and other TCEQ studies indicate that these unreported emissions could total several thousand tons per year (tpy); unreported or underreported floating roof landing loss emissions alone in the HGB area totaled approximately 7,250 tons in 2003. The rulemaking will help reduce emissions from these sources as well as other sources of potentially unreported tank emissions, such as slotted guidepoles and other tank fittings.

SECTION BY SECTION DISCUSSION

Grammatical, style, and other non-substantive corrections are made throughout the rulemaking to be consistent with Texas Register requirements, to improve readability, and to conform to the drafting standards in the Texas Legislative Drafting Manual, August 2006. Such changes include appropriate and consistent use of acronyms, section references, and certain terminology such as "that" and "which" and "shall" and "must." These changes are not discussed further.

Subchapter B, General Volatile Organic Compound Sources

Division 1, Storage of Volatile Organic Compounds

Adopted §115.110 adds ten definitions used in regulatory text. Adopted §115.110(3) defines Incompatible liquid as the term is used in §115.112(d)(2)(H)(ii). The definition is intended to allow tank landings when necessary for change of service to a material that would be contaminated by the previously stored material. For example, a change in service to gasoline with a lower Reid vapor pressure (RVP) that must be performed to comply with applicable fuel requirements is considered an incompatible liquid. The definition has been revised in response to comments to specify that different chemical mixtures and different grades of liquid material would also be considered incompatible liquids if the liquid being introduced into the tank would be made unusable for its intended purpose due to contamination from the previously stored liquid. Adopted §115.110(10) defines Tank battery as the term is used in §115.112(d)(4) and (d)(5). In response to comments, the definition has been modified to clarify that a collection of tanks at a pipeline breakout station, petroleum refinery, or petrochemical plant is not considered to be a tank battery. In response to comments, definitions have been added for the terms deck cover, pole float, pole sleeve, pole wiper, slotted guidepole, internal sleeve emission control system, and flexible enclosure system. These definitions have been added to clarify additional options for controlling emissions from slotted guidepoles that have been incorporated into §115.112(d)(2)(G). The commission has also added a definition for pipeline breakout station because the term is used in clarifying the applicability of requirements for control of flash emissions in §115.112(d)(4) and (5).

Adopted changes to §115.112 amend §115.112(a) to specify that the existing requirements apply to the HGB area until January 1, 2009. Adopted changes also add subsection (d) to specify additional requirements for storage vessels in the HGB area that will take effect on January 1, 2009. In response to comment, the phrase "beginning January 1, 2009," has been added to clarify when the new requirements take effect. Adopted §115.112(d)(1) specifies the tank size and vapor pressure criteria that determine control requirements for tanks. These are the same criteria and control requirements that are now effective in the HGB area. These requirements are being moved to subsection (d) to be at the same location as new provisions that will apply to tanks in the HGB area.

Adopted §115.112(d)(2) changes the control requirements for tank fittings. In response to comments, rule language has been changed to be more consistent with language in the EPA regulations in 40 CFR Part 63, Subpart WW, National Emission Standards for Storage Vessels (Tanks) Control Level 2.

The proposed requirement in §115.112(d)(2)(A) that all openings in an internal or external floating roof except for automatic bleeder vents, rim space vents, and roof drains must provide a projection below the liquid surface and be equipped with a cover, seal, or lid has been modified. The requirements for all openings except automatic bleeder vents (vacuum breaker vents) and rim space vents to provide a projection below the liquid surface is separate from the requirement for all openings except automatic bleeder vents (vacuum breaker vents), rim space vents, leg sleeves, and roof drains to be equipped with a cover. The proposed wording would have incorrectly required the use of covers on fixed roof support columns. The proposed wording that the cover, seal, or lid must be equipped with a working gasket and kept in a closed position (with no visible gaps) at all times except when the opening is in actual use has been revised in response to comments to specify that required deck covers must be closed (with no gap of more than 1/8 inch) at all time, except when they must be opened for access.

Adopted §115.112(d)(2)(B) specifies that automatic bleeder vents (also known as vacuum breaker vents) and rim space vents must be equipped with a gasketed lid, pallet, flapper, or other closure device and must be closed at all times except when required to be open to relieve excess pressure or vacuum, in accordance with the manufacturer's design. The current rule requires only that the automatic bleeder vents and rim space vents be closed. In response to comments, the language has been changed to allow use of a gasketed lid, pallet, flapper, or other closure device instead of a working gasket. Also in response to comments, language allowing automatic bleeder vents to open in accordance with the manufacturer's design has been added. For convenience, the requirements for automatic bleeder vents and rim space vents have been combined in §115.112(d)(2)(B).

Section 115.112(d)(2)(C) has been revised in response to comments to allow openings for fixed roof support columns to be equipped with flexible fabric sleeve seals instead of deck covers. Adopted §115.112(d)(2)(D) requires that any roof drain that empties into the stored liquid must be equipped with a slotted membrane fabric cover or equivalent control. The current rule specifies the use of the slotted membrane fabric cover; the adopted rule allows the use of other controls. EPA regulations allow controls other than slotted membrane fabric covers. Other controls can provide equivalent or superior emission reduction performance. Examples include weighted ball or ball in cage type controls. The adopted rule also specifies that the requirement does not apply to stub drains on internal floating roof tanks. Stub drains are found on internal floating roof tanks that have bolted decks. Their purpose is to allow stored liquid that collects on the roof to drain back into the tank. Covers or other controls on these stub drains would provide minimal, if any, reduction in VOC emissions. In response to comments, the phrase "no visible gap" has been changed to "no gap of more than 1/8 inch."

Adopted §115.112(d)(2)(E) states that there must be no visible holes, tears, or other openings in any seal or seal fabric. Adopted §115.112(d)(2)(F) states that secondary seals on external floating roof tanks must be rim-mounted and specifies a maximum allowable area of gaps between the secondary seal and the tank wall. In response to comments, the phrase "with the exception of gaps that do not exceed the following specification" has been added to clarify that a limited gap area is allowed.

Adopted §115.112(d)(2)(G) requires each slotted guidepole well to be controlled. The quantities of emissions reduced would depend on various factors including the tank size and material stored. As an example, a 100-foot diameter external floating roof tank with 4,000,000-gallon capacity that stores gasoline with an RVP of 9 pounds per square inch absolute (psia) and has 25 turnovers per year with an uncontrolled slotted guidepole would emit 11.85 tpy VOC from the guidepole alone and 14 tpy total VOC from the tank. The same tank with a controlled slotted guidepole would have 4.5 tpy VOC from the guidepole alone and 6.6 tons tpy total VOC emissions. For this case, controlling the slotted guidepole would result in a 62% decrease in annual VOC emissions from the guidepole and a 53% decrease in total annual tank VOC emissions. In response to comments, the wording has been changed to allow additional control options for slotted guidepoles consistent with the EPA regulations for tanks in 40 CFR Part 63, Subpart WW, and the Storage Tank Emissions Reduction Partnership Program (STERPP). These additional controls include a pole wiper and a pole float, a pole wiper and a pole sleeve, an internal sleeve emission control system, retrofit to a solid guidepole system, a flexible enclosure system, and a cover over the external floating roof. Emission calculations using the EPA TANKS program indicate that emissions from a slotted guidepole in a tank storing gasoline with an RVP of 10 psia could be reduced from 13.5 tpy down to 0.2 tpy by installing a cover over the roof. The language in §115.112(d)(2)(G) has also been revised to qualify that the controls for slotted guidepoles are only required for external floating roof tanks. Based on the emission calculations, emissions from slotted guidepoles in internal floating roof tanks or domed external floating roof tanks would be equivalent to emissions expected by installing slotted guidepole controls on external floating roof tanks.

Adopted §115.112(d)(2)(H) specifies that a floating roof must be kept floating on the liquid surface at all times except when it must be supported by leg supports during initial fill and other limited circumstances. Instances when the roof is supported by its legs are referred to as "landings." Adopted §115.112(d)(2)(H) limits the circumstances under which tank landings are allowed to times when the landing is necessary either to carry out inspections or maintenance, or to support a change in service to a liquid that is incompatible with the previously stored liquid. Change in service to gasoline with a lower RVP that must be performed to comply with applicable fuel requirements is considered a change to a liquid that is incompatible with the previously stored liquid and would be allowed. Different chemical mixtures and different grades of liquid material would also be considered incompatible liquids if the liquid being introduced into the tank would be made unusable for its intended purpose due to contamination from the previously stored liquid. Tank landings for the purposes of inventory control (also known as convenience landings) would not be allowed unless vapors are routed to a control device during the time that the roof is landed, or landing emissions are within an emissions limit or cap established under a 30 TAC Chapter 116 permit. Convenience landings would also be allowed if sitewide landing emissions are less than 25 tpy. Emissions from tank landings are higher than those that would occur while the roof is floating and have generally not been included in EI. A recent survey by the Air Quality Division's Industrial Emissions Assessment Section indicates that an additional 7,250 tons from tank landings should have been reported in 2003. The adopted rule helps to reduce these previously unreported emissions. Storage tanks with a capacity less than 25,000 gallons and those storing material with a vapor pressure less than 1.5 psia are not subject to the control requirements because such tanks are not required to be equipped with floating roofs. As an alternative to the adopted requirements of §115.112(d)(2)(H)(i) - (iv), §115.112(d)(2)(H)(v) provides a compliance option where a floating roof storage tank emissions limit or cap could be established in permits issued under 30 TAC Chapter 116 to control floating roof tank landing emissions along with standing and working loss emissions from the tank. The commission has recently established enforceable storage tank emission caps with several independent, for-hire petroleum and bulk liquid terminals in the HGB region and will allow operation under these caps to demonstrate compliance with the rules for reducing emissions from tank landings. The emission limits or caps enable these terminals to reduce landing emissions through a combination of measures, including operational roof landing restrictions where feasible, lowering of leg position to minimize vapor space, restricting landed tank refill rates, degassing with controls following landings, and new and emerging control techniques. In response to comments, the proposed restriction specifying the cap could not include any increase in emissions due to tank landings that would otherwise be prohibited under §115.112(d)(2)(H)(i) - (iv) has been deleted. Also in response to comments, §115.112(d)(2)(H)(vi) has been added to allow facilities with sitewide landing emissions less than 25 tpy to be exempt from the restrictions on tank landings. The meaning of "initial fill" in §115.112(d)(2)(H) has been clarified in response to comments to indicate that refilling a tank that has been emptied, degassed, and cleaned according to the provisions of Chapter 115, Subchapter F, Division 3, is allowed. The word "required" has been deleted from §115.112(d)(2)(H)(i) in response to comments to clarify that landings are allowed for maintenance performed according to company or site maintenance plans and not just in response to regulatory requirements. The wording in §115.112(d)(2)(H)(ii) has been revised in response to comments to use the term "incompatible liquid" in §115.110. Also in response to comments, §115.112(d)(2)(H)(iv) has been changed to require control of VOC emissions until the roof is within 10% by volume of being refloated, instead of until the roof is completely refloated. Commenters expressed concern that requiring control until the roof was completely refloated could result in liquids being drawn into the control device and causing damage.

Adopted §115.112(d)(3) specifies that vapor recovery systems used as a control device must maintain a minimum control efficiency of 90%. This is the same requirement that currently applies.

Adopted §115.112(d)(4) specifies that flash emissions from condensate storage tanks must be controlled if condensate throughput for an individual tank or the collection of tanks in a tank battery prior to custody transfer is greater than 1,500 barrels (63,000 gallons) per year, unless the owner or operator demonstrates that the emissions from the individual tank or the collection of tanks in the tank battery are less than 25 tpy. Adopted §115.112(d)(5) specifies that flash emissions from crude oil or condensate storage tanks must be controlled if uncontrolled VOC emissions from an individual tank at an upstream oil or gas production site or a midstream pipeline breakout station, or collectively from a tank battery at an upstream oil or gas production site, would be greater than 25 tpy. This limit was proposed as §115.112(d)(4). The throughput limit for condensate was added to the adopted rule as §115.112(d)(4) for ease of enforcement. Using default emission factors described later in this preamble, a throughput of 1,500 barrels per year of condensate would be expected to have 25 tpy of VOC emissions. If an owner or operator can demonstrate that a condensate tank with throughput greater than 1,500 barrels per year would have emissions less than 25 tpy, the tank would not be subject to the flash emission controls, as allowed under the new exemption in §115.117(a)(9). Crude oil and condensate typically contain dissolved gases that flash as the pressure on the liquid is reduced. For example, flashing occurs when the liquids are routed from a separator or other pressurized vessel to an atmospheric storage tank. The flashed gases may contain VOC in addition to methane and ethane, and may also entrain VOC from the stored liquid. In many cases, these gases can be economically routed to a vapor recovery device so that the energy content can be recovered for use at the production site or the gas can be compressed and routed to the sales line. If the volume of gas is sufficient, the capital cost for these vapor recovery devices can be repaid in a short time because of the high economic value of the recovered gas. The 25 tpy threshold for control was chosen because it defines the major source level for severe nonattainment areas. The HGB area was classified as severe under the one-hour ozone standard before the one-hour standard was replaced with the eight-hour standard. The adopted 25 tpy threshold also represents the maximum emission rate that a site would be authorized to operate under a permit by rule (PBR). The 25 tpy threshold applies to an individual tank or to an aggregation of tanks in a tank battery at an oil and gas exploration and production site. Because flash emissions could occur from any of the connected tanks, the adopted rule requires that the total emissions from all connected tanks be considered in determining whether the 25 tpy threshold is met. In response to comments, the commission has specified that the requirements for controlling flash emissions apply only to tanks and tank batteries storing crude oil and condensate prior to custody transfer at exploration and production sites and to individual tanks at midstream pipeline breakout stations. Crude oil and condensate stored at downstream sites such as pipeline terminals, refineries, or petrochemical plants may be a source of flash emissions, but in response to comments, the commission has decided not to subject these downstream sites to the new rule at this time because the test data and test methods in support of the rule were designed to be used at oil and gas production sites. The commission will continue to evaluate the extent of flash emissions at downstream sites and may regulate such emissions in the future. The adopted rule gives several options for estimating the uncontrolled flash emissions. The methods are based on estimating an emission factor in terms of pounds of VOC emitted per barrel (lb/bbl) of crude oil or condensate produced. Railroad Commission regulations in 16 TAC §3.58(b) require producers to file a monthly report of the amount of oil, casing head gas, natural gas, and condensate produced during the month. Owners or operators can use these production records for the previous 12 months (rolling) along with the emission factor to estimate the total VOC emissions. The emission factor can be determined by direct measurement of the gas over a 24-hour period. Gas volume can be measured by manifolding all of the tanks together and using a device such as a mass flow meter or positive displacement meter. A sample of the gas can be analyzed using Gas Processors Association Method 2286, Tentative Method of Extended Analysis for Natural Gas and Similar Mixtures by Temperature Programmed Gas Chromatography, or accepted EPA methods to measure the composition of the flashed vapors. These measurements can be used to calculate the pounds of VOC emitted over the 24-hour measurement period. The pounds of VOC can then be divided by the oil or condensate production rate in barrels to determine the emission rate in pounds of VOC per barrel. Instead of making direct measurements, the owner or operator can use default emission factors of 33.3 lb/bbl of condensate or 1.6 lb/bbl of crude. These factors were determined in a study titled VOC Emissions from Oil and Condensate Storage Tanks. This study, conducted in 2006, was sponsored by the TCEQ and the Houston Advanced Research Center (HARC) and is identified as project H51C. For crude oil, owners or operators can use a chart found as Exhibit 2 of the EPA publication Lessons Learned from Natural Gas STAR Partners: Installing Vapor Recovery Units on Crude Oil Storage Tanks, October 2003, to estimate the volume of flash gas per barrel of oil. The VOC mass emission rate can then be determined by assuming that the hydrocarbon vapors have a molecular weight of 34 pounds per pound mole and are 48% by weight VOC. These values came from the HARC H51C study. Finally, the owner or operator can use a computer simulation or other method approved by the executive director to estimate flash emissions. These options are specified to minimize the burden on owners and operators to make direct measurements or complex calculations. If the regulated entity chooses to make direct measurements and they yield emission rates that are higher than those determined by the default emission factors, EPA chart, or simulation, or if computer simulation yields results higher than the default emission factors or chart, the higher rates must be used. In response to comments, rule language has been added to §115.112(d)(5) to specify that the higher rates must be used. The proposed rule only noted this restriction in the preamble. The commission has deleted the proposed §115.112(d)(4)(E) and combined the option to use a computer simulation with the option to use another method approved by the executive director. This language was previously in §115.112(d)(4)(F). The accuracy of computer simulations is entirely dependent on the accuracy of the inputs and the use of appropriate model parameters. Regulated entities will still have the option to use a computer simulation to estimate flash emissions, but the use must be pre-approved by the executive director to ensure that the results are accurate. Staff of the Industrial Emissions Assessment Section who review such calculations for EI reporting will review the simulation use.

Nothing in the adopted rule implies authorization of flash emissions. All emissions must be authorized according to a permit or other authorization under 30 TAC Chapters 106 or 116. The adopted rule regulates flash emissions from crude oil and condensate storage at oil or gas production sites and pipeline terminals. Flash emissions may also occur at storage terminals, refineries, and petrochemical plants, and crude oil and condensate are not the only sources of flash emissions. Processes in petroleum refineries and chemical plants can generate liquids containing dissolved gases that will flash when the liquid is routed from higher pressure equipment to an atmospheric storage tank. Although flash emissions from these other liquids are not regulated under the adopted rule, the commission is not implying that these emissions are authorized. Methods specified in the EPA Compilation of Air Pollutant Emission Factors (AP-42) to calculate emissions from storage tanks do not include emissions from flash. Unless these flash emissions have been separately estimated and included in best available control technology (BACT) and health effects reviews during permitting, the emissions are not authorized even if they are not expressly prohibited by regulation in Chapter 115.

Adopted §115.115(c) specifies appropriate measuring instruments and test methods for determining flash emissions if the owner or operator chooses to demonstrate compliance with the 25 tpy limit by direct measurement. The use of a mass flow meter, positive displacement meter, or similar device must be used for determining flash gas flow rate. Conventional pitot tube or orifice plate techniques may not be appropriate for the relatively low flow rates from oil and condensate storage tanks. Flow measurements must be made over a 24-hour period representative of normal operation to make sure that the measurements capture emissions during a typical working cycle including pumping into and out of the tanks. The language in §115.115(c) has been changed to specify that at oil and gas production sites, flow measurements must be made while the producing wells are operational. The proposed rule listed this requirement, but the adopted language has been changed to clarify that it applies to measurements made at oil and gas production sites and not to measurements made at pipeline breakout stations that could be at some distance from the producing wells. Gas composition must be determined using Gas Processors Association Method 2286, Tentative Method of Extended Analysis for Natural Gas and Similar Mixtures by Temperature Programmed Gas Chromatography, or approved EPA test methods. The listed test methods have been changed since proposal to include standard EPA test methods for the determination of VOC composition in addition to the Gas Processors Association Method 2286.

In response to comments, the term "reportable emissions" in §115.116(a) has been replaced with the term "emissions inventory reportable emissions" to avoid confusion with the use of the term "reportable emissions" as used in the general air quality rules in 30 TAC Chapter 101.

Adopted §115.116(c)(1) specifies that owners or operators of storage tanks that are not required to be equipped with a floating roof or vapor recovery system because the vapor pressure of the stored material is less than 1.5 psia shall keep records of the material stored and the vapor pressure. These records are necessary to document that material stored in fixed roof tanks meets the criteria for exemption from control requirements. In response to comments, the wording "length of time material is stored" has been replaced with the more precise wording "starting and ending dates when the material is stored." Commenters had expressed confusion over the meaning of the phrase.

Adopted §115.116(c)(2) specifies that owners or operators of crude oil or condensate storage tanks with flash emissions shall keep records to verify that emissions from these tanks are below the 25 tpy criteria for exemption from control requirements. Records must be sufficient to allow investigators to determine whether flash emissions have been calculated by an appropriate method. If a computer simulation is used, records of the input and output must be retained. In response to comments, the wording has been changed to clarify that the requirements apply only to tanks or tank batteries at exploration and production sites or to tanks at pipeline breakout stations. Also in response to comments, the requirement to project emissions for the next year upon request has been deleted.

The adopted amendment to §115.117(a)(2) specifies that in the HGB area, the storage of crude oil and condensate prior to custody transfer in tanks with capacity less than 210,000 gallons will no longer be exempt from the control requirements of Subchapter B, Division 1 after January 1, 2009. The VOC emissions from such tanks at oil and gas production sites (especially emissions arising from flashed gases) have been found to be a significant source of VOC emissions and have previously not been reported.

A new exemption §115.117(a)(9) has been added to specify that if an owner or operator can demonstrate that a condensate tank with throughput greater than 1,500 barrels per year would have emissions less than 25 tpy, then the tank would not be subject to the flash emission controls in §115.112(d)(4).

Adopted §115.119(c) specifies that compliance with the requirements of §§115.112(d), 115.115(c), and 115.116(c) must occur by January 1, 2009, as part of the effort to address the eight-hour ozone standard for the HGB area. However, if compliance with the new requirements would necessitate emptying and degassing the tank, compliance would not be required until the next time the tank is emptied or degassed but not later than January 1, 2017. Additional emissions that would arise from emptying and degassing a tank could negate the benefit of the emission controls and so would not be required solely for the purpose of installing controls. Because tanks are generally taken out of service at least once every ten years, the controls must be installed no later than ten years from the date these rules are adopted. The delay in compliance would apply only to the installation of equipment; monitoring and recordkeeping requirements must be observed beginning January 1, 2009. Regulated entities that use the delay of compliance provision should be prepared to justify why tank emptying and degassing was necessary to comply with the rules. Tanks with a nominal capacity less than 210,000 gallons (794,850 liters) storing crude oil and condensate prior to custody transfer that were previously exempt must comply by January 1, 2009. Since proposal, wording has been added to clarify that these tanks must comply by January 1, 2009, regardless if compliance would require emptying and degassing the tank.

Subchapter F, Miscellaneous Industrial Sources

Division 3, Degassing or Cleaning of Stationary, Marine, and Transport Vessels

The adopted change to §115.541(a)(1) specifies that after January 1, 2009, the degassing control requirements will apply to storage tanks in the HGB area with a nominal capacity of 75,000 gallons or greater storing materials with a true vapor pressure greater than 2.6 psia or to storage tanks with a nominal capacity of 250,000 gallons or more storing material with a true vapor pressure of 0.5 psia or greater. The current rule mandates degassing controls only to storage tanks with a nominal capacity of one million gallons or more. The EI database has records of more than 950 floating roof storage tanks with capacity between 75,000 and one million gallon capacity that could be required to employ vapor recovery during tank degassing under the adopted rule. There are also more than 3,000 fixed roof storage tanks in this size range, but an unknown number of these storage tanks store materials with a vapor pressure less than 2.6 or 0.5 psia and will not be subject to the adopted degassing requirement. Degassing emissions from these smaller storage tanks can be abated with technology similar to that used for larger tanks. The size and vapor pressure criteria for determining which storage tanks are subject to the degassing control requirements were changed since proposal in response to comments and subsequent cost effectiveness calculations by staff.

The adopted change to §115.542(a)(5) specifies that the current control requirements apply in the HGB area only until January 1, 2009. Adopted §115.542(a)(6) specifies new criteria for control of degassing vapors from storage tanks and transport vessels in the HGB area. The change requires that vapors be vented to a control device until the VOC concentration of the vapors is reduced to less than 34,000 ppm by volume (ppmv) as methane or to less than 50% of the lower explosive limit (LEL). The current rules specify the 34,000 ppmv concentration as one criterion for determining when vapors can be vented to the atmosphere but also allow venting after a turnover of four vapor space volumes has occurred. If the storage tanks are drained dry and if the flow of displacement gases is measured properly, four turnovers would generally be sufficient to reduce VOC concentrations to less than 34,000 ppmv. If liquid remains in the bottom of the storage tank or transport vessel, as commonly occurs due to irregularities in the vessel surface, the remaining liquid would continue to be a source of VOC emissions after the four turnover criterion has been satisfied. The adopted rules remove the option to vent to atmosphere after a turnover of four vapor space volumes has occurred. Dilution from ventilation gas used to sweep the vapor space within the vessel could also cause a reading of 34,000 ppmv VOC to be reached temporarily, but if liquid remains in the storage tank the concentration could again rise when the flow of ventilation gas ceases. The adopted revision requires continued control of the vapors until the VOC concentration decreases to below 34,000 ppmv or a reading of less than 50% is obtained on an LEL meter. The concentration must be rechecked periodically while the tank is vented to the atmosphere to ensure that it remains below 34,000 ppmv or 50% LEL. If ventilation is continuous, the concentration must be measured at least once every 12 hours. If ventilation ceases for more than four hours, the concentration must be rechecked before the tank is reopened. The 50% LEL criterion was added in response to comments. The VOC concentration equivalent to 50% LEL is less than 34,000 ppmv and therefore is an acceptable criterion to determine when degassing vapors can be emitted to atmosphere. Also in response to comments, language has been added to specify that the concentration measurements are no longer required after five consecutive readings less than 34,000 ppmv or less than 50% LEL have been obtained.

The adopted change to §115.542(b)(4) specifies that the stated control requirements apply in the HGB area only until January 1, 2009. Adopted §115.542(b)(5) specifies new criteria for control of degassing vapors from marine vessels in the HGB area. The change requires vapors to be vented to a control device until the VOC concentration of the vapors is reduced to less than 34,000 ppmv as methane or 50% LEL. The current rules specify this concentration as one criterion for determining when vapors may be vented to the atmosphere but also allow venting after a turnover of four vapor space volumes has occurred. The adopted rules remove the option to vent to atmosphere after a turnover of four vapor space volumes has occurred. This change is being adopted for degassing vapors from marine vessels for the same reasons discussed for the adopted §115.542(a)(6) for storage tanks and transport vessels. The 50% LEL criterion has been added to the rule because the commission has specified that an equivalent LEL percentage can be used to determine when degassing need no longer be controlled for storage tanks. The current rule in §115.542(b)(4) uses 20% of the LEL as one of the criteria for when marine vessels may be vented to the atmosphere. This requirement was not changed because it applies to sources in the Beaumont-Port Arthur area as well as (until January 1, 2009) sources in the HGB area. The revised §115.542(b)(5) specifies 50% of the LEL to be consistent with the value used in §115.542(a)(6) for storage tanks and transport vessels. Because the LEL criterion is an option to allow flexibility in measurement methods, using 50% instead of 20% in §115.142(b)(5) will not allow an increase in VOC emissions over those allowed under §115.542(b)(4).

Adopted §115.545(11) specifies the methods that must be used to measure the VOC concentration of the storage vessels, transport vessels, or marine vessels to determine when the vapors can be vented to the atmosphere instead of to a control device. In response to comments, several additional analytical methods have been specified to allow flexibility for the concentration measurements. However, the large potential variability in chemical composition of stored liquids necessitates carefully selecting and implementing the analytical method according to the precise chemical and physical circumstances occurring at the time of the measurement. Thus, the commission requires that sufficient records and other information be maintained to show that the alternative method used completely meet the needs of the specific instance. Examples of such records are maintenance and calibration records of all equipment, training records of equipment operators, and a written sampling plan for each instance complete with data quality objectives and QA/QC measurement parameters. The measurement should be made at the head space of the vessel, as close as possible to the tank bottom to ensure that the concentration measurement is representative of actual conditions, but the measurements should be made at a safe location.

Adopted §115.546(1)(D) specifies that records of the VOC concentration measurements required by §115.542(a)(6) and (b)(5) must be maintained. The records are necessary to document that degassing vapors are routed to a control device until they reach the criteria to be released to the atmosphere.

A change to §115.547(2) is adopted to state that after January 1, 2009, storage tanks in the HGB area with a nominal capacity of less than one million gallons but greater than or equal to 250,000 gallons or with a nominal capacity of greater than or equal to 75,000 gallons storing material with vapor pressure greater than 2.6 psia will no longer be exempt from the requirements to control degassing emissions. As discussed earlier in this preamble, degassing emissions from these smaller tanks can be controlled with technology similar to that used to control degassing emissions from the larger tanks. The commission revised the exemption level in response to public comments.

The words "causes" and "prevents" are added to §115.547(4) so that the text more clearly expresses the intended meaning of the exemption.

Adopted §115.549(d) specifies that compliance with the new and revised requirements must occur by January 1, 2009, as part of the effort to address the eight-hour ozone standard for the HGB area.

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the adopted rulemaking action in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking action does not meet the definition of a "major environmental rule" as defined in that statute. A "major environmental rule" is a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state. The primary purpose of this adopted rulemaking action is to require owners or operators of VOC storage tanks, transport vessels, and marine vessels located in the HGB eight-hour ozone nonattainment area to better control their storage and degassing operations, thereby reducing VOC emissions. The adopted rules assist in identifying previously unreported emissions, and reducing them appropriately. It is anticipated that this adopted rulemaking will positively affect human health and the environment, and not adversely affect the economy or productivity in any material manner. Moreover, the adopted rules will improve air quality and make positive progress towards attainment of the HGB eight-hour ozone standard. Therefore, the adopted rulemaking does not constitute a major environmental rule, and thus is not subject to a formal regulatory analysis.

In addition, this adopted rulemaking does not meet any of the four applicability criteria of a "major environmental rule" as defined in the Texas Government Code. Texas Government Code, §2001.0225 applies only to a major environmental rule the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

The rulemaking action, which is designed to reduce VOC emissions that have previously been underreported in EI, does not exceed an express requirement under federal or state law. Furthermore, there is no contract or delegation agreement that covers the topic that is the subject of this action. Finally, this rulemaking action was not developed solely under the general powers of the agency, but is authorized by specific sections of Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act), and the Texas Water Code, which are cited in the STATUTORY AUTHORITY section of this preamble, including Texas Health and Safety Code, §§382.011, 382.012, and 382.017. Therefore, the adopted rulemaking does not exceed a standard set by federal law, exceed an express requirement of state law, exceed a requirement of a delegation agreement, nor is adopted solely under the general powers of the agency.

Based upon the foregoing, this rulemaking action is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225.

TAKINGS IMPACT ASSESSMENT

Under Texas Government Code, §2007.002(5), "taking" means 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 §17 or §19, Article I, Texas Constitution; or a governmental action that affects an 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% in the market value of the affected private real property, determined by comparing the market value of the property as if the governmental action is not in effect and the market value of the property determined as if the governmental action is in effect.

The commission completed a takings impact assessment for the adopted rules. The adopted rules will not affect private real property in a manner that would require compensation to private real property owners under the United States Constitution or the Texas Constitution. The adoption also will not affect private real 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. Therefore, the adopted rules will not cause a taking under Texas Government Code, Chapter 2007.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined that this rulemaking action relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq.), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by §281.45(a)(3) and 31 TAC §505.11(b)(2), relating to Actions and Rules Subject to the Coastal Management Program, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the rules of the Coastal Coordination Council, and determined the action is consistent with the applicable CMP goals and policies. The CMP goal applicable to this rulemaking action is the goal to protect, preserve, and enhance the diversity, quality, quantity, functions, and values of coastal natural resource areas (31 TAC §501.12(l)). No new sources of air contaminants will be authorized and the adopted rules will maintain at least the same level of or increase the level of emissions control as the existing rules. The CMP policy applicable to this rulemaking action is the policy that commission rules comply with federal regulations in 40 CFR, to protect and enhance air quality in the coastal areas (31 TAC §501.32). This rulemaking action complies with 40 CFR Part 51, Requirements for Preparation, Adoption, and Submittal of Implementation Plans. Therefore, in accordance with 31 TAC §505.22(e), the commission affirms this rulemaking action is consistent with CMP goals and policies.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

The requirements of Chapter 115 are applicable requirements of 30 TAC Chapter 122. Owners or operators of sites subject to the Federal Operating Permit Program will be required to obtain, revise, reopen, and renew their Federal Operating Permits, as appropriate, in order to include the requirements of this adopted rulemaking.

PUBLIC COMMENT

The commission held public hearings on this proposal at the following times and locations: January 29, 2007, 2:00 p.m. and 6:00 p.m., Houston-Galveston Area Council, 3555 Timmons Lane, Houston; January 31, 2007, 7:00 p.m., J. Erik Jonsson Central Library Auditorium, 1515 Young Street, Dallas; February 1, 2007, 2:00 p.m., Arlington City Hall Council Chambers, 101 W. Abrams Street, Arlington; February 1, 2007, 6:00 p.m., Midlothian Conference Center, 1 Community Circle, Midlothian; February 6, 2007, 2:00 p.m., Longview Public Library, 222 W. Cotton Street, Longview; and February 8, 2007, 2:00 p.m., Texas Commission on Environmental Quality, Building E, Room 201S, 12100 Park 35 Circle, Austin.

The commission received comments from Baker Botts L.L.P. on behalf of the 8-Hour Ozone SIP Coalition (EOSIPC), Association of Electric Companies of Texas, Inc. (AECT), Celanese, Ltd., CEMA Solutions, Inc. (CEMA), Coalition of Manufacturers for Air Quality (COMAQ), Dow Chemical Company (Dow), Energy Business, Inc. (EBI), GEM Mobile Treatment Services, Inc. (GEM), Galveston-Houston Association for Smog Prevention (GHASP), Harris County Public Health & Environmental Services (HCPHES), Houston-Sierra Club (HSC), Marathon Pipe Line (MPL), Mothers for Clean Air (MFCA), Remediation Service, Int'l (RSI), Texas Chemical Council (TCC), Texas Oil & Gas Association (TxOGA), Baker Botts L.L.P. on behalf of Texas Terminal Operators Group (TTO), United States Environmental Protection Agency Region 6 (EPA), and one individual. State Representative Ana E. Hernandez of District 143, State Representative Jessica Farrar of District 148, and Mayor Bill White of Houston jointly with County Judge Robert Eckels of Harris County submitted comments on the SIP that did not have specific comments on the proposed rules.

The commenters suggested modifications to the proposed rules as stated in the RESPONSE TO COMMENTS section of this preamble.

RESPONSE TO COMMENTS

The EPA requested that the commission provide a legend or explanation that clarifies the symbols used to identify changes that will be made to the rule.

The commission used Texas Register format to indicate changes to the rule. In the proposal, new rule language was shown in underline, and rule language to be deleted was in brackets.

Celanese endorsed the comments provided by the TCC.

The commission acknowledges Celanese's endorsement of the comments provided by the TCC.

The AECT and EOSIPC expressed support for the process the agency has used to select the proposed control strategies and the conclusions reached. The EOSIPC and TxOGA also expressed support for the proposal with the technical corrections submitted by its members comments, and AECT, Dow, EOSIPC, and TCC stated that these control strategies will result in additional progress towards attainment of the eight-hour ozone standard in the HGB area.

The commission appreciates the support.

The EPA and RSI expressed support for the agency's efforts to expand controls and reduce VOC emissions within the HGB area. EBI stated that accounting for storage and transport emissions sources is "very good stewardship."

The commission appreciates the support.

The EOSIPC expressed support for the commission's ongoing work to incorporate the findings of the TexAQS II field study into the development of new modeling episodes that occurred in 2005 and 2006.

Both the TCC and Dow support the development of a new modeling episode that incorporates the TexAQS II field study results. Dow additionally suggested that the TCEQ should consider information resulting from industry-sponsored research projects that show point source emissions from the HGB perimeter counties have little effect on key air quality monitors in Harris County.

The commission appreciates the support for the technical work completed to date. The TCEQ has, and will continue, to review and analyze other technical studies as it moves forward with development of a new modeling episode and development of appropriate control strategies for the HGB area.

Both the AECT and COMAQ encouraged the agency to consider the primary reason the HGB area cannot attain the eight-hour ozone standard by the deadline is due to NO _X and VOC emissions from on-road and off-road mobile sources, marine vessels, and other federally regulated sources. The COMAQ stated that NO _X emissions from such sources are estimated to comprise about 54% of the 2009 NO _X emissions inventory for the HGB area. The EOSIPC asserted that agency photochemical modeling demonstrates that on-road and non-road mobile source emissions reductions constitute the most effective path toward the HGB area achieving attainment. The COMAQ and EOSIPC stated that significant progress towards attainment in the HGB area cannot be realized before substantial reductions are made in mobile source emissions. COMAQ further noted the TCEQ does not have the authority to regulate emissions from federally regulated sources. The TCC and Dow encouraged the commission to continue promoting voluntary programs like TERP to accelerate mobile source emission reductions. AECT and COMAQ expressed support for additional legislative funding for the TERP program. COMAQ additionally commented that the agency should "emphasize that TERP has resulted in about 22 tpd of NO _X and VOC emission reductions from on-road and non-road sources in the HGB area. The AECT suggested the commission continue to encourage the EPA to take all appropriate measures to accelerate reductions of NO _X and VOC emissions from on-road and non-road mobile sources, marine vessels, and other federally regulated emission sources in the HGB area. The AECT suggested the commission encourage and support programs and initiatives that will reduce NO _X and VOC emissions from on-road and non-road mobile sources in the HGB area even if the measures cannot be used for emission reduction credits in the SIP.

The issues brought up in these comments are beyond the scope of this rulemaking. The purpose of this rule project is to decrease VOC emissions from industrial point sources that have been previously unreported or underreported to the TCEQ and to provide better recordkeeping and reporting to formulate a more accurate inventory and enable more accurate modeling for future SIP development.

The COMAQ encouraged the TCEQ to continue to emphasize the following facts and to use these facts in the development of the HGB eight-hour ozone SIP rules: (1) emissions of NO _X and VOC (including HRVOC) from industrial point sources have been significantly reduced since 2001; and (2) TCEQ photochemical modeling indicates additional NO _X and VOC (including HRVOC) emissions reductions from point and area sources in the HGB area will not bring the area into attainment with the eight-hour ozone standard. The EOSIPC stated that since 2001, its member companies have invested over two billion dollars in state-of-the-art emissions controls that have reduced ozone precursor emissions; the results of these investments are evident in the ambient air. Additionally, the EOSIPC asserts that independent scientific studies show that the current control strategies are reducing ozone. These decreases have occurred before the full implementation of the current point source NO _X and HRVOC emissions control strategy that was adopted in 2004 and will be fully implemented in 2007.

The commission acknowledges the efforts that have been made by industrial point sources in the HGB area to reduce emissions. The purpose of this rule package is to reduce emissions of VOC that have been previously unreported or underreported in the EI and therefore not considered in modeling exercises to determine the most effective control measures to reduce ozone. Additional emission reductions from across the broad spectrum of sources may be needed to reduce ozone levels enough to meet the eight-hour standard.

The TTO requested that the commission make changes to the proposed rule to address market realities that for-hire terminals face. HSC noted that under "Potentially Controversial Matters" in the Executive Summary for the HGB VOC rules TCEQ stated, "Representatives of terminal operators oppose the prohibition of convenience tank landings." HSC expressed objection that TCEQ was allowing the regulated community to "call the shots" about rule development.

The commission has made some changes to the proposed rule as a result of the TTO comments, as discussed in the Response to Comments section of this rulemaking. The reference to the opposition of terminal owners and operators to the prohibition of convenience landings was intended only to alert the commissioners to communications that had been received before the formal rule proposal. The prohibition was included in the proposed rule, but after further discussion and research, §115.112(d)(2)(H)(v) and (vi) allow for convenience landings if emissions are authorized under a permit limit or emission cap in a permit issued under 30 TAC Chapter 116 or if site-wide emissions from tank roof landings are less than 25 tpy.

Both GHASP and HSC requested that the VOC rules be made more stringent because TCEQ has not been able to document sufficient VOC emission reductions to show attainment of the ozone standard by 2010. Similarly, an individual commenter encouraged the commission to place more stringent controls on storage tank emissions.

Photochemical modeling has shown that VOC reductions alone would not be sufficient to allow the HGB area to attain the eight-hour ozone standard by 2010. The commission's responses to the commenters' specific suggestions for making the VOC rules more stringent are detailed elsewhere in this document.

GHASP asserted that the only new control measures in the 8-hour ozone SIP are enhancements to on-road and non-road NO _X emissions controls and encouraged the agency to adopt additional control measures. GHASP specifically encouraged the agency to consider measures that would expand the monitoring network, track emissions events and predict future emissions event impacts, incorporate reactivity based strategies such as trading of HRVOC and/or other VOC emissions, and control wastewater and other industrial VOC sources. GHASP stated that the HGB area needs every possible emissions reduction to achieve attainment and generally favors industrial controls first, followed by diesel source controls.

The commission appreciates the comment but the suggestions are outside the scope of this rulemaking and therefore no changes were made to the Chapter 115 rules as a result of this comment. The commission considered developing rules to require more stringent controls for wastewater facilities, but concluded that more information is needed to quantify potentially underreported emissions before effective rules can be developed.

MFCA specifically suggested increasing VOC reductions from large industrial sources in the HGB area by 95% or more, and both MFCA and GHASP suggested establishing controls on other VOC in addition to HRVOC in the HGB area. Additionally, GHASP encouraged the agency to consider measures that concomitantly reduce pollutants that pose additional risks, such as air toxics and particulates.

The commission appreciates the comments but the suggestions are outside the scope of this rulemaking and therefore no changes were made to the Chapter 115 rules as a result of these comments.

HCPHES expressed support for the amendments to Chapter 115 to reduce VOC emissions from storage and degassing operations in the HGB area. The HCPHES suggested adopting and/or implementing various rules adopted by other states to reduce VOC content in solvents, paints, and various household and cosmetic products. The HCPHES also suggested expanding the HRVOC regulations beyond Harris County and adding to the list of chemicals subject to the HRVOC rules.

The commission appreciates the comment in support of the Chapter 115 rules and the suggestions for additional control measures to reduce VOC emissions. The rule sections associated with the HCPHES suggestions are beyond the scope of this rulemaking and therefore no changes have been made to the rule based on the comments. Furthermore, the EPA is scheduled to adopt more stringent VOC content limits in paints and various household and cosmetic products in November 2007.

HSC commented that the rule changes for storage tanks, degassing, and flash emissions should be applied statewide.

Extending coverage of these rules to the entire state is beyond the scope of this rulemaking. Because the proposal only applied the rule changes to the HGB area, affected parties in other areas of the state have not received proper notice of the changes and would not have an opportunity to comment. The commission may consider extending coverage of the rule amendments in a future rulemaking.

EBI objected to the adoption of the rule language prior to determining the resolution of the Texas Petrochemical situation with the city of Houston. EBI recommended the commission expressly notify the city of Houston of the intended purpose of the regulations and suggested adding a qualifier to the rule language specifying the rule does not apply to the foregoing situation.

The city of Houston is aware of the proposed rule language, as evidenced by comments made by the mayor of Houston on the SIP proposal. The commission has made no changes to the rule as a result of this comment.

HSC expressed disagreement with the statements in the Executive Summary for the HGB VOC rules concerning enforcement responsibilities. HSC further expressed concern that new TCEQ regulations in the past have created greatly increased workloads for investigators and requested that the commission document how many more investigations and investigator hours will be required to implement these rules. EBI expressed concerns about the commission's lack of enforcement of the regulations the commission promulgates.

The proposed increased stringency of rules for tanks does not require additional inspections, just changes in compliance criteria. The changes to the degassing rules would affect additional sources, but degassing is done infrequently. The requirements for control of flash emissions would impose new requirements at sites that are already subject to other commission rules for permitting and emissions inventory reporting but may not be complying with these requirements due to underestimation of flash emissions. The recordkeeping requirements of the new rules could aid investigators in determining whether facilities are in compliance with existing rules.

GEM suggested clarifying whether the term "storage vessel" used in the proposed rule text refers to "storage tanks."

The term "storage vessel" as used in the rule includes "storage tanks." Most instances of the term "storage vessel" in the adopted rule have been changed to "storage tank."

EBI suggested the Chapter 115 rule language be revised to distinguish between VOC and NMVOC. EBI recommended clarifying that the rule applies to storage for VOC and NMVOC or limit the rule solely to crude and natural gas tanks and then propose a separate rule for NMVOC.

The definition of VOC in 30 TAC §101.1 (relating to Definitions) excludes methane and other compounds determined by the EPA to have a negligible contribution to tropospheric ozone formation. Therefore, the suggested change is not necessary.

COMAQ, TCC, TTO, and Dow suggested including in §115.110 definitions of the following terms as they are defined by the EPA in 40 CFR §63.1061: pole float, pole sleeve, pole wiper, and slotted guidepole. The TTO suggested also adding the following definitions: deck cover, external floating roof tank cover, flexible enclosure system, internal sleeve emission control system.

The commission has added definitions for the terms deck cover, pole float, pole sleeve, pole wiper, slotted guidepole, flexible enclosure system, and internal sleeve emission control system as requested. A definition for external floating roof tank cover was not added because it was not necessary.

Dow suggested the TCEQ expand the definition of "incompatible liquid" in §115.110 to include (1) liquids that have different chemical mixtures and cannot be mixed due to product quality specifications and (2) different grades of liquid materials that cannot be mixed due to product quality specifications. In addition, Dow suggested that theses definition changes should be considered acceptable in §115.112(d)(2)(H)(ii). Dow also suggested that any liquid or fuel with a different specification should be considered as an incompatible liquid for the purposes of the rule. The TTO suggested the rule language in §115.110(1) be revised to read "incompatible liquid--a liquid that is a different chemical compound, a fuel with different regulatory specifications, or any liquid that is otherwise compatible but for commercial contractual reasons." The TCC suggested the term "incompatible" should recognize the following additional scenarios: a liquid material that would contaminate or significantly change the quality of a future stored material, any liquid or fuel with different product specifications.

The commission has revised the definition to include different chemical mixtures or different grades of liquid material that would be unusable for its intended purpose due to contamination from the previously stored liquid. Minor differences in product quality specifications or materials owned by different customers are not intended to be covered under the definition, or the definition of incompatible liquid would be so broad as to be practically unenforceable. The commission notes that facilities have the option to authorize landing emissions under a cap or emissions limit under a Chapter 116 permit or a 25 tpy exemption as allowed in §115.112(d)(2)(H)(v) and (vi).

The TxOGA expressed support for the definition of "incompatible liquid" in §115.110(1). The TCC agreed with the concept of allowing floating roof landings to support a change in service to a liquid that is incompatible with the previously stored liquid.

The commission appreciates the support.

The TxOGA and TCC suggested the definition of "tank battery" in §115.110(2) be changed to read "Exploration and Production Tank Battery--A collection of equipment at an exploration and production site used to separate, treat, store, and transfer crude oil, condensate, natural gas, and produced water."

Instead of making the change as suggested, the commission is changing the definition to specify that a collection of tanks at a pipeline breakout station, petroleum refinery, or petrochemical plant is not considered to be a tank battery. The commission has also changed §115.112(d)(4) and (5) to specify that control of flash emissions is required only for crude oil or condensate storage prior to custody transfer or at a pipeline breakout station. With these changes, the flash emission control requirements would apply to individual tanks or the collection of tanks at an oil and gas exploration and production site and to individual tanks at a pipeline breakout station. The requirements would apply to upstream and midstream operations but not to downstream operations such as crude oil and condensate storage at pipeline terminals, petroleum refineries, or petrochemical plants. The commission will continue to evaluate the extent of flash emissions at the downstream operations and may take action to regulate these sources at a later time.

HSC requested that the minimum control efficiency in §115.112(a)(3) and (d)(3) be increased from 90% to 95%.

The commission made no changes to the rule as a result of this comment. The focus of the rulemaking project was to effect real reductions in VOC emissions. Although the rule only requires a control efficiency of 90%, many of the control devices in use in fact reduce emissions by 95% or more.

HSC requested that the rules in §115.112(b) and (c) for Gregg, Nueces, Victoria, Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties be changed to be as stringent as those for the HGB area. HSC also requested that all references in §115.112(c)(1), Table I(b), to 1.5 psia be changed to 0.5 psia and that all references to 25,000 gallons be changed to 10,000 gallons.

Revising the rules for the listed counties is beyond the scope of this rulemaking. Because no changes were proposed to the referenced subsections, affected parties in these counties have not received proper notice of the changes and would not have an opportunity to comment. The commission may consider extending coverage of the rule amendments in a future rulemaking.

HSC commented that rules in §115.112(d) should apply statewide.

Extending coverage to the entire state is beyond the scope of this rulemaking. Because the proposed rule only applied the rule changes to the HGB area, affected parties in other areas of the state have not received proper notice of the changes and would not have an opportunity to comment. The commission may consider extending coverage of the rule amendments in a future rulemaking.

MFCA suggested requiring the installation of control measures for storage tanks with VOC vapor pressure equal to or greater than 0.5 pounds per square inch absolute. GHASP commented that the Chapter 115 rules should be changed to reflect the best available control technology requirements that dictate storage tanks operating with a vapor pressure greater than 0.5 psia and a capacity of more than 25,000 gallons have a floating roof or vent to control device. HSC commented that all references to 1.5 psia in Tables I(a) and II(a) should be changed to 0.5 psia and that all references to 25,000 gallons and 40,000 gallons in Tables I(a) and II(a) should be changed to 10,000 gallons.

The commission considered lowering the vapor pressure that would trigger control requirements during the development of the rule proposal. After reviewing data available in the EI, the commission concluded that emissions from fixed-roof tanks storing materials with vapor pressures between 0.5 and 1.5 psia represented a small portion of the total VOC emissions from fixed roof tanks and that requiring additional controls for these tanks would not provide a meaningful reduction in VOC emissions.

Controls for smaller tanks are less cost effective than controls for larger tanks. According to data in the EI, there are a total of 3,451 fixed roof tanks with a total capacity of 52.8 million gallons that have capacities greater than or equal to 10,000 gallons but less than 25,000 gallons in the HGB area. There are 1,073 tanks with total capacity of 32.6 million gallons that have capacities between 25,000 and 40,000 gallons. For comparison, there are 5,498 fixed roof tanks with a total capacity of over 14 billion gallons that have capacities of 40,000 gallons or more. There are an additional 2,259 floating roof tanks with combined capacity over 24 billion gallons. The relative capacity of tanks that would be affected by the requested change represent less than 1% of the total fixed roof tank capacity in the HGB and less than 0.3% of the total fixed and floating roof capacity. The commission decided not to pursue additional controls for tanks that represent such a small percentage of the total tank capacity. Controls for these small tanks would not result in meaningful emission reductions.

The EPA requested confirmation that §115.112(d) specifying additional requirements for storage vessels in the HGB area will begin January 1, 2009. The EPA also noted that although the preamble makes this clear, a start date of January 1, 2009, may need to be added to the rule.

The commission has added the start date of January 1, 2009, to §115.112(d) as suggested.

The TCC suggested incorporating the language in 40 CFR §63.1063(b)(1), (2), (3), and (5) into §115.112(d)(2) to address the operational requirements of floating roof tanks.

The commission has revised §115.112(d)(2)(H) to include the language in 40 CFR §63.1063(b)(1) regarding support of a floating roof by other devices (e.g., hangers from the fixed roof). Language in 40 CFR §63.1063(b)(3) requiring that covers be closed at all times except when they must be opened for access has been incorporated into §115.112(d)(2)(A). The commission declines to add the language in 40 CFR §63.1063(b)(2) and (5). The language in 40 CFR §63.1063(b)(2) would require that when the liquid depth is insufficient to float the floating roof, the process of filling to refloat the roof must be continuous and be performed as soon as practical. The restrictions on tank landings in §115.112(d)(2)(H) adequately address emissions from landed floating roofs. The requirement in 40 CFR §63.1063(b)(5) for each unslotted guidepole cap to be closed at all times except when gauging the liquid level or taking liquid samples is addressed in §115.112(d)(2)(A).

The COMAQ and TCC suggested the rule language in §115.112(d)(2)(A) be revised to replace the phrase "no visible gap" with the phrase "no gap of more than 1/8 inch." The requested change would make the TCEQ language consistent with the language in the EPA MACT standard 40 CFR §63.1063(d)(1)(v).

The commission has made the suggested change.

The TCC encouraged the agency to incorporate the language used in 40 CFR Part 63, Subpart WW and revise §115.112(d)(2)(A) to allow exemption for leg sleeves from the requirement to have a cover.

The commission has made the suggested changes.

TxOGA suggested the word "emergency" be added before "roof drains" in §115.112(d)(2)(A) and (D).

The commission has not made the suggested change. The wording of §115.112(d)(2)(D) specifies that the requirement applies to roof drains that empty into the stored liquid. A roof drain system that uses a hose or piping to drain water from the roof to the side of the tank shell does not empty into the stored liquid and so would not be subject to the control requirement.

Dow, COMAQ, and the TCC suggested replacing the phrase "working gasket" in §115.112(d)(2)(A) - (C) (and elsewhere in the proposed document) with the phrase "gasket in good operating condition" for clarity. Additionally, the TCC and COMAQ suggested revising §115.112(d)(2)(A) and (C) by changing the term "rim vent" to "rim space vent."

The commission has made the suggested changes.

TTO suggested the rule language in §115.112(d)(2)(A) be deleted and replaced with language from 40 CFR §63.1063(a)(2)(i) and (ii) to read "each opening except for those for automatic bleeder vents (vacuum breaker vents) and rim space vents shall have its lower edge below the surface of the stored liquid. Each opening except for automatic bleeder vents (vacuum breaker vents), rim space vents, leg sleeves, and deck (roof) drains shall be equipped with a deck cover. The deck cover shall be equipped with a gasket between the cover and the deck."

The commission has made the suggested changes, with slight differences in wording to correspond to the format of the existing rule as well as agency guidelines, Texas Register guidelines, and Texas Legislative Drafting Manual, August 2006.

TTO suggested the rule language in §115.112(d)(2)(B) be deleted and replaced with language from 40 CFR §63.1063(b)(4) to read "each automatic bleeder vent (vacuum breaker vent) and rim space vent shall be closed at all times, except when required to be open to relieve excess pressure or vacuum, in accordance with the manufacturer's design." TCC suggested revising §115.112(d)(2)(B) by adding the phrase "or at the manufacturer's recommended setting" so that §115.112(d)(2)(B) will be consistent with §115.112(d)(2)(C) and with 40 CFR §63.1063(b)(4).

The commission has made the suggested changes.

TxOGA suggested the rule language in §115.112(d)(2)(C) be clarified concerning the placement of gaskets on rim vents. TxOGA suggested that the language read "rim vent valves, if flanged, must be equipped with a working gasket and the valve be set to open only when the roof is being floated off the roof leg supports or at the manufacturer's recommended setting."

The commission has revised the language in §115.112(d)(2) to be consistent with language in 40 CFR §63.1063(a)(2)(iii). The new language applicable to rim vents is in §115.112(d)(2)(B). It specifies that rim space vents must be equipped with a gasketed lid, pallet, flapper, or other closure device instead of specifying that each rim vent be equipped with a gasket.

TTO expressed support for exempting stub drains from the requirements of §115.112(d)(2)(D) and agreed with the commission's assessment that controls on stub drains would provide minimal VOC reductions.

The commission appreciates the support.

TxOGA suggested the rule language in §115.112(d)(2)(E) be clarified to read "there must be no visible holes, tears, or other openings in a primary or secondary seal or seal fabric." TxOGA expressed the opinion that the envelope on a mechanical shoe seal system is not part of the primary or secondary seal, and that the "no tear or hole" requirement should not be construed to apply to the envelope on a mechanical shoe seal system.

The commission has not made the suggested change in the rule language because the language applies to fabrics used to seal deck fittings as well as primary and secondary seals. The commission acknowledges that inspecting the envelope would be difficult in a tank equipped with a secondary seal. The inspection requirements in §115.114 do not require moving the secondary seal to inspect the primary seal. If a hole or tear in the envelope of a mechanical shoe seal is found, it must be repaired if it would cause an increase in VOC emissions. Information available to commission staff indicates that the envelope is part of the vapor barrier and thus any holes or tears found in the envelope must be repaired.

TxOGA suggested the rule language in §115.112(d)(2)(F) be clarified to read "for external floating roof storage tanks, secondary seals must be the rim-mounted type (the seal must be continuous from the floating roof to the tank wall with the exception of gaps that do not exceed the following specifications). The accumulated area of gaps that exceed 1/8 inch (0.32 centimeters) in width between the secondary seal and the tank wall must be no greater than 1.0 square inch per foot (21 square centimeters per meter) of tank diameter."

The commission has made the requested change.

COMAQ, Dow, MPL, and TxOGA suggested that the TCEQ allow the use of a pole sleeve option, similar to the EPA option in 40 CFR §60.1063(a)(2)(viii), to control VOC emissions from slotted guidepoles as an alternative to a gasketed float as specified in §115.112(d)(2)(G). TTO suggested the rule language in §115.112(d)(2)(G) be deleted and replaced with language from both the EPA Storage Tank Emission Reduction Partnership Program (STERPP) (65 FR 19891, April 13, 2000) and 40 CFR §63.1063(a)(2)(viii) to read "each opening for a slotted guidepole shall be equipped with one of the following control device configurations: (i) a pole wiper and a pole float. The wiper or seal of the pole float shall be at or above the height of the pole wiper, (ii) a pole wiper and a pole sleeve, (iii) an internal sleeve emission control system, (iv) a flexible enclosure system, or (v) an external floating roof tank cover." TCC and TxOGA suggested revising §115.112(d)(2)(G) to adopt the language of 40 CFR §63.1063 as well as all other control options provided in the EPA STERPP (65 FR 19891, April 13, 2000).

The commission has revised §115.112(d)(2)(G) to include the suggested options.

TTO suggested the language in §115.112(d)(2)(H) be revised to read "the floating roof must be floating on the liquid surface at all times except when the floating roof is supported by the leg supports during the initial fill of a new floating roof storage tank or an existing floating roof storage tank that has been degassed and/or cleaned pursuant to Subchapter F of this chapter, or as allowed under the following circumstances." TTO additionally requested clarification in preamble language concerning under which, if any, circumstances uncontrolled landing emissions would not be required to be routed to a control device in order to comply with proposed 30 TAC §115.112(d)(2)(H).

The commission has revised the language in §115.112(d)(2)(H) to allow refill of a tank that has been degassed and cleaned according to the requirements of Chapter 115, Subchapter F, Division 3. The commission has also modified preamble language to clarify that uncontrolled landing emissions would be allowed under an emissions cap as specified in §115.112(d)(2)(H)(v) or when total landing emissions at a site are less than 25 tpy as specified in the new §115.112(d)(2)(H)(vi).

Dow suggested that §115.112(d)(2)(H)(i) be clarified so that the phrase "when necessary for required maintenance or inspection" includes maintenance and inspection activities required by both environmental regulations and by company/individual site programs. COMAQ and TCC suggested removing the term "required" from §115.112(d)(2)(H)(i) since the term could be interpreted to mean the maintenance that is required by a particular rule.

The commission has deleted the word "required" as requested. The intent of the rule language is to allow landings when needed for maintenance and inspection whether the activities are needed in order to comply with environmental regulations or to satisfy company or individual site programs.

COMAQ, TCC, and TTO suggested adding the phrase "but not limited to" after "including" in §115.112(d)(2)(H)(ii).

The commission has not made the requested change. Legally, the term "including" is understood to mean "but not limited to." The commission has changed the wording to use the definition of incompatible liquid in §115.110, so the wording no longer contains the word "including."

TTO requested that §115.112(d)(2)(H)(ii) be revised to read "when necessary for supporting a change in service to a liquid that is not compatible with the previously stored liquid, including but not limited to gasoline with a different RVP to comply with applicable requirements; a termination of a contract for the storage of a liquid; a new customer or owner of a liquid coming into a storage tank; or off-spec products."

The commission has revised the definition of "incompatible liquid" in §115.110 and has changed the wording of §115.112(d)(2)(H)(ii) to use the definition. Landings to replace off-spec products could be allowed under the revised definition if the product to be loaded into the tank would be contaminated with the previously stored off-spec product to the extent that the newly-loaded product would be unusable for its intended purpose. The commission declines to allow landings for commercial reasons such as termination of a contract or a new customer or owner of a liquid but notes that facilities have the option to authorize landing emissions under an emission limit or cap or a 25 tpy exemption as specified in §115.112(d)(2)(H)(v) and (vi).

HSC requested that the proposed §115.112(d)(2)(H)(iii) be revised to change the reference to 25,000 gallons to 10,000 gallons and from 1.5 psia to 0.5 psia.

The purpose of the proposed §115.112(d)(2)(H)(iii) was to exempt floating roof tanks that store materials that could be stored in fixed-roof tanks without controls under §115.112(d)(1) from the prohibition on tank landings. When a floating roof is landed, the tank functions essentially as a fixed roof tank, negating the emission reduction benefits of the floating roof. Because §115.112(d)(1) allows materials with a vapor pressure less than 1.5 psia to be stored in fixed roof tanks, restricting landings when the materials are stored in floating roof tanks would hold owners and operators who go beyond the requirements of the rule by storing such materials in floating roof tanks to an unnecessarily restrictive standard. As discussed in response to other comments, the commission has chosen not to require materials with a vapor pressure of less than 1.5 psia to be stored in a floating roof tank or a fixed roof tank with controls.

TxOGA and TTO suggested the rule language in §115.112(d)(2)(H)(iv) be clarified to read "(H) The floating roof must be floating on the liquid surface at all times except when the floating roof is supported by the leg supports during the initial fill or as allowed under the following circumstances: (iv) when the vapors are routed to a control device from the time the roof is landed until it is within 10% of being refloated." The commenters expressed concern that vapor abatement equipment may experience problems if liquids are accidentally injected.

The commission has made the requested change.

Dow expressed support for a floating roof storage tank emissions cap in §115.112(d)(2)(H)(v) and suggested that the cap does not have to be sitewide in order to be effective. Dow suggested a structure similar to the TCEQ flexible air permitting program, where the regulated entity defines the universe of the storage tanks at a given site that can be included in the emissions cap. Dow also suggested allowing a single plant site to have multiple caps to address floating roof tanks in different geographical areas of the site.

The commission has removed the term "sitewide" from §115.112(d)(2)(H)(v) as requested.

COMAQ suggested clarifying §115.112(d)(2)(H)(v) to indicate that emissions from the landing of floating roof tanks can be authorized by an emission limit in a permit or permit by rule (PBR), or included in an emissions cap approved under 30 TAC Chapter 116. TCC suggested removing the term "sitewide" from the preamble language and from §115.112(d)(2)(H)(v) and revising the rule language to read "tank landings that comply with established Chapter 116 emission limits or caps." Both Dow and TCC suggested the rule include PBR §106.263 (which can be used for tank landings due to scheduled maintenance, startups, or shutdowns) as an authorization option for the landing of the floating roof tanks for a single tank.

The commission has removed the term "sitewide" from §115.112(d)(2)(H)(v) and added language to clarify that landing emissions can be authorized by an emission limit or a cap under a Chapter 116 permit, as long as the limit expressly includes landing loss emissions. The commission does not agree to allow the use of a PBR to comply with the provisions of §115.112(d)(2)(H). Allowing use of PBR §106.263 to authorize emissions from convenience landings could allow a site to add up to 25 tpy of VOC emissions in addition to landing loss emissions that have been authorized under an express permit limit or permit cap. The provisions of §115.112(d)(2)(H) would not prevent an owner or operator from authorizing a new tank or change of service to an existing tank under an applicable PBR, but floating roof tank landings from any such tanks would have to either meet the requirements of §115.112(d)(2)(H)(i) - (iv) or (vi) or be incorporated into an emission cap as referenced in §115.115(d)(2)(H)(v).

TTO expressed support for the compliance option authorizing the approval of sitewide floating roof storage tank emission caps in permits issued under Chapter 116 but objected to the language that excludes an increase in caps from "otherwise prohibited roof landing emissions. TTO stated the language was vague, could be read to conflict with several existing cap agreements with the Executive Director, and the cap is more appropriately left to the commission's permitting staff. TTO suggested the language "and the cap value is not increased to account for emission from landings that would otherwise be prohibited" be deleted from §115.112(d)(2)(H)(v).

The purpose of rules in Chapter 115 requiring emission reductions or controls from specific types of sources is to reduce emissions of VOC that are contributing to ozone formation in ozone nonattainment areas. Requirements in Chapter 115 may thus be more stringent than would be required by the commission's permitting staff. The requirements for monitoring and control of HRVOC in Chapter 115, Subchapter H, are an example. For the current rulemaking, however, the commission has deleted the suggested language.

HSC requested that §115.112(d)(2)(H)(v) be deleted. HSC objects to the use of an emission cap in lieu of a prohibition on convenience landings.

For-hire terminals may have difficulty complying with a strict prohibition on convenience landings, since the terminals do not own the liquid in the tanks. Complying with individual emission limits or caps will require tank owners and operators to minimize landing loss emissions while allowing them operational flexibility.

TTO suggested adding a new §115.112(d)(2)(H)(vi) and (vii) to read "(vi) when aggregate sitewide uncontrolled VOC emissions from all floating roof tank landings are less than 25 tons per year on a rolling 12-month basis using the methodology for landing emissions in the United Stated Environmental Protection Agency AP-42 "Compilation of Air Pollutant Emission Factors" (revised November 2006); (vii) when landing emissions are authorized under an applicable permit by rule in Chapter 106 of this title."

The commission agrees that an exemption from the prohibition on roof landings is appropriate for facilities with low landing loss emissions and has therefore added §115.112(d)(2)(H)(vi) to provide an exemption for facilities with sitewide emissions less than 25 tpy. As noted in response to a previous comment, the commission does not agree to allow the use of a PBR to comply with the provisions of §115.112(d)(2)(H).

GHASP suggested that the vapor recovery system control efficiency requirements in §115.112(d)(3) be changed from 90% to 95% citing that the New Source Performance Standards specify a minimum control efficiency of 95%.

The commission made no changes to the rule in response to this comment. The focus of the rulemaking project was to effect real reductions in VOC emissions. Although the rule only requires a control efficiency of 90%, many of the control devices in use in fact reduce emissions by 95% or more.

HSC requested that §115.112(d)(4) be made more stringent by requiring control of flash emissions for tanks with emissions of greater than or equal to 10 tpy instead of the proposed level of 25 tpy.

The cost effectiveness of controls decreases proportionally to a source's emissions rate. If no pipeline is available to transport recovered vapors, emissions and energy use from tanker trucks would counter some of the benefits from vapor recovery. Other states that explicitly require control of flash emissions include Wyoming and Colorado. Wyoming requires control if uncontrolled emissions are greater than or equal to 40 tpy. The state-wide Colorado rule requires control if uncontrolled emissions are greater than or equal to 20 tpy. The commenter gave no specific justification for the proposed level of 10 tpy. Furthermore, the EPA expressed support for the 25 tpy threshold.

EPA endorsed the 25 tpy threshold for control because it defines the major source level for severe ozone nonattainment areas.

The commission appreciates the support.

The TCC commented that the vapor pressure of certain liquid streams at oil and gas exploration and production sites may be greater than 11 psia because of the presence of entrained gas. TCC further requested the commission clarify that tanks containing crude oil and condensate streams that have a true vapor pressure less than 11 psia and meet the control requirements of §115.112 Table 1(a), including storage in an external floating roof with a primary and secondary seal, are adequately controlled for the purposes of this rule.

The commission does not agree that crude oil and condensate streams with a reported true vapor pressure less than 11 psia do not have flash emissions nor that storage in an external floating roof tank with primary and secondary seals provides adequate control if flash emissions are occurring. The commission acknowledges that the highest flash emissions would be expected to occur at upstream oil and gas exploration and production sites when the stream is first exposed to atmospheric pressure. Tanks at midstream pipeline breakout stations would also be expected to have higher potential for flash emissions than tanks at downstream petroleum refineries or petrochemical plants. For these reasons, the commission has revised the rule to require control of flash emissions only at the upstream oil and gas exploration and production sites and at midstream pipeline breakout stations.

The TCC suggested the preamble (specifically pages 17 and 18) be revised to remove references to crude oil and condensate storage at all locations other than exploration and production facilities. Additionally, the TCC requested the commission clarify that the term "condensate" applies to the liquids produced from natural gas rather than those tanks at a petroleum plant that may receive condensate from a natural gas production site. TxOGA requested that the term "tanks" in §115.112(d)(4) be revised to the phrase "exploration and production tanks."

The commission has changed §115.112(d)(4) and (5) to specify that control of flash emissions is required only for crude oil or condensate storage at upstream oil and gas exploration and production sites prior to custody transfer or at pipeline breakout stations. The requirements would not apply to downstream operations such as crude oil and condensate storage at petroleum refineries or petrochemical plants. Remote sensing projects carried out under TexAQS II found plumes from crude oil storage tanks at refineries. Crude oil and condensate transferred downstream may still contain dissolved gases; thus, flash emissions could still be occurring at these downstream locations. However, the H51C study that was used to determine default emission factors for crude oil and condensate storage tested tanks at upstream sites only, and the test methods that were used to measure the emissions would not be applicable to large external floating roof storage tanks such as those typically used at refineries. Tanks at midstream pipeline breakout stations are also regulated under the rule as adopted. Crude oil and condensate that have been transferred through pressurized pipelines are likely to flash when transferred to atmospheric storage tanks. The commission will continue to evaluate the extent of flash emissions at the downstream operations and may take action to regulate these sources at a later time.

The TCC suggested consistency between the actual rule language in §115.112(d)(4) and the preamble for the rule with regards to estimating flash emissions using the method that yields the higher emission rate.

The commission has moved the requirements that were proposed as §115.112(d)(4) to §115.112(d)(5) and has revised the language to state that if emissions determined using direct measurements or other methods approved by the executive director under §115.112(d)(5)(A) or (D) are higher than emissions estimated using the default factors or charts in §115.112(d)(5)(B) or (C), the higher values must be used. The intent of allowing the use of default emission factors is to enable regulated entities to avoid the cost of performing measurements or complex computer simulations. However, if the regulated entity chooses to use one of the more accurate, site-specific emission determination methods, this information should be used in determining whether emissions exceed the 25 tpy threshold.

The TCC requested clarification that simulation methods acceptable for use to estimate flash emissions include API E&P Tank Model and any other model as listed in the TCEQ EI guidance document (Technical Supplement 6, January, 2007).

The EI guidance document lists a number of methods for estimating flash emissions and ranks them according to expected accuracy. These methods are used state-wide. Flash emissions have traditionally been under reported, and one goal of the current rulemaking is to obtain a better accounting of these emissions in the HGB area. Thus, some of the methods that may be acceptable for estimating flash emissions in ozone attainment areas in West Texas may not be accurate for sources in the HGB area. The use of any simulation method is problematic, because the model must be run correctly using proper input data in order to get accurate results. Because of these problems, the commission has revised §115.112(d)(5) to delete the proposed §115.112(d)(4)(D) that would have allowed the use of computer simulations. The new §115.112(d)(5)(D) allows the use of other test methods or computer simulations pre-approved by the executive director to estimate flash emissions. Computer simulations can still be used, but must be pre-approved by the executive director to make sure the simulation is used properly.

HSC requested that §115.116(a)(1) and (b)(1) be made more stringent by changing the referenced vapor pressure from 1.0 psia to 0.5 psia.

The requested change would affect tanks in other nonattainment areas than HGB. Because notice for the proposed rule indicated that the proposed changes would only apply to tanks in the HGB area, affected owners and operators in other areas of the state have not received proper notice of any changes that would affect their operations. Thus, the requested change is beyond the scope of the current rulemaking.

Dow and COMAQ suggested the removal of the word "reportable" from §115.116(a)(2) since the term "reportable" has other meanings in other portions of Texas air pollution regulations. The removal of the word "reportable" will clarify that the additional emissions must be included in the emissions inventory report and then either recorded or reported per the applicable existing provisions in 30 TAC Chapter 101 (General Rules). TCC suggested revising §115.116(a)(2) to change the term "reportable" to "emission inventory reportable" to clarify that emissions from secondary seal gaps are not necessarily a reportable emission event as defined in Chapter 101, Subchapter F.

The commission has changed the term "reportable" to "emissions inventory reportable" as suggested.

CEMA suggested that language be added to the rule that acknowledges the option for facility operators to use internal combustion engine (ICE) based VOC oxidation systems to prevent an unfair market advantage for the control technologies listed in Chapter 115 despite equal or better performance by ICE-based equipment. CEMA suggested revising the rule language in §115.116(a)(3) and (b)(3) and §115.546(2) to include a section that reads "the output voltage of the engine exhaust oxygen sensor and the inlet and outlet gas temperature of the catalytic converter on an internal combustion engine."

The language in the rules does not specify nor exclude the use of any particular control technology as long as it achieves the required 90% reduction. The referenced rule sections do not list monitoring requirements for all possible types of control. Moreover, the suggested monitoring language for ICE equipment would not be sufficient to insure that the ICE system is functioning properly. For example, PBR §106.533(g)(4) for remediation requires that owners or operators of ICE systems conduct an evaluation of engine effectiveness initially and at least weekly, using a photo ionization detector (PID) or flame ionization detector (FID) in conjunction with a flow meter to determine the quantity of carbon compounds in the inlet gas stream and the engine exhaust. The FID or PID instrument chosen must be capable of properly detecting the types of contaminants present. For these reasons, no changes have been made to the rule language in response to the comment, but the absence of specific mention in the rule does not exclude the use of ICE-based equipment.

GHASP suggested that the owners and operators of facilities subject to the monitoring and recordkeeping requirements in §115.116 be required to report their performance parameters and efficiency calculations because the public needs the opportunity to monitor these facilities.

Facilities with Title V operating permits under 30 TAC Chapter 122 are required to submit annual reports stating whether they are in compliance with all applicable requirements, which would include rules in Chapter 115. Owners or operators must also submit deviation reports for each six-month period if there have been deviations in permit terms or conditions during the period. The public can obtain copies of these reports (minus any confidential data) from TCEQ. TCEQ investigators can also request that monitored data or calculations be reported.

EPA recommended that each requirement for a two-year record retention time, including those in §115.116(a)(5) and (b)(5), be changed to require a five-year record retention time, consistent with Title V and 30 TAC Chapter 122 requirements.

The commission has not made the suggested change. Facilities with Title V permits are required to retain records for five years under Title V and 30 TAC Chapter 122, regardless of the specified retention time in a specific rule. The requirements in §115.116(a)(5) and (b)(5) apply to sources outside the HGB nonattainment area. Thus, no changes can be made to these requirements at this time because public notice for the rulemaking indicated that the rule changes would apply only to sources in the HGB area.

HSC requested that §115.116(c)(1) be made more stringent by changing 40,000 gallons and 25,000 gallons to 10,000.

The purpose of the recordkeeping requirement in §115.116(c)(1) is to require owners and operators to maintain records documenting that the materials stored in tanks that are not equipped with controls as specified in Table I(a) or Table II(a) of §115.112(a)(1) have vapor pressures low enough to be stored without controls. As noted in response to other comments, the commission has chosen not to change the size threshold at which tanks would be subject to controls to 10,000 gallons.

Dow and TCC suggested deleting the recordkeeping requirements in §115.116(c)(1) since the regulated entity is already required to report this information through the Title V Operating Permits program. The TCC also suggested that if §115.116(c)(1) is not deleted, then the commission should clarify the phrase "length of time the material is stored" to indicate if the phrase refers to the date the tank is placed into service, the period of time it takes the tank to turnover, or the period of time that the liquid material lies in the tank while the roof is resting on its legs.

The commission has maintained the referenced recordkeeping requirement to ensure that owners and operators have appropriate, current, readily available records to allow investigators to verify that materials stored in uncontrolled tanks have vapor pressures low enough to be stored without controls. Records in Title V operating permits may only refer to material safety data sheets that list a range of vapor pressures for an ill-defined material (such as bunker oil). The actual vapor pressure of such materials can vary with different suppliers, different shipments, or different production runs. Results of remote sensing studies have shown unexpected VOC emissions from fixed-roof storage tanks that store materials with reportedly low vapor pressures. The commission has revised the language in §115.116(c)(1) to specify that the "length of time the material is stored" refers to the starting and ending dates that a material is or has been in the tank.

HSC requested that §115.116(c)(2) be made more stringent by changing the referenced emission level from 25 tpy to 10 tpy.

The purpose of the recordkeeping requirement in §115.116(c)(2) is to document that emissions from tanks not equipped with controls for flash emissions are below the level at which control is required. As discussed in response to other comments, the commission has chosen not to change the level from 25 tpy to 10 tpy. Since the level has not changed, it would be inappropriate to revise this recordkeeping requirement.

The TCC suggested revising §115.116(c)(2) to read "the owner or operator of any Exploration and Production storage vessel . . . shall maintain records . . . The records must be updated annually and must be made available for review as soon as possible upon request." The TCC suggested the commission use the "maximum authorized emission rate" to satisfy the "projected emissions" requirement, rather than requiring the owner or operator of an Exploration and Production storage vessel to speculate within the context of the rule on the projected tank emissions for the next year of operations.

The commission has revised §115.116(c)(2) to specify that the recordkeeping requirement applies only to crude oil and condensate stored prior to custody transfer or at midstream pipeline breakout stations. The commission agrees that the maximum authorized emission rate, if calculated to correctly account for flash emissions, can be used to document that emissions are less than the 25 tpy threshold for control and has deleted the requirement to project emissions for the next year.

HSC requested that the rule be made more stringent by changing 1.5 psia to 0.5 psia in §115.117(a)(1) and by changing 25,000 gallons to 10,000 gallons in §115.117(a)(3).

As noted in response to earlier comments, the commission has decided to maintain the exemption levels at 1.5 psia and 25,000 gallons.

HSC requested that the rule be made more stringent by changing 1.5 psia to 0.5 psia in §115.117(b)(1) and (c)(1), by eliminating the exemption in §115.117(b)(2), by changing 25,000 gallons to 10,000 gallons in §115.117(b)(3) and (c)(3), and changing 420,000 gallons to 10,000 gallons in §115.117(c)(4).

The requested changes affect subsections that were not opened in the current rulemaking. These subsections affect sources outside the HGB eight-hour ozone nonattainment area. Owners and operators of these sources have not been given proper notice of proposed changes and would not have an opportunity to comment. Thus, making the suggested changes is beyond the scope of the current rulemaking.

GHASP suggested eliminating the exemptions for tanks constructed prior to 1980 and 1982 and requiring the installation of appropriate rim mounted secondary seals for external floating roof tanks. In instances where upgrading the tanks is not technologically feasible, GHASP suggested that those tanks should be relegated to service with liquids with vapor pressures less than 0.5 psia, or service exempt from NSPS Subpart Kb.

The commission did not propose substantive changes to the referenced exemptions in §115.117(4), (6), or (7). Making changes at this time is thus beyond the scope of the current rulemaking because it would impose controls on owners or operators who have not received proper notice of additional regulatory requirements and would not have an opportunity to comment. The commission may consider eliminating these exemptions in a future rulemaking.

The EPA requested confirmation that credit for this rule has been appropriately prorated to reflect the extended time period allowed for compliance.

The purpose of the rule was to reduce VOC emissions that have been previously unreported or underreported in the EI. For this reason, the commission has not taken credit for emissions reductions from this rule.

The EPA requested confirmation that the new rule includes all components needed for enforcement purposes. In particular, the EPA noted that if compliance with the rule would necessitate emptying and degassing the tank, compliance would not be required until the next time the tank is emptied and degassed but not later than January 1, 2017. The EPA asked the commission to consider whether existing reporting requirements are sufficient to allow inspectors to verify the most recent date a tank was emptied and degassed and to add reporting requirements if necessary to provide for enforceability of the rule.

Commission general air quality rules in 30 TAC §101.201(b) require owners or operators to maintain records of scheduled maintenance activities, which would include tank degassing and cleaning. No changes were made to the rule as a result of this comment.

COMAQ suggested that TCEQ reconsider its position in §115.119(c) that the required control equipment could be put into place without tanks having to be taken out of service, citing that COMAQ members' experience has been that any significant work on tank roof fittings and seal systems requires tank de-inventory and degassing in order to prevent unacceptable LEL readings and personnel safety concerns.

The commission maintains that certain types of roof fittings and controls for slotted guidepoles can be installed without taking the tank out of service. However, the rule language in §115.119(c) states that compliance can be delayed beyond January 1, 2009, until the next time the tank is emptied and degassed if compliant equipment cannot be installed without taking the tank out of service. The decision whether equipment can be safely installed without taking the tank out of service will be made by the owner or operator. The rule does not give specific requirements for proving that the installation cannot be safely performed while the tank is in service, but the owner or operator should document and maintain for inspection purposes the rationale for delayed compliance.

Dow supports the TCEQ's consideration that storage vessels will have to be degassed and emptied to comply with §115.112(d) requirements, and suggested editing §115.119(c) to clarify that compliance with §§115.112(d), 115.115(c), and 115.116(c) is not required until the next scheduled emptying and degassing activity after January 1, 2009.

The commission appreciates the support, but does not agree that compliance is not required until the next scheduled emptying and degassing activity after January 1, 2009. The reason for allowing the delay of compliance is to avoid requiring that a tank be taken out of service and degassed solely for the purpose of complying with the new requirements. In some cases, the emissions that would occur from the degassing activity (even when complying with the revised requirements for degassing in Chapter 115, Subchapter F) would be greater than emissions that would be reduced by installing compliant equipment. For tanks that will be emptied and degassed after the date the rule becomes effective but prior to January 1, 2009, the commission expects that equipment required to comply with the revised rules can be installed at that time, even though compliance is not required until January 1, 2009. Owners and operators who are planning tank emptying and degassing activities should plan ahead to install compliant equipment at the next opportunity.

EPA noted that the preamble discussion for §115.119(c) states, "The commission anticipates that most, if not all, of the required control equipment can be put into place without taking the tank out of service," and requested that the commission consider modifying the rule to require that most, if not all, of the components in the rules be met by January 1, 2009.

Industry commenters disagree with the commission's statement that most required control equipment can be put into place without taking a tank out of service. The rule language states that compliance must be achieved by January 1, 2009, unless compliance would require emptying and degassing the storage tank. A further requirement that "most" of the components in the rules be met by January 1, 2009, would be unenforceable.

HSC objected to delayed compliance for tanks that must be emptied and degassed to install controls, since degassing is controlled, and stated that exceptions to not emptying a tank for installation of controls should only be allowed based on a petition from a regulated entity that demonstrates that emissions from emptying and degassing cannot be controlled and that the tank must be emptied to install the controls. GHASP commented that the storage tank regulations in Chapter 115 should mandate compliance by all affected facilities by January 1, 2009. GHASP stated that operating practices can be modified to eliminate convenience landings and that if a facility chooses to install controls that require emptying the tank, operating practices can be modified until the tank maintenance is undertaken.

In some cases, the emissions that would occur from the degassing activity (even when complying with the revised requirements for degassing in Chapter 115, Subchapter F) would be greater than emissions that would be reduced by installing compliant equipment. Due to the high cost effectiveness of requiring degassing controls on small tanks, the commission has revised the new degassing control requirements to apply only to tanks with nominal capacity greater than or equal to 250,000 gallons or to tanks with nominal capacity greater than or equal to 75,000 gallons storing material with vapor pressure greater than 2.6 psia. If degassing is not controlled, emissions from taking the tank out of service to install controls could negate the environmental benefit of the controls. The provision for delayed compliance is not anticipated to affect the compliance date for tank landings, since facilities can comply with the requirements by changes in operational practices, as noted by the commenter.

HSC requested that the control requirements for VOC loading operations in §115.212 be revised to require a control efficiency of 95% rather than 90%.

The requested change is beyond the scope of the current rulemaking, since no changes were proposed to §115.212. Staff considered this change to loading requirements as the rule proposal was being developed. According to available data in the EI, most of the control devices in use were already reducing emissions by 95% or more. Also, emissions from controlled loading operations represent a small fraction of the total VOC from point sources in the HGB area. Thus, making this change would result in only minimal emissions reductions.

RSI suggested the commission examine the upcoming South Coast Air Quality Management District (SCAQMD) tank degassing regulations.

The commission has reviewed the existing SCAQMD regulations on tank degassing and commission staff has discussed upcoming changes with SCAQMD staff.

GEM suggested degassing companies be required to provide notification of degassing activities if onsite inspections of tank degassing is going to be implemented.

The commission requires notification of scheduled maintenance activities such as tank degassing if expected emissions will exceed a reportable quantity as defined in 30 TAC §101.1. A specific notification requirement may be considered in a future rulemaking.

The TCC suggested the commission confirm in §115.541 that if a covered tank is flooded with a diluent that has a true vapor pressure of less than 0.50 psia then the control requirements of this subchapter are no longer applicable.

The commission does not agree that flooding a tank with a low vapor pressure diluent automatically negates the applicability of control requirements of Subchapter F. Pockets of material with a higher vapor pressure may be present in sludge on the tank bottom and be unaffected by the use of the diluent. Use of a diluent would also create a mixture that would presumably be a waste that could cause additional VOC emissions when disposed.

COMAQ suggested the emission specifications and control requirements for the degassing of storage tanks with a nominal capacity between 40,000 and 1 million gallons should not be included in §115.541(a)(1) and §115.547(2). COMAQ states that the 40,000 gallon threshold was arbitrarily chosen by the commission and does not take into account the quantity of emissions from the degassing process or the economic feasibility of installing the controls. TCC commented that the minimum cost for complying with the degassing requirements would be $5,000 and suggested revising the degassing emission specifications applicability threshold in §115.541 from 40,000 gallons to 250,000 gallons. HSC requested that the rule be made more stringent by changing 40,000 gallons to 10,000 gallons in §115.541(a)(1) and §115.547(2).

Emission reductions that can be realized by requiring controlled degassing decrease as the size of the tank (and, thus, the amount of vapor space saturated with VOC) decreases. Control of degassing emissions is generally carried out by outside contractors who bring equipment to the site. The charge for bringing in and operating the equipment is generally the same regardless of the size of the tank to be degassed. Thus, the cost effectiveness for controlling degassing emissions for tanks as small as 10,000 gallons is much higher than for larger tanks. The commission does not believe that the cost for controlling degassing emissions from these smaller tanks is justified. As noted by TCC, the cost effectiveness for controlling degassing emissions from a 40,000 gallon tank storing a material with a vapor pressure of 0.5 psia would be greater than $60,000 per ton of VOC removed. The commission has estimated that the cost effectiveness of controlling degassing emissions from tanks with capacity of 250,000 gallons storing materials with a vapor pressure of 0.5 psia or higher would be less than $12,000 per ton. The cost effectiveness for requiring degassing controls increases for smaller tanks and would exceed the $12,000 per ton value that is used in evaluating BACT. Thus, the commission has revised the applicability threshold to 250,000 gallons for tanks storing materials with vapor pressures down to 0.5 psia. However, smaller tanks storing more volatile materials would have higher emissions and lower cost effectiveness. Regulations applicable in the SCAQMD take the higher emission potential into account by requiring degassing controls for tanks as small as 19,815 gallons storing materials with a vapor pressure greater than 3.9 psia, and for tanks as small as 39,630 gallons storing materials with a vapor pressure greater than 2.6 psia. Commission staff estimated the cost effectiveness to control degassing emissions from tanks with a range of sizes and vapor pressures of stored liquid, and concluded that the cost effectiveness to control degassing emissions from tanks 75,000 gallons or larger storing materials with vapor pressure greater than 2.6 psia was approximately $20,000 per ton or less. The commission has revised the rule to require degassing control for tanks with a capacity of 250,000 gallons or more, and for tanks with capacity of 75,000 gallons to 250,000 gallons storing material with vapor pressure greater than 2.6 psia.

HSC additionally requested that the rule be made more stringent by changing 8,000 gallons to 5,000 gallons in §115.541(a)(2) and by changing 420,000 gallons to 10,000 gallons in §115.541(b) and §115.547(2).

The commenter gives no basis to support the requested changes. The rule proposal did not include a change in the size of transport or marine vessel that would be required to control degassing emissions. Thus, the requested change is beyond the scope of the current rulemaking.

HSC requested that the rule be made more stringent by changing 90% to 95% in §115.541(a)(1)(B) and (a)(2)(B) and in §115.541(b)(2).

GEM suggested if the four vapor space turnover requirement remains part of the degassing rule then the commission should require that approved inlet vapor flow meters be installed at the inlet of the control device to help standardize the flow volume measurement.

The commission has deleted the turnover requirement for affected sources in the HGB after January 1, 2009. The four vapor space turnover provision remains in effect for sources in the BPA nonattainment area, but changes that would affect sources in this area are beyond the scope of the current rulemaking since public notice indicated that rule changes were only being made for sources in the HGB area.

HSC requested that the rule be made more stringent by changing 34,000 ppmv to 10,000 ppmv in §115.542(a)(2) and (b)(5).

The purpose of the proposed rule was to change the method for demonstrating when sufficient degassing had occurred, not changing the required level. The 34,000 ppmv level is based on requiring degassing control down to an equivalent partial pressure of 0.5 psia: 0.5/14.7*1,000,000 = 34,000 ppmv. Because no change to this level was proposed, lowering it is beyond the scope of this rulemaking.

HSC requested that the rule be made more stringent by changing 34,000 ppmv to 10,000 ppmv in §115.542(b)(4) and by eliminating the words "a turnover of at least four vapor space volumes has occurred, the partial vapor pressure is less than 0.5 psia (19,000 ppmw) . . . or the concentration of VOC is less than 20% of the lower explosive limit."

The requirements in §115.542(b)(4) apply to sources in the Beaumont-Port Arthur (BPA) and until January 1, 2009, in the HGB area. No changes affecting sources in BPA were proposed; thus, making the requested change is beyond the scope of the current rulemaking. The regulated community must have time to implement new rule requirements; thus, the current wording is necessary to maintain the applicability of the existing requirements in HGB until the compliance date for the new requirements.

COMAQ requests that the TCEQ clarify whether "ventilated," "ventilation," and "vented" mean forced ventilation only, or both forced and passive ventilation as used in §115.542(a)(6). In this same section, the TCC suggested clarifying the intent of the phrase "before dilution."

The commission has revised the rule language to use the term "vented to the atmosphere" for clarity. The commission has removed the word "before dilution" from the rule language as requested. The intent of the phrase "before dilution" was to emphasize that vapors are not to be released to the atmosphere untreated because an excessive volume of ventilation gas is used. Depending on the type of control technology used to abate the degassing emissions, dilution gas is sometimes necessary to maintain safe conditions in the abatement device. The concentration measurement should be made before the dilution gas is added.

TxOGA expressed general support for §115.542 stating that the use of vapor concentration rather than turnover volume for determination of sufficient processing of vapors provides operational consistency during tank degassing. TxOGA suggested that the LEL is a better threshold for determining compliance than the ppmv or ppmw determination and suggested that §115.542(a)(5) and (6) be changed to add "50% LEL" as a criteria for determining when vapors can be released to atmosphere instead of the 34,000 ppmv concentration limit.

The commission agrees that a VOC concentration equivalent to 50% LEL will be lower than the 34,000 ppmv concentration criteria and so has made the requested change in §115.542(6). The commission has not made the suggested change in §115.542(a)(5) because this provision applies to sources in the BPA nonattainment area as well as to the HGB area until January 1, 2009. Because notice for the current rulemaking indicated that changes were being made only for the HGB area, changing the provision applicable to BPA is beyond the scope of the current rulemaking.

Dow, TCC, and COMAQ suggested revising the periodic measurements required to confirm that the VOC concentration is less that 34,000 ppmv in §115.542(a)(6) and (b)(5). The commenters suggested that three consecutive readings, each taken at a 12-hour interval, with a VOC concentration less than 34,000 ppmv during ventilation is adequate to confirm that the VOC concentration is not varying significantly and that further checks every 12 hours are not warranted.

The commission agrees that concentration measurements can be ceased at some point in the degassing and cleaning process but is concerned that if sludge remains in the tank after the initial degassing, VOC concentrations could decrease to less than 34,000 ppmv but later increase when the sludge is disturbed during the cleaning process. The commission has changed the rule to specify that concentration measurements can be discontinued after five consecutive readings less than 34,000 ppmv. With readings taken every 12 hours, the five readings would provide that the concentration would remain below 34,000 ppmv for at least 48 hours. VOC emissions associated with the removal of sludge from the tank may need to be recorded and reported under the maintenance rules in 30 TAC Chapter 101.

The TCC suggested revising §115.541(a)(1) and §115.542(a)(5) to allow a delay in compliance until the next time the vessel is emptied but no later than January 1, 2017, if compliance would require the installation of degassing nozzles or connections. However, if appropriate degassing nozzles can be added by changing out a manway, the TCC suggested the commission should consider revising §115.542(a)(5) to allow a manway to be opened for the short period of time necessary to change-out the manway to one with the appropriate nozzles.

The commission does not agree that a delay in compliance is necessary for tanks that must have degassing nozzles or connections installed. Hatches with nozzles installed can be obtained for newly-affected tanks. The commission has not revised §115.542(a)(5) to specifically allow the manway opening. Maintenance activities such as manway opening are subject to an affirmative defense as long as they comply with the general rules for maintenance in 30 TAC Chapter 101.

The TCC suggested that §115.542(b)(5) be revised by adding the phrase "of the degassing operation."

The commission has made the suggested change.

TTO expressed support for the 34,000 ppmv trigger for controlling vapors during tank degassing but requested clarification that sampling to obtain VOC concentration measurements during degassing does not require tank entry and VOC concentration measurements can be taken from a tank's manway. TxOGA suggested that the preamble language regarding the frequency and method for measurement of VOC concentrations in §115.545(11) be modified to read "the measurement should be made at the head space of the vessel, as close as possible to the tank bottom to ensure that the concentration measurement is representative of actual conditions. However, these measurements are to be taken at locations that do not endanger the safety of sampling personnel."

The commission did not intend that VOC measurements be made inside the tank or other location that would endanger the safety of sampling personnel.

COMAQ, Dow, GEM, TCC, TTO, and TxOGA suggested the agency allow acceptable alternate test methods for VOC concentration measurements specified in §115.545(11). The suggested methods include EPA Method 25A; EPA Method 18, adjusted to allow for one bag sample to be collected; bag sampling; portable hydrocarbon gas analyzer; PID; chemical specific detection tubes; and LEL meters. COMAQ commented that FIDs are not appropriate for testing VOC in nitrogen-rich, oxygen-poor atmospheres because the FID will "flame out." Dow suggested that measurement of the total organic carbon (TOC) content of the condensate stream be allowed for vessels that are degassed and cleaned via steam.

The commission agrees that additional methods for measuring the VOC concentration would be acceptable and has revised the rule accordingly. The commission does not agree that chemical specific detection tubes are appropriate because they are usually compound specific and could result in false negatives. Also, the detection tubes might be difficult to operate in the tank degassing environment. The commission does not agree that measurement of the TOC content of the condensate stream would be an appropriate indication of the VOC concentration of the vapor space. Even if an accurate correlation between the TOC concentration of the condensate and the VOC in the vapor space could be determined, use of this method would require the TCEQ staff to review and approve the correlation before it could be used. Tank degassing events are episodic and of short duration; approval of a correlation might not be possible in time for it to be used.

Dow and TCC suggested that the TCEQ clarify that the instrument response factor criteria in §8.1 of EPA Method 21 be for the average composition of the liquid in the tank, transport vessel, or marine vessel and not for each individual VOC in the liquid. Dow noted that this approach is consistent with EPA's HON regulation in 40 CFR §63.180(b)(2)(i).

The commission agrees that use of the average composition of the tank contents to determine the instrument response factor is appropriate and has revised the rule accordingly.

RSI suggested that the protocol for sampling and analyzing must be clearly defined so that enforcement does not have to merely assume that measurements are being done correctly.

The commission has listed approved testing methods in §115.545(11) in order to ensure that measurements are being performed correctly.

COMAQ suggested including an exemption from the emissions specifications and control requirements if the tank owner or operator can demonstrate compliance would be economically unreasonable by revising §115.547(2) to read "degassing and cleaning . . . any stationary VOC storage tank with a nominal storage capacity of less than one million gallons, or any marine vessel, with a nominal storage capacity of less than 10,000 barrels (420,000 gallons), is exempt from the requirements of this division. In addition, a tank is exempt from the requirements of this division if its owner or operator can demonstrate to the satisfaction of the executive director that compliance with the requirements of this division would be economically unreasonable."

The commission does not agree that an exemption should be allowed for individual tanks based on whether control is "economically unreasonable." The rules in Chapter 115 must meet the standards that the EPA has set for reasonably available control technology (RACT). The EPA definition of RACT is "the lowest emission limitation that a particular source can meet by applying a control technique that is reasonably available considering technological and economic feasibility." The standard is economic feasibility, not economic reasonableness. With the revised applicability levels in the adopted rule based on tank size and vapor pressure of stored material, the commission maintains that control of degassing emissions from all affected tanks is economically reasonable as well as technically and economically feasible.

RSI commented that calculating the destruction rate efficiency of abatement devices used to control emissions from the tank degassing process is not easily defined. Knowing the influent concentration in ppmv makes logical sense for determining when a tank degassing event is finished but in order to determine the allowable emissions it is necessary to also know the flow rate of the effluent in cubic feet per minute.

The degassing rules do not require a calculation of allowable emissions from abatement devices. Thus, no changes have been made to the rule in response to this comment.

RSI expressed concern that their ICE technology, with destruction efficiency greater than 99.9%, will be priced out of the market in Texas because these rules only require a destruction efficiency of 90%.

The commission has made no change to the rules as a result of this comment. Even though the rule only specifies 90% destruction efficiency, other concerns may drive regulated entities to use more efficient control equipment. When degassing operations are carried out as part of maintenance activities, emissions must be minimized under the requirements of the general air quality rules in 30 TAC Chapter 101. Emissions from planned maintenance activities must be authorized under 30 TAC Chapters 106 or 116 according to the schedule in 30 TAC §101.222. Authorization will require use of BACT, which could require more stringent control than the minimum specified in 30 TAC §115.541.

TxOGA expressed support for a portable equipment registration or certification program for vendors or contractors who provide degassing equipment that would certify that the vendor degassing equipment meets TCEQ emission standards and ensure that contractor providing the portable equipment understands TCEQ rules and documentation requirements.

Establishing a registration or certification program for degassing vendors or contractors is beyond the scope of the current rulemaking, but the commission may consider such a program in the future.

HSC requested that the exemption for oceangoing, self-propelled marine vessels in §115.547(5) be removed so that these vessels must be degassed and cleaned when they have emptied their VOC cargo.

The commission did not provide notice of any change to the referenced exemption for oceangoing, self-propelled marine vessels. Thus, proper notice to the owners and operators of such vessels has not been given and making the requested change is beyond the scope of the current rulemaking. The commission may consider a change to this exemption in future rulemaking.

Subchapter B. GENERAL VOLATILE ORGANIC COMPOUND SOURCES

1. STORAGE OF VOLATILE ORGANIC COMPOUNDS

30 TAC §§115.110, 115.112 - 115.117, 115.119

STATUTORY AUTHORITY

The amendments and new rule are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, that authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code; and under Texas Health and Safety Code, §382.017, concerning Rules, that authorizes the commission to adopt rules consistent with the policy and purposes of the Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act). The amendments and new rule are also adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, that establishes the commission's purpose to safeguard the state air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, that authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, that authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require the submission of information concerning the emission of air contaminants; and §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to require owners and operators of emission sources to maintain measuring and monitoring records and make such records available to the commission. The rules are adopted under federal mandates contained in 42 USC, §7410, that require states to introduce pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted amendments and new rule implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, and 382.016.

§115.110.Definitions.

The following words and terms, when used in this division (relating to Storage of Volatile Organic Compounds), have the following meanings, unless the context clearly indicates otherwise. Additional definitions for terms used in this division are found in §§3.2, 101.1, and 115.10 of this title (relating to Definitions).

(1) Deck cover--A device that covers an opening in a floating roof deck. Some deck covers move horizontally relative to the deck (i.e., a sliding cover).

(2) Flexible enclosure system--A system that includes all of the following: a flexible device that completely encloses the slotted guidepole and eliminates the hydrocarbon vapor emission pathway from inside the tank through the guidepole slots to the outside air; a guidepole cover at the top of the guidepole; and a well cover positioned at the top of the guidepole well that seals any openings between the well cover and the guidepole (e.g. pole wiper), any openings between the well cover and any other objects that pass through the well cover, and any other openings in the top of the guidepole well.

(3) Incompatible liquid--A liquid that is a different chemical compound, a different chemical mixture, a different grade of liquid material, or a fuel with different regulatory specifications provided that the chemical compound, chemical mixture, grade of liquid material, or fuel would be unusable for its intended purpose due to contamination from the previously stored liquid.

(4) Internal sleeve emission control system--An emissions control system that includes all of the following: an internal guidepole sleeve that eliminates the hydrocarbon vapor emission pathway from inside the tank through the guidepole slots to the outside air; a guidepole cover at the top of the guidepole; and a well cover positioned at the top of the guidepole well that seals any openings between the well cover and the guidepole (e.g. pole wiper), any openings between the well cover and any other objects that pass through the well cover, and any other openings in the top of the guidepole well.

(5) Pipeline breakout station--A facility along a pipeline containing storage vessels used to relieve surges or receive and store crude oil or condensate from the pipeline for reinjection into the pipeline and continued transportation by pipeline or to other facilities.

(6) Pole float--A float located inside a guidepole that floats on the surface of the stored liquid. The rim of the float has a wiper or seal that extends to the inner surface of the pole.

(7) Pole sleeve--A device that extends from either the cover or the rim of an opening in a floating roof deck to the outer surface of a pole that passes through the opening. The sleeve extends into the stored liquid.

(8) Pole wiper--A seal that extends from either the cover or the rim of an opening in a floating roof deck to the outer surface of a pole that passes through the opening.

(9) Slotted guidepole--A guidepole or gaugepole that has slots or holes through the wall of the pole. The slots or holes allow the stored liquid to flow into the pole at liquid levels above the lowest operating level.

(10) Tank battery--A collection of equipment used to separate, treat, store, and transfer crude oil, condensate, natural gas, and produced water. A tank battery typically receives crude oil, condensate, natural gas, or some combination of these extracted products from several production wells for accumulation and separation prior to transmission to a natural gas plant or petroleum refinery. A collection of storage tanks at a pipeline breakout station, petroleum refinery, or petrochemical plant is not considered to be a tank battery.

§115.112.Control Requirements.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and until January 1, 2009, in the Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), the following requirements apply.

(1) No person shall place, store, or hold in any stationary tank, reservoir, or other container any volatile organic compound (VOC) unless such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is equipped with at least the control device specified in Table I(a) of this paragraph for VOC other than crude oil and condensate, or Table II(a) of this paragraph for crude oil and condensate.

Figure: 30 TAC §115.112(a)(1)

(2) For floating roof storage tanks subject to the provisions of paragraph (1) of this subsection, the following requirements apply.

(A) All openings in an internal or external floating roof except for automatic bleeder vents (vacuum breaker vents) and rim space vents must provide a projection below the liquid surface or be equipped with a cover, seal, or lid. Any cover, seal, or lid must be in a closed (i.e., no visible gap) position at all times except when the device is in actual use.

(B) Automatic bleeder vents (vacuum breaker vents) must be closed at all times except when the roof is being floated off or landed on the roof leg supports.

(C) Rim vents, if provided, must be set to open only when the roof is being floated off the roof leg supports or at the manufacturer's recommended setting.

(D) Any roof drain that empties into the stored liquid must be equipped with a slotted membrane fabric cover that covers at least 90% of the area of the opening.

(E) There must be no visible holes, tears, or other openings in any seal or seal fabric.

(F) For external floating roof storage tanks, secondary seals must be the rim-mounted type (the seal must be continuous from the floating roof to the tank wall). The accumulated area of gaps that exceed 1/8 inch (0.32 centimeter) in width between the secondary seal and tank wall must be no greater than 1.0 square inch per foot (21 square centimeters permeter) of tank diameter.

(3) Vapor recovery systems used as a control device on any stationary tank, reservoir, or other container must maintain a minimum control efficiency of 90%.

(b) For all persons in Gregg, Nueces, and Victoria Counties, the following requirements shall apply:

(1) No person shall place, store, or hold in any stationary tank, reservoir, or other container any volatile organic compound (VOC), unless such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is equipped with at least the control device specified in Table I(a) for VOC other than crude oil and condensate or Table II(a) for crude oil and condensate.

(2) For floating roof storage tanks subject to the provisions of paragraph (1) of this subsection, the following requirements shall apply.

(A) All openings in an internal or external floating roof, except for automatic bleeder vents (vacuum breaker vents) and rim space vents, must provide a projection below the liquid surface or be equipped with a cover, seal, or lid. Any cover, seal, or lid must be in a closed (i.e., no visible gap) position at all times, except when the device is in actual use.

(B) Automatic bleeder vents (vacuum breaker vents) are to be closed at all times except when the roof is being floated off or landed on the roof leg supports.

(C) Rim vents, if provided, are to be set to open only when the roof is being floated off the roof leg supports or at the manufacturer's recommended setting.

(D) Any roof drain that empties into the stored liquid shall be equipped with a slotted membrane fabric cover that covers at least 90% of the area of the opening.

(E) There shall be no visible holes, tears, or other openings in any seal or seal fabric.

(F) For external floating roof storage tanks, secondary seals shall be the rim-mounted type (the seal shall be continuous from the floating roof to the tank wall). The accumulated area of gaps that exceed 1/8 inch (0.32 centimeter) in width between the secondary seal and tank wall shall be no greater than 1.0 square inch per foot (21 square centimeters/meter) of tank diameter.

(c) For all persons in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties, the following requirements shall apply.

(1) No person may place, store, or hold in any stationary tank, reservoir, or other container any VOC, other than crude oil or condensate, unless such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is designed and equipped with at least the control device specified in Table I(b) for VOC other than crude oil and condensate.

Figure: 30 TAC §115.112(c)(1) (No change.)

(2) For floating roof storage tanks subject to the provisions of paragraph (1) of this subsection, the following requirements shall apply.

(A) There shall be no visible holes, tears, or other openings in any seal or seal fabric.

(B) All tank gauging and sampling devices shall be vapor-tight except when gauging and sampling is taking place.

(3) No person in Matagorda or San Patricio Counties shall place, store, or hold crude oil or condensate in any stationary tank, reservoir, or other container, unless such tank, reservoir, or other container is a pressure tank capable of maintaining working pressures sufficient at all times to prevent vapor or gas loss to the atmosphere or is equipped with one of the following vapor-loss control devices, properly maintained and operated:

(A) an internal floating cover or external floating roof as defined in §115.10 of this title (relating to Definitions). This control equipment shall not be permitted if the VOC has a true vapor pressure of 11.0 psia (75.8 kPa) or greater. All tank-gauging and tank-sampling devices shall be vapor-tight, except when gauging or sampling is taking place; or

(B) a vapor recovery system as defined in §115.10 of this title (relating to Definitions).

(d) For all persons in the Houston/Galveston/Brazoria area the following requirements apply beginning January 1, 2009.

(1) No person shall place, store, or hold in any stationary tank, reservoir, or other container any VOC unless such container is capable of maintaining working pressure sufficient at all times to prevent any vapor or gas loss to the atmosphere, or is equipped with at least the control device specified in either Table I(a) of subsection (a)(1) of this section for VOC other than crude oil and condensate, or Table II(a) of subsection (a)(1) of this section for crude oil and condensate.

(2) For floating roof storage tanks subject to the provisions of paragraph (1) of this subsection, the following requirements apply.

(A) All openings in an internal floating cover or external floating roof as defined in §115.10 of this title (relating to Definitions) except for automatic bleeder vents (vacuum breaker vents), and rim space vents must provide a projection below the liquid surface. All openings in an internal floating cover or external floating roof except for automatic bleeder vents (vacuum breaker vents), rim space vents, leg sleeves, and roof drains must be equipped with a deck cover. The deck cover must be equipped with a gasket in good operating condition between the cover and the deck. The deck cover must be closed (i.e. no gap of more than 1/8 inch) at all times, except when the cover must be open for access.

(B) Automatic bleeder vents (vacuum breaker vents) and rim space vents must be equipped with a gasketed lid, pallet, flapper, or other closure device and must be closed (i.e. no gap of more than 1/8 inch) at all times except when required to be open to relieve excess pressure or vacuum, in accordance with the manufacturer's design.

(C) Each opening into the internal floating cover for a fixed roof support column may be equipped with a flexible fabric sleeve seal instead of a deck cover.

(D) Any roof drain that empties into the stored liquid must be equipped with a slotted membrane fabric cover that covers at least 90% of the area of the opening or an equivalent control that must be kept in a closed (i.e., no gap of more than 1/8 inch) position at all times except when the drain is in actual use. Stub drains on internal floating roof tanks are not subject to this requirement.

(E) There must be no visible holes, tears, or other openings in any seal or seal fabric.

(F) For external floating roof storage tanks, secondary seals must be the rim-mounted type (the seal must be continuous from the floating roof to the tank wall with the exception of gaps that do not exceed the following specification). The accumulated area of gaps that exceed 1/8 inch (0.32 centimeter) in width between the secondary seal and tank wall must be no greater than 1.0 square inch per foot (21 square centimeters per meter) of tank diameter.

(G) Each opening for a slotted guidepole in an external floating roof tank must be equipped with one of the control device configurations specified in clauses (i) - (vi) of this subparagraph.

(i) A pole wiper and a pole float. The wiper or seal of the pole float must be at or above the height of the pole wiper.

(ii) A pole wiper and a pole sleeve.

(iii) An internal sleeve emission control system.

(iv) Retrofit to a solid guidepole system.

(v) A flexible enclosure system.

(vi) A cover on an external floating roof tank.

(H) The floating roof must be floating on the liquid surface at all times except when the floating roof is supported by the leg supports or other support devices (e.g., hangers from the fixed roof) during the initial fill (including refill after the tank has been degassed and cleaned in accordance with §§115.541 - 115.547 of this title (relating to Degassing or Cleaning of Stationary, Marine, and Transport Vessels) or as allowed under the following circumstances:

(i) when necessary for maintenance or inspection;

(ii) when necessary for supporting a change in service to an incompatible liquid);

(iii) when the storage tank has a capacity of less than 25,000 gallons or the vapor pressure of the material stored is less than 1.5 psia;

(iv) when the vapors are routed to a control device from the time the floating roof is landed until the floating roof is within ten percent by volume of being refloated;

(v) when all emissions from the tank, including emissions from roof landings, have been included in a floating roof storage tank emissions limit or cap approved under Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification); or

(vi) when all emissions from floating roof landings at the regulated entity as defined in §101.1 of this title (relating to Definitions) are less than 25 tons per year.

(3) Vapor recovery systems used as a control device on any stationary tank, reservoir, or other container must maintain a minimum control efficiency of 90%.

(4) Storage tanks storing condensate prior to custody transfer must route flashed gases to a vapor recovery system or control device if the liquid throughput through an individual tank or the aggregate of tanks in a tank battery exceeds 1,500 barrels (63,000 gallons) per year.

(5) Storage tanks storing crude oil or condensate prior to custody transfer or at a pipeline breakout station must route flashed gases to a vapor recovery system or control device if the uncontrolled VOC emissions from an individual storage tank, or from the aggregate of tanks in a tank battery, have the potential to equal or exceed 25 tons per year on a rolling 12-month basis. Uncontrolled emissions must be estimated by one of the following methods; however, if emissions determined using direct measurements or other methods approved by the executive director under subparagraphs (A) or (D) of this paragraph are higher than emissions estimated using the default factors or charts in subparagraphs (B) or (C) of this paragraph, the higher values must be used:

(A) direct measurement using the measuring instruments and methods specified in §115.115 of this title (relating to Approved Test Methods);

(B) using a factor of 33.3 pounds of VOC per barrel (42 gallons) of condensate produced or 1.6 pounds of VOC per barrel (42 gallons) of oil produced;

(C) for crude oil storage only, using the chart in Exhibit 2 of the United States Environmental Protection Agency publication Lessons Learned from Natural Gas STAR Partners: Installing Vapor Recovery Units on Crude Oil Storage Tanks, October 2003, and assuming that the hydrocarbon vapors have a molecular weight of 34 pounds per pound mole and are 48% by weight VOC; or

(D) other test method or computer simulation approved by the executive director.

§115.115.Approved Test Methods.

(a) For the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas, compliance with §115.112(a) and (d) of this title (relating to Control Requirements) must be determined by applying the following test methods, as appropriate:

(1) Test Methods 1-4 (40 Code of Federal Regulations (CFR) Part 60, Appendix A) for determining flow rates, as necessary;

(2) Test Method 18 (40 CFR Part 60, Appendix A) for determining gaseous organic compound emissions by gas chromatography;

(3) Test Method 22 (40 CFR Part 60, Appendix A) for visual determination of fugitive emissions from material sources and smoke emissions from flares;

(4) Test Method 25 (40 CFR Part 60, Appendix A) for determining total gaseous nonmethane organic emissions as carbon;

(5) Test Methods 25A or 25B (40 CFR Part 60, Appendix A) for determining total gaseous organic concentrations using flame ionization or nondispersive infrared analysis;

(6) test method described in 40 CFR §60.113a(a)(1)(ii) (effective April 8, 1987) for measurement of storage tank seal gap;

(7) determination of true vapor pressure using American Society for Testing and Materials (ASTM) Test Methods D323-89, D2879, D4953, D5190, or D5191 for the measurement of Reid vapor pressure; or

(8) minor modifications to these test methods approved by the executive director.

(b) For Gregg, Nueces, and Victoria Counties, compliance with §115.112(b) of this title shall be determined by applying the following test methods, as appropriate:

(1) Test Methods 1-4 (40 Code of Federal Regulations 60, Appendix A) for determining flow rates, as necessary;

(2) Test Method 18 (40 Code of Federal Regulations 60, Appendix A) for determining gaseous organic compound emissions by gas chromatography;

(3) Test Method 22 (40 Code of Federal Regulations 60, Appendix A) for visual determination of fugitive emissions from material sources and smoke emissions from flares;

(4) Test Method 25 (40 Code of Federal Regulations 60, Appendix A) for determining total gaseous nonmethane organic emissions as carbon;

(5) Test Methods 25A or 25B (40 Code of Federal Regulations 60, Appendix A) for determining total gaseous organic concentrations using flame ionization or nondispersive infrared analysis;

(6) test method described in 40 CFR 60.113a(a)(1)(ii) (effective April 8, 1987) for measurement of storage tank seal gap;

(7) determination of true vapor pressure using ASTM Test Methods D323-89, D2879, D4953, D5190, or D5191 for the measurement of Reid vapor pressure; or

(8) minor modifications to these test methods approved by the executive director.

(c) For the Houston/Galveston/Brazoria area, compliance with §115.112(d)(5) of this title may be determined by using the following measurement instruments or applying the following test methods, as appropriate:

(1) mass flow meter, positive displacement meter, or similar device over a 24-hour period representative of normal operation for flow measurements of flash gases. For crude oil and natural gas production sites, the flow measurements must be made while the producing wells are operational; and

(2) test methods referenced in subsection (a)(2), (4), and (5) of this section or Gas Processors Association Method 2286, Tentative Method of Extended Analysis for Natural Gas and Similar Mixtures by Temperature Programmed Gas Chromatography, to measure the concentration of VOC in the flashed gases; or

(3) minor modifications to these test methods approved by the executive director.

§115.116.Monitoring and Recordkeeping Requirements.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas, the following recordkeeping requirements apply.

(1) The owner or operator of any storage vessel with an external floating roof that is exempted from the requirement for a secondary seal as specified in §115.117(a)(1), (6), and (7) of this title (relating to Exemptions) and is used to store volatile organic compounds (VOC) with a true vapor pressure greater than 1.0 pounds per square inch absolute (psia) (6.9 kilo Pascals (kPa)) at storage conditions shall maintain records of the type of VOC stored and the average monthly true vapor pressure of the stored liquid.

(2) The results of inspections required by §115.114(a) of this title (relating to Inspection Requirements) must be recorded. For secondary seal gaps that are required to be physically measured during inspection, these records must include a calculation of emissions for all secondary seal gaps that exceed 1/8 inch (0.32 centimeter) where the accumulated area of such gaps is greater than 1.0 square inch per foot (21 square centimeters per meter) of tank diameter. These calculated emissions inventory reportable emissions (Tr) must be reported in the annual emissions inventory submittal required by §101.10 of this title (relating to Emissions Inventory Requirements). The emissions must be calculated using the following methodology:

(A) Allowable Seal Gap (greater than 1/8 inch wide): As (square inches) = 1 square inch per tank diameter foot x tank diameter.

(B) Measured Seal Gap: Ms (square inches).

(D) Reportable Seal Gap/Allowable Ratio: RRs = Rs divided by As.

(E) Tank Circumference: Tc (feet).

(F) Reportable Seal Gap Length (total linear feet of seal gap greater than 1/8 inch gap width): Rl.

(G) Reportable Seal Gap Length/Tank Circumference Ratio: RRl = Rl/Tc.

(H) Tank Emissions (with good single seal): Ts = Compilation of Air Pollutant Emission Factors (AP-42) Calculation (convert to pounds/day).

(I) Tank Emissions (with two good seals): Tss = AP-42 Calculation (convert to pounds/day). Note: Use maximum local monthly average ambient temperature as reported by the National Weather Service to calculate true vapor pressure.

(J) Emissions Inventory Reportable emissions: Tr (pounds) = (Ts - Tss) x RRs x RRl x 90 days. Note: In no case should Tr be greater than (Ts - Tss).

(3) Affected persons shall install and maintain monitors to continuously measure and record operational parameters of any of the following emission control devices installed to meet applicable control requirements. Such records must be sufficient to demonstrate proper functioning of those devices to design specifications, including:

(A) the exhaust gas temperature immediately downstream of a direct-flame incinerator;

(B) the inlet and outlet gas temperature of a chiller or catalytic incinerator; and

(C) the exhaust gas VOC concentration of any carbon adsorption system, as defined in §115.10 of this title (relating to Definitions), to determine if breakthrough has occurred.

(4) The results of any testing conducted in accordance with the provisions specified in §115.115(a) of this title (relating to Approved Test Methods) must be maintained at an affected facility.

(5) All records must be maintained for two years and be made available for review upon request by authorized representatives of the executive director, the United States Environmental Protection Agency (EPA), or local air pollution control agencies with jurisdiction.

(b) For all persons in Gregg, Nueces, and Victoria Counties, the following recordkeeping requirements shall apply.

(1) The owner or operator of any storage vessel with an external floating roof which is exempted from the requirement for a secondary seal as specified in §115.117(b)(1), (6), and (7) of this title and used to store VOC with a true vapor pressure greater than 1.0 psia (6.9 kPa) at storage conditions shall maintain records of the type of VOC stored and the average monthly true vapor pressure of the stored liquid.

(2) The results of inspections required by §115.114(b) of this title shall be recorded.

(3) In Victoria County, affected persons shall install and maintain monitors to continuously measure and record operational parameters of any of the following emission control devices installed to meet applicable control requirements. Such records must be sufficient to demonstrate proper functioning of those devices to design specifications, including:

(A) the exhaust gas temperature immediately downstream of a direct-flame incinerator;

(B) the inlet and outlet gas temperature of a chiller or catalytic incinerator; and

(C) the exhaust gas VOC concentration of any carbon adsorption system, as defined in §115.10 of this title, to determine if breakthrough has occurred.

(4) The results of any testing conducted in accordance with the provisions specified in §115.115(b) of this title shall be maintained at an affected facility.

(5) All records shall be maintained for two years and be made available for review upon request by authorized representatives of the executive director, EPA, or local air pollution control agencies.

(c) For all persons in the Houston/Galveston/Brazoria area, the following recordkeeping requirements apply in addition to those specified in subsection (a) of this section.

(1) The owner or operator of any stationary tank, reservoir, or container with a fixed roof that is not required to be equipped with a floating roof or vapor recovery system, as specified in either Table I(a) or Table II(a) of §115.112(a)(1) of this title (relating to Control Requirements), shall maintain records of the type of VOC stored, the starting and ending dates when the material is stored, and the true vapor pressure at the average monthly storage temperature of the stored liquid. This requirement does not apply to storage tanks with nominal storage capacity of 25,000 gallons or less storing volatile organic liquids other than crude oil or condensate, or to storage tanks with nominal storage capacity of 40,000 gallons or less storing crude oil or condensate.

(2) The owner or operator of any storage tank that stores crude oil or condensate prior to custody transfer or at a pipeline breakout station and is not equipped with vapor recovery shall maintain records of the estimated annual emissions from the storage tank to document that the uncontrolled emissions are less than 25 tons per year. The records must be updated annually and must be made available for review within 72 hours upon request by authorized representatives of the executive director, the EPA, or local air pollution control agencies with jurisdiction.

§115.117.Exemptions.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas, the following exemptions apply.

(1) Except as provided in §115.116 of this title (relating to Monitoring and Recordkeeping Requirements), any volatile organic compound (VOC) with a true vapor pressure less than 1.5 pounds per square inch absolute (psia) (10.3 kilo Pascals (kPa)) at storage conditions is exempt from the requirements of this division (relating to Storage of Volatile Organic Compounds).

(2) Crude oil and condensate stored in tanks with a nominal capacity less than 210,000 gallons (794,850 liters), prior to custody transfer, is exempt from the requirements of this division. After January 1, 2009, this exemption no longer applies in the Houston/Galveston/Brazoria area.

(3) Storage containers that have a capacity of less than 25,000 gallons (94,625 liters) located at motor vehicle fuel dispensing facilities are exempt from the requirements of this division.

(4) A welded tank with a mechanical shoe primary seal that has a secondary seal from the top of the shoe seal to the tank wall (a shoe-mounted secondary seal) is exempt from the requirement for retrofitting with a rim-mounted secondary seal if the shoe-mounted secondary seal was installed or scheduled for installation before August 22, 1980.

(5) External floating roof tanks storing waxy, high pour point crude oils are exempt from any secondary seal requirements of §115.112(a) of this title (relating to Control Requirements).

(6) Any welded tank storing VOC having a true vapor pressure less than 4.0 psia (27.6 kPa) is exempt from any external floating roof secondary seal requirement if any of the following types of primary seals have been installed before August 22, 1980:

(A) a mechanical shoe seal;

(B) a liquid-mounted foam seal; or

(7) Any welded tank storing crude oil having a true vapor pressure equal to or greater than 4.0 psia (27.6 kPa) and less than 6.0 psia (41.4 kPa) at storage conditions is exempt from any external floating roof secondary seal requirement if any of the following types of primary seals have been installed before December 10, 1982:

(A) a mechanical shoe seal;

(B) a liquid-mounted foam seal; or

(8) Storage containers that have a capacity of no more than 1,000 gallons are exempt from the requirements of this division.

(9) Condensate storage tanks or tank batteries with a throughput exceeding 1,500 barrels (63,000 gallons) per year are exempt from the requirement in §115.112(d)(4) of this title to route flashed gases to a vapor recovery system or control device if the owner or operator demonstrates using test methods specified in §115.115(c) of this title, that uncontrolled VOC emissions from the individual tank, or from the aggregate of storage tanks in a tank battery, are less than 25 tons per year on a rolling 12-month basis.

(b) For all persons in Gregg, Nueces, and Victoria Counties, the following exemptions apply.

(1) Except as provided in §115.116 of this title, any VOC with a true vapor pressure less than 1.5 psia (10.3 kPa) at storage conditions is exempt from the requirements of this division.

(2) Crude oil and condensate stored in tanks with a nominal capacity less than 210,000 gallons (794,850 liters), prior to custody transfer, is exempt from the requirements of this division.

(3) Storage containers which have a capacity of less than 25,000 gallons (94,625 liters) located at motor vehicle fuel dispensing facilities are exempt from the requirements of this division.

(4) A welded tank with a mechanical shoe primary seal which has a secondary seal from the top of the shoe seal to the tank wall (a shoe-mounted secondary seal) is exempt from the requirement for retrofitting with a rim-mounted secondary seal if the shoe-mounted secondary seal was installed or scheduled for installation before August 22, 1980.

(5) External floating roof tanks storing waxy, high pour point crude oils are exempt from any secondary seal requirements of §115.112(b) of this title.

(6) Any welded tank storing VOC having a true vapor pressure less than 4.0 psia (27.6 kPa) is exempt from any external secondary seal requirement if any of the following types of primary seals have been installed before August 22, 1980:

(A) a mechanical shoe seal;

(B) a liquid-mounted foam seal; or

(7) Any welded tank storing crude oil having a true vapor pressure equal to or greater than 4.0 psia (27.6 kPa) and less than 6.0 psia (41.4 kPa) at storage conditions is exempt from any external secondary seal requirement if any of the following types of primary seals have been installed before December 10, 1982:

(A) a mechanical shoe seal;

(B) a liquid-mounted foam seal; or

(8) Storage containers which have a capacity of no more than 1,000 gallons are exempt from the requirements of this division.

(c) For all persons in Aransas, Bexar, Calhoun, Matagorda, San Patricio, and Travis Counties, the following exemptions apply.

(1) Any VOC with a true vapor pressure less than 1.5 psia (10.3 kPa) at storage conditions is exempt from the requirements of this division.

(2) Slotted sampling and gauge pipes installed in any floating roof storage tank are exempt from the provisions of §115.112(c) of this title.

(3) Storage tanks with nominal capacities between 1,000 gallons (3,785 liters) and 25,000 gallons (94,625 liters) are exempt from the requirements of §115.112(c)(1) of this title if construction began before May 12, 1973.

(4) Storage tanks with a nominal capacity of 420,000 gallons (1,589,700 liters) or less are exempt from the requirements of §115.112(c)(3) of this title.

(5) Storage containers which have a capacity of no more than 1,000 gallons are exempt from the requirements of this division.

§115.119.Counties and Compliance Schedules.

(a) The owner or operator of each stationary tank, reservoir, or other container in which any volatile organic compound (VOC) is placed, stored, or held in Brazoria, Chambers, Collin, Dallas, Denton, El Paso, Fort Bend, Galveston, Hardin, Harris, Jefferson, Liberty, Montgomery, Orange, Tarrant, and Waller Counties shall continue to comply with this division (relating to Storage of Volatile Organic Compounds) as required by §115.930 of this title (relating to Compliance Dates).

(b) The owner or operator of each stationary tank, reservoir, or other container in which any VOC is placed, stored, or held in Ellis, Johnson, Kaufman, Parker, and Rockwall Counties shall comply with this division as soon as practicable, but no later than March 1, 2009.

(c) The owner or operator of each stationary tank, reservoir, or other container in which any VOC is placed, stored, or held in Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties shall comply with the requirements of §§115.112(d), 115.115(c), and 115.116(c) of this title (relating to Control Requirements; Approved Test Methods; and Monitoring and Recordkeeping Requirements) as soon as practicable, but no later than January 1, 2009. If compliance with these requirements would require emptying and degassing of the stationary tank, reservoir, or container, compliance is not required until the next time the stationary tank, reservoir, or container is emptied or degassed but no later than January 1, 2017. The owner or operator of each stationary tank, reservoir, or container with a nominal capacity less than 210,000 gallons (794,850 liters) storing crude oil and condensate prior to custody transfer in Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties shall comply with the requirements of this division as soon as practicable but no later than January 1, 2009, regardless if compliance with these requirements would require emptying and degassing of the stationary tank, reservoir, or container.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702034

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter F. MISCELLANEOUS INDUSTRIAL SOURCES

3. DEGASSING OR CLEANING OF STATIONARY, MARINE, AND TRANSPORT VESSELS

30 TAC §§115.541 - 115.547, 115.549

STATUTORY AUTHORITY

The amendments are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, that authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code; and under Texas Health and Safety Code, §382.017, concerning Rules, that authorizes the commission to adopt rules consistent with the policy and purposes of the Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act). The amendments are also adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, that establishes the commission's purpose to safeguard the state air resources, consistent with the protection of public health, general welfare, and physical property; §382.011, concerning General Powers and Duties, that authorizes the commission to control the quality of the state's air; §382.012, concerning State Air Control Plan, that authorizes the commission to prepare and develop a general, comprehensive plan for the control of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require the submission of information concerning the emission of air contaminants; and §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to require owners and operators of emission sources to maintain measuring and monitoring records and make such records available to the commission. The rules are adopted under federal mandates contained in 42 USC, §7410, that require states to introduce pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted amendments implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, and 382.016.

§115.541.Emission Specifications.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), the following emission specifications apply to degassing during or in preparation of cleaning.

(1) For all stationary volatile organic compound (VOC) storage tanks with a nominal storage capacity of one million gallons or more and after January 1, 2009, storage tanks in the Houston/Galveston/Brazoria area with a nominal storage capacity of 250,000 gallons or greater or with a nominal storage capacity of 75,000 gallons or greater storing materials with a true vapor pressure greater than 2.6 pounds per square inch absolute (psia).

(A) No person shall permit VOC emissions with a vapor space partial pressure greater than or equal to 0.5 psia (3.4 kilo Pascals (kPa)) under actual storage conditions unless the vapors are processed by a vapor control system.

(B) The vapor control system must maintain a control efficiency of at least 90%.

(C) When conducting degassing or cleaning operations, no avoidable liquid or gaseous leaks, as detected by sight or sound, may originate from the degassing or cleaning operations.

(D) The intentional bypassing of a vapor control device used during degassing or cleaning is prohibited. Any visible VOC leak originating from the vapor control device or other associated product recovery device must be repaired as soon as practical.

(2) For all transport vessels, as defined in §115.10 of this title, with a nominal storage capacity of 8,000 gallons or more.

(A) No person shall permit VOC emissions with a vapor space partial pressure greater than or equal to 0.5 psia (3.4 kPa) under actual storage conditions unless the vapors are processed by a vapor control system.

(B) The vapor control system must maintain a control efficiency of at least 90%.

(C) When conducting degassing or cleaning operations, no avoidable liquid or gaseous leaks, as detected by sight or sound, may originate from the degassing or cleaning operations.

(E) All transport vessels, as defined in §115.10 of this title, must be kept vapor-tight at all times until the VOC vapors remaining in the vessel are discharged to a vapor control system.

(b) For all persons in the Beaumont/Port Arthur and Houston/Galveston/Brazoria areas, the following emission specifications apply to degassing during or in preparation of cleaning for all marine vessels, as defined in §101.1 of this title (relating to Definitions), that have a nominal storage capacity of 10,000 barrels (420,000 gallons) or more and contain VOC.

(1) No person shall degas or clean a tank that carried a VOC with a vapor partial pressure greater than or equal to 0.5 psia (3.4 kPa) unless the vapors are processed by a vapor control system.

(2) The vapor control system must maintain a control efficiency of at least 90%.

(3) When conducting degassing or cleaning operations, no avoidable liquid or gaseous leaks, as detected by sight or sound, may originate from the degassing or cleaning operations.

(4) The intentional bypassing of a vapor control device used during degassing or cleaning is prohibited. Any visible VOC leak originating from the vapor control device or other associated product recovery device must be repaired as soon as possible.

(5) All marine vessels, as defined in §101.1 of this title, containing VOC must have all cargo tank closures properly secured, or maintain a negative pressure within the tank when a closure is opened, and must have all pressure/vacuum relief valves operating within certified limits as specified by classification society or flag state until the vapors are discharged to a vapor control system if the vessel is degassed or cleaned.

§115.542.Control Requirements.

(a) For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), the following control requirements apply to stationary storage tanks and transport vessels.

(1) No person shall permit the degassing or cleaning of volatile organic compounds (VOC) from a stationary storage tank or transport vessel unless the vapors are processed by a vapor control system.

(2) When degassing or cleaning is effected through the hatches of a transport vessel with a loading arm equipped with a vapor collection adapter, then pneumatic, hydraulic, or other mechanical means must be provided to force a vapor-tight seal between the adapter and the hatch. A means must be provided to minimize liquid drainage from the degassing or cleaning device when it is removed from the hatch of any transport vessel or to accomplish drainage before such removal.

(3) When degassing or cleaning is effected through the hatches or manways of stationary VOC storage tanks, all lines must be equipped with fittings that make vapor-tight connections and that are closed when disconnected; or equipped to permit residual VOC in the line to discharge into a recovery or disposal system after degassing or cleaning is complete.

(4) Degassing and cleaning equipment must be designed and operated to prevent avoidable VOC leaks.

(5) In the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and until January 1, 2009, in the Houston/Galveston/Brazoria areas, vapors must be routed to the control device until a turnover of at least four vapor space volumes has occurred, or four turnovers of the vapor space under a floating roof, or the partial vapor pressure is less than 0.5 pounds per square inch absolute (psia) (19,000 parts per million by weight (ppmw), or 34,000 parts per million by volume (ppmv) expressed as methane). After one of these conditions has been satisfied, the storage tank or transport vessel may be vented to the atmosphere for the remainder of the degassing or cleaning process.

(6) After January 1, 2009, in the Houston/Galveston/Brazoria area, vapors must be routed to the control device until the VOC measured concentration before the inlet to the control device is less than 34,000 ppmv as methane or less than 50% of the lower explosive limit (LEL). After this condition has been satisfied, the storage tank or transport vessel may be vented to the atmosphere for the remainder of the degassing or cleaning process provided that the VOC concentration remains below 34,000 ppmv as methane or less than 50% of the LEL. The VOC concentration must be measured once every 12 hours if the storage tank or transport vessel is vented continuously to the atmosphere, and upon restart of the degassing and cleaning operation if venting to the atmosphere has been suspended for more than four hours. If any measurements of the VOC concentration equal or exceed 34,000 ppmv as methane or are equal to or greater than 50% of the LEL, the storage tank or transport vessel must be routed to the control device until the concentration is below 34,000 ppmv as methane or less than 50% of the LEL. While venting to the atmosphere, measurements must continue until five consecutive readings of VOC concentrations collected at 12 hour intervals are measured to be less than 34,000 ppmv or less than 50% of the LEL.

(b) For all persons in the Beaumont/Port Arthur and Houston/Galveston/Brazoria areas, the following control requirements apply to marine vessels.

(1) No person shall permit the degassing or cleaning of a marine vessel containing VOC unless the vapors are processed by a vapor control system.

(2) When degassing or cleaning is effected through the hatches of a marine vessel containing VOC with a loading arm equipped with a vapor collection adapter, then pneumatic, hydraulic, or other mechanical means must be provided to force a vapor-tight seal between the adapter and the hatch, or a negative pressure inside the cargo tank must be maintained. A means must be provided to minimize liquid drainage from the degassing or cleaning device and line when they are removed from the hatch of any marine vessel containing VOC or to accomplish drainage before such removal.

(3) Degassing and cleaning equipment must be designed and operated to prevent avoidable VOC leaks.

(4) In the Beaumont/Port Arthur area and until January 1, 2009, in the Houston/Galveston/Brazoria area, vapors must be routed to the control device until the marine vessel is stripped VOC liquid-free and a turnover of at least four vapor space volumes has occurred, the partial vapor pressure is less than 0.5 psia (19,000 ppmw, or 34,000 ppmv expressed as methane), or the concentration of VOC is less than 20% of the LEL. After one of these conditions has been satisfied, the marine vessel may be vented to the atmosphere for the remainder of the degassing or cleaning process.

(5) After January 1, 2009, in the Houston/Galveston/Brazoria area, vapors must be routed to the control device until the VOC measured concentration before the inlet to the control device is less than 34,000 ppmv as methane or less than 50% of the LEL. After this condition has been satisfied, the marine vessel may be vented to the atmosphere for the remainder of the degassing or cleaning process provided that the VOC concentration remains below 34,000 ppmv as methane or less than 50% of the LEL. The VOC concentration must be measured once every 12 hours if the marine vessel is vented continuously to the atmosphere, and upon restart of the degassing and cleaning operation if venting to the atmosphere has been suspended for more than four hours. If any measurements of the VOC concentration equal or exceed 34,000 ppmv as methane or are equal to or greater than 50% of the LEL, the marine vessel must be routed to the control device until the concentration is below 34,000 ppmv as methane or less than 50% of the LEL. While venting to the atmosphere, measurements must continue until five consecutive readings of VOC concentrations collected at 12-hour intervals are measured to be less than 34,000 ppmv or less than 50% of the LEL.

§115.543.Alternate Control Requirements.

For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), alternate methods of demonstrating and documenting continuous compliance with the applicable control requirements or exemption criteria in this division (relating to Degassing or Cleaning of Stationary, Marine, and Transport Vessels) may be approved by the executive director in accordance with §115.910 of this title (relating to Availability of Alternate Means of Control) if emission reductions are demonstrated to be substantially equivalent.

§115.544.Inspection Requirements.

For all persons in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), the following inspection requirements apply.

(1) Inspection for visible liquid leaks, visible fumes, or significant odors resulting from volatile organic compound (VOC) transfer operations must be conducted during each degassing or cleaning operation by the owner or operator of the VOC degassing and cleaning facility.

(2) VOC degassing or cleaning through the affected transfer lines must be discontinued when a leak is observed and the leak cannot be repaired within a reasonable length of time. The intentional bypassing of a vapor control device during cleaning or degassing is prohibited.

§115.545.Approved Test Methods.

For the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions), compliance with §115.541 and §115.542 of this title (relating to Emission Specifications and Control Requirements) must be determined by applying the following test methods, as appropriate:

(1) Test Methods 1-4 (40 Code of Federal Regulations (CFR) Part 60, Appendix A) for determining flow rates;

(2) Test Method 18 (40 CFR Part 60, Appendix A) for determining gaseous organic compound emissions by gas chromatography;

(3) Test Method 25 (40 CFR Part 60, Appendix A) for determining total gaseous nonmethane organic emissions as carbon;

(4) Test Methods 25A or 25B (40 CFR Part 60, Appendix A) for determining total gaseous organic concentrations using flame ionization or nondispersive infrared analysis;

(5) additional test procedures described in 40 CFR §60.503(b), (c), and (d) (effective February 14, 1989) for determining compliance for bulk gasoline terminals;

(6) Test Method 21 (40 CFR Part 60, Appendix A) for determining volatile organic compound (VOC) leaks;

(7) determination of true vapor pressure using American Society for Testing and Materials (ASTM) Test Method D323-89, D2879, D4953, D5190, or D5191 for the measurement of Reid vapor pressure, adjusted for actual storage temperature in accordance with API Publication 2517, Third Edition, 1989;

(8) Test Method 27 (40 CFR Part 60, Appendix A) for determining tank-truck leaks;

(9) 40 CFR §63.565(c) (effective September 19, 1995) or 40 CFR §61.304(f) (effective October 17, 2000) for determination of marine vessel vapor tightness;

(10) minor modifications to these test methods approved by the executive director; or

(11) VOC concentration measurements required by §115.542(a)(6) and (b)(5) of this title (relating to Control Requirements) must be performed using one of the methods or measurement instruments listed in subparagraphs (A) - (F) of this paragraph.

(A) Test Method 21 (40 CFR Part 60, Appendix A). The instrument response factor criteria in §8.1 of the United States Environmental Protection Agency Method 21 may be determined using the average composition of the liquid in the tank rather than for each individual liquid.

(B) Test Method 18 (40 CFR Part 60, Appendix A) except that only one bag sample needs to be collected for each concentration measurement.

(C) Bag samples, provided the means of collecting the sample and the type of bag used are appropriate and representative of the type of space being sampled and the analytical method used to evaluate bag contents are appropriate for the concentration levels and compound types.

(D) Test Method 25A (40 CFR Part 60, Appendix A).

(E) Portable hydrocarbon gas analyzer using an appropriate detector that is effective in the concentration range being measured and calibrated with compounds of interest in each case. Analyzers must be calibrated and maintained according to manufacturer's specifications.

(F) Lower explosive limit detector. The detector must be calibrated and maintained according to manufacturer's specifications.

§115.546.Monitoring and Recordkeeping Requirements.

For facilities in the Beaumont/Port Arthur, Dallas/Fort Worth, El Paso, and Houston/Galveston/Brazoria areas as defined in §115.10 of this title (relating to Definitions) affected by §115.541 and §115.542 of this title (relating to Emission Specifications and Control Requirements), the owner or operator of any volatile organic compound (VOC) degassing or cleaning facility shall maintain the following information at the facility for at least two years and shall make such information available upon request to representatives of the executive director, the United States Environmental Protection Agency, or any local air pollution control agency having jurisdiction in the area:

(1) for storage tank, transport vessel, or marine vessel degassing or cleaning operations:

(A) a record of the type and number of all transport vessels, stationary VOC storage tanks, and marine vessels that are degassed or cleaned at the affected facility;

(B) the chemical name and estimated liquid quantity of VOC contained in each vessel prior to degassing or cleaning;

(C) the chemical name and estimated liquid quantity of VOC removed from each storage tank, transport vessel, or marine vessel; and

(D) after January 1, 2009, in the Houston/Galveston/Brazoria area, a record of the measurements of VOC concentration or percent of lower explosive limit from the storage tank, transport vessel, or marine vessel being degassed while the tank or vessel is vented to the atmosphere;

(2) for vapor control systems:

(A) continuous monitoring and recording of the exhaust gas temperature immediately downstream of a direct-flame incinerator;

(B) continuous monitoring and recording of the inlet and outlet gas temperature of a catalytic incinerator; and

(C) continuous monitoring and recording of the exhaust gas VOC concentration for carbon adsorption systems that contain facilities to regenerate the carbon bed directly, as defined in §115.10 of this title (relating to Definitions); or periodic monitoring of the exhaust gas VOC as specified by 40 Code of Federal Regulations §61.354(d) (effective October 17, 2000), of any carbon adsorption system that does not regenerate the carbon bed directly, to determine breakthrough;

(3) the results of any leak inspection and repair conducted in accordance with the provisions specified in §115.544 of this title (relating to Inspection Requirements); and

(4) the results of any testing conducted in accordance with the provisions specified in §115.545 of this title (relating to Approved Test Methods).

§115.547.Exemptions.

(1) Degassing or cleaning any storage tank, transport vessel, or marine vessel with a vapor space partial pressure less than 0.5 pounds per square inch absolute (psia) (3.4 kilo Pascals) of volatile organic compound (VOC) under actual storage conditions is exempt from the requirements of this division (relating to Degassing or Cleaning of Stationary, Marine, and Transport Vessels).

(2) Degassing or cleaning any transport vessel with a nominal storage capacity of less than 8,000 gallons, or any stationary VOC storage tank with a nominal storage capacity of less than 1 million gallons, or any marine vessel with a nominal storage capacity of less than 10,000 barrels (420,000 gallons), is exempt from the requirements of this division. After January 1, 2009, stationary VOC storage tanks in the Houston/Galveston/Brazoria area with a nominal storage capacity and vapor pressure of stored liquid as listed in subparagraphs (A) and (B) of this paragraph are no longer exempt from the requirements of this division.

(A) Storage tanks with nominal storage capacity greater than or equal to 250,000 gallons but less than 1 million gallons.

(B) Storage tanks with nominal storage capacity greater than or equal to 75,000 gallons but less than 250,000 gallons storing materials with true vapor pressure greater than 2.6 psia.

(3) Any stationary VOC storage tank during preventative maintenance, roof repair, primary seal inspection, or removal and installation of a secondary seal, if product is not moved in or out of the storage tank, emissions are minimized, and the repair is completed within seven calendar days, is exempt from the requirements of this division.

(4) Any marine vessel that has sustained damage that prevents a cargo tank's opening from being properly secured, causes the onboard vapor recovery system to be inoperative, or prevents the pressure/vacuum relief valves from operating within certified limits as specified by classification society or flag state is exempt from §115.541(b) and §115.542(b) of this title (relating to Emission Specifications and Control Requirements); however, all reasonable measures must be taken to minimize VOC emissions.

(5) Any oceangoing, self-propelled marine vessel is exempt from the degassing or cleaning requirements of this division.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702035

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Chapter 117. CONTROL OF AIR POLLUTION FROM NITROGEN COMPOUNDS

The Texas Commission on Environmental Quality (TCEQ or commission) adopts the repeal of §§117.10, 117.101, 117.103, 117.105 - 117.111, 117.113 - 117.117, 117.119, 117.121, 117.131, 117.133 - 117.135, 117.138, 117.139, 117.141, 117.143, 117.145, 117.147, 117.149, 117.151, 117.201, 117.203, 117.205 - 117.211, 117.213 - 117.217, 117.219, 117.221, 117.223, 117.260, 117.261, 117.265, 117.273, 117.279, 117.283, 117.301, 117.305, 117.309, 117.311, 117.313, 117.319, 117.321, 117.401, 117.405, 117.409, 117.411, 117.413, 117.419, 117.421, 117.451, 117.455, 117.458, 117.460, 117.461, 117.463, 117.465, 117.467, 117.469, 117.471, 117.473, 117.475, 117.478, 117.479, 117.481, 117.510, 117.512, 117.520, 117.524, 117.530, 117.534, 117.570, and 117.571. The commission also adopts new §§117.10, 117.100, 117.103, 117.105, 117.110, 117.115, 117.123, 117.125, 117.130, 117.135, 117.140, 117.145, 117.150, 117.152, 117.154, 117.156, 117.200, 117.203, 117.205, 117.210, 117.215, 117.223, 117.225, 117.230, 117.235, 117.240, 117.245, 117.252, 117.254, 117.256, 117.300, 117.303, 117.305, 117.310, 117.315, 117.320, 117.323, 117.325, 117.330, 117.335, 117.340, 117.345, 117.350, 117.352, 117.354, 117.356, 117.400, 117.403, 117.410, 117.423, 117.425, 117.430, 117.435, 117.440, 117.445, 117.450, 117.454, 117.456, 117.1000, 117.1003, 117.1005, 117.1010, 117.1015, 117.1020, 117.1025, 117.1035, 117.1040, 117.1045, 117.1052, 117.1054, 117.1056, 117.1100, 117.1103, 117.1105, 117.1110, 117.1115, 117.1120, 117.1125, 117.1135, 117.1140, 117.1145, 117.1152, 117.1154, 117.1156, 117.1200, 117.1203, 117.1205, 117.1210, 117.1215, 117.1220, 117.1225, 117.1235, 117.1240, 117.1245, 117.1252, 117.1254, 117.1256, 117.1300, 117.1303, 117.1310, 117.1325, 117.1335, 117.1340, 117.1345, 117.1350, 117.1354, 117.1356, 117.2000, 117.2003, 117.2010, 117.2025, 117.2030, 117.2035, 117.2045, 117.2100, 117.2103, 117.2110, 117.2125, 117.2130, 117.2135, 117.2145, 117.3000, 117.3003, 117.3005, 117.3010, 117.3020, 117.3025, 117.3035, 117.3040, 117.3045, 117.3054, 117.3056, 117.3100, 117.3101, 117.3103, 117.3110, 117.3120, 117.3123, 117.3125, 117.3140, 117.3142, 117.3145, 117.3200, 117.3201, 117.3203, 117.3205, 117.3210, 117.3215, 117.3300, 117.3303, 117.3310, 117.3325, 117.3330, 117.3335, 117.3345, 117.4000, 117.4005, 117.4025, 117.4035, 117.4040, 117.4045, 117.4050, 117.4100, 117.4105, 117.4125, 117.4135, 117.4140, 117.4145, 117.4150, 117.4200, 117.4205, 117.4210, 117.8000, 117.8010, 117.8100, 117.8110, 117.8120, 117.8130, 117.8140, 117.9000, 117.9010, 117.9020, 117.9030, 117.9100, 117.9110, 117.9120, 117.9130, 117.9200, 117.9210, 117.9300, 117.9320, 117.9340, 117.9500, 117.9800, and 117.9810.

The repeals and new sections of Chapter 117 will be submitted to the United States Environmental Protection Agency (EPA) as a revision to the state implementation plan (SIP), except for the following new sections: §§117.110(c), 117.125, 117.210(c), 117.225, 117.310(c), 117.325, 117.410(d), 117.425, 117.1010(b), 117.1025, 117.1110(b), 117.1125, 117.1210(b), 117.1225, 117.1310(b), 117.1325, 117.2010(i), 117.2025, 117.2110(h), 117.2125, 117.3010(e), 117.3025, 117.3123(f), 117.3125, 117.3310(e), and 117.3325. Sections 117.110(c), 117.125, 117.210(c), 117.225, 117.310(c), 117.325, 117.1010(b), 117.1025, 117.1110(b), 117.1125, 117.1210(b), 117.1225, 117.2010(i), 117.2025, 117.3010(e), and 117.3025 correspond to portions of the existing rule previously excluded from the EPA-approved Texas SIP. Sections 117.410(d), 117.425, 117.1310(b), 117.1325, 117.2110(h), 117.2125, 117.3123(f), 117.3125, 117.3310(e), and 117.3325 are portions of new rules adopted with this rulemaking that have not previously been submitted to EPA.

The commission adopts the repeal of §§117.10, 117.101, 117.103, 117.105 - 117.111, 117.113 - 117.117, 117.119, 117.121, 117.131, 117.133 - 117.135, 117.138, 117.139, 117.141, 117.143, 117.145, 117.147, 117.149, 117.151, 117.201, 117.203, 117.205 - 117.211, 117.213 - 117.217, 117.219, 117.221, 117.223, 117.260, 117.261, 117.265, 117.273, 117.279, 117.283, 117.301, 117.305, 117.309, 117.311, 117.313, 117.319, 117.321, 117.401, 117.405, 117.409, 117.411, 117.413, 117.419, 117.421, 117.451, 117.455, 117.458, 117.460, 117.461, 117.463, 117.465, 117.467, 117.469, 117.471, 117.473, 117.475, 117.478, 117.479, 117.481, 117.510, 117.512, 117.520, 117.524, 117.530, 117.534, 117.570, and 117.571 without changes. New §§117.10, 117.123, 117.223, 117.323, 117.400, 117.403, 117.410, 117.423, 117.440, 117.445, 117.1000, 117.1100, 117.1125, 117.1200, 117.1300, 117.1310, 117.1345, 117.2035, 117.2100, 117.2103, 117.2110, 117.2130, 117.2135, 117.2145, 117.3020, 117.3103, 117.3123, 117.3142, 117.3145, 117.3300, 117.3303, 117.3310, 117.3325, 117.3330, 117.3335, 117.3345, 117.9030, 117.9210, 117.9320, and 117.9340 are adopted with changes to the proposed text as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10538). New §§117.100, 117.103, 117.105, 117.110, 117.115, 117.125, 117.130, 117.135, 117.140, 117.145, 117.150, 117.152, 117.154, 117.156, 117.200, 117.203, 117.205, 117.210, 117.215, 117.225, 117.230, 117.235, 117.240, 117.245, 117.252, 117.254, 117.256, 117.300, 117.303, 117.305, 117.310, 117.315, 117.320, 117.325, 117.330, 117.335, 117.340, 117.345, 117.350, 117.352, 117.354, 117.356, 117.425, 117.430, 117.435, 117.450, 117.454, 117.456, 117.1003, 117.1005, 117.1010, 117.1015, 117.1020, 117.1025, 117.1035, 117.1040, 117.1045, 117.1052, 117.1054, 117.1056, 117.1103, 117.1105, 117.1110, 117.1115, 117.1120, 117.1135, 117.1140, 117.1145, 117.1152, 117.1154, 117.1156, 117.1203, 117.1205, 117.1210, 117.1215, 117.1220, 117.1225, 117.1235, 117.1240, 117.1245, 117.1252, 117.1254, 117.1256, 117.1303, 117.1325, 117.1335, 117.1340, 117.1350, 117.1354, 117.1356, 117.2000, 117.2003, 117.2010, 117.2025, 117.2030, 117.2045, 117.2125, 117.3000, 117.3003, 117.3005, 117.3010, 117.3025, 117.3035, 117.3040, 117.3045, 117.3054, 117.3056, 117.3100, 117.3101, 117.3110, 117.3120, 117.3125, 117.3140, 117.3200, 117.3201, 117.3203, 117.3205, 117.3210, 117.3215, 117.4000, 117.4005, 117.4025, 117.4035, 117.4040, 117.4045, 117.4050, 117.4100, 117.4105, 117.4125, 117.4135, 117.4140, 117.4145, 117.4150, 117.4200, 117.4205, 117.4210, 117.8000, 117.8010, 117.8100, 117.8110, 117.8120, 117.8130, 117.8140, 117.9000, 117.9010, 117.9020, 117.9100, 117.9110, 117.9120, 117.9130, 117.9200, 117.9300, 117.9500, 117.9800, and 117.9810 are adopted without changes and the text will not be republished.

BACKGROUND AND SUMMARY OF THE FACTUAL BASIS FOR THE ADOPTED RULES

GENERAL BACKGROUND

The commission is repealing 30 Texas Administrative Code (TAC) Chapter 117, Control of Air Pollution from Nitrogen Compounds, in its entirety and adopts a new reformatted Chapter 117. This repeal and reformatting of Chapter 117 is necessary to accommodate new rules for the eight-hour ozone attainment demonstration and to provide for future potential rulemakings. The adopted rules retain current one-hour ozone rules for all ozone attainment and nonattainment areas of the state. Further background information on the existing Chapter 117 one-hour ozone rules may be found in previous amendments to Chapter 117. In addition to the reformatting of Chapter 117, the rulemaking implements requirements of House Bill (HB) 965. During the 79th Legislature, 2005, the Texas Legislature adopted HB 965, requiring the commission to conduct a study to determine the technical and economic feasibility of regulating residential water heaters. If the study indicated that regulating residential water heaters is technically or economically infeasible, HB 965 required that the executive director recommend to the commission that the rules be repealed no later than December 31, 2006.

This rulemaking also includes new rules that are part of the commission's control strategy for the Dallas-Fort Worth eight-hour nonattainment area to attain the eight-hour ozone national ambient air quality standards (NAAQS) and are a part of the eight-hour attainment demonstration SIP revision for the Dallas-Fort Worth eight-hour nonattainment area. The rules adopted in this rulemaking will require emission reductions necessary for the Dallas-Fort Worth eight-hour nonattainment area to make progress toward, attain, and maintain the eight-hour ozone NAAQS.

The Federal Clean Air Act (FCAA) Amendments of 1990, as codified in 42 United States Code (USC), §§7401 et seq ., require EPA to set NAAQS to ensure public health and to designate areas as either in attainment or nonattainment with the NAAQS, or as unclassifiable. States are primarily responsible for ensuring attainment and maintenance of the NAAQS once established by EPA. Each state is required to submit a SIP to the EPA that provides for attainment and maintenance of the NAAQS for those areas in nonattainment.

The Dallas-Fort Worth area, consisting of four counties (Collin, Dallas, Denton, and Tarrant), was designated nonattainment and classified as moderate for the one-hour ozone NAAQS in accordance with the 1990 FCAA Amendments. The area was required to attain the one-hour ozone NAAQS by November 15, 1996. A SIP was submitted based on a volatile organic compound (VOC) reduction strategy, but the Dallas-Fort Worth area did not attain the NAAQS by the mandated deadline. Consequently, in 1998 the EPA reclassified the Dallas-Fort Worth area from "moderate" to "serious," resulting in a requirement to submit an additional SIP revision demonstrating attainment by the new deadline of November 15, 1999.

The Dallas-Fort Worth area also failed to reach attainment by the November 15, 1999, deadline. In the attainment demonstration SIP revision adopted by the commission in April 2000, the importance of local nitrogen oxides (NO_X ) reductions as well as the transport of ozone and its precursors from the Houston-Galveston-Brazoria ozone nonattainment area were considered. Based on photochemical modeling demonstrating transport from the Houston-Galveston-Brazoria area, the agency requested an extension of the Dallas-Fort Worth area attainment date to November 15, 2007, the same attainment date as for the Houston-Galveston-Brazoria area, in accordance with an EPA policy allowing extension of attainment dates due to transport of pollutants from other areas.

The EPA transport policy was later overturned by three federal courts, including the Court of Appeals for the 5th Circuit, which ruled in Sierra Club et. al v. EPA , 314 F. 3d 735 (2002) that EPA did not have authority to extend an area's attainment date based on transport. Although the Dallas-Fort Worth area was not the specific subject of any of these suits, as a result, the EPA could not approve the Dallas-Fort Worth area one-hour ozone attainment demonstration SIP, including an extended attainment date.

On July 18, 1997, EPA promulgated a revised ozone standard (the eight-hour ozone NAAQS), (62 FR 38856). The eight-hour ozone NAAQS was challenged by numerous litigants and ultimately upheld by the United States Supreme Court in February 2001. On April 30, 2004, EPA promulgated the first phase of the implementation rules for the eight-hour ozone NAAQS (Phase I Implementation Rule) (69 FR 23951). Also on April 30, 2004, the Dallas-Fort Worth area was designated as nonattainment and classified as moderate for the eight-hour ozone NAAQS. Five additional counties (Ellis, Johnson, Kaufman, Parker, and Rockwall) were added to the Dallas-Fort Worth eight-hour ozone nonattainment area. Effective June 15, 2004, nine counties (Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant) in the Dallas-Fort Worth area are nonattainment for the eight-hour ozone NAAQS. The Dallas-Fort Worth eight-hour nonattainment area must attain the eight-hour ozone NAAQS by June 15, 2010.

EPA's Phase I Implementation Rule provided three options for eight-hour ozone nonattainment areas that do not have an approved one-hour ozone attainment SIP: 1) submit a one-hour ozone attainment demonstration; 2) submit an eight-hour ozone attainment providing for a 5% increment of progress (IOP) emission reductions from the area's 2002 emissions baseline that is in addition to federal and state measures already approved by EPA and achieves these reductions by June 15, 2007; or 3) submit an eight-hour ozone attainment demonstration. The due date for any option selected was June 15, 2005, one year after designation. The commission, in consultation with EPA, determined that option two was the most expeditious approach to beginning to achieve the emission reductions ultimately needed to meet the June 15, 2005, transportation conformity deadline and make progress toward attainment of the eight-hour ozone NAAQS by June 15, 2010. Therefore, the commission adopted a 5% IOP Plan in April 2005 and submitted it to EPA. On November 29, 2005, EPA subsequently finalized its Phase II Implementation Rule for the eight-hour ozone NAAQS (Phase II Implementation Rule) (70 FR 71612). The Phase II Implementation Rule provides guidance and requirements for the remaining elements of the program to implement the eight-hour ozone NAAQS.

On December 22, 2006, the District of Columbia (D.C.) Circuit Court issued an opinion, South Coast AQMD v. EPA , 472 F. 3d 882 (D.C. Cir., 2006), regarding the Phase I Implementation Rule. The court granted certain petitions in part that were associated with the case, vacated the Phase I Implementation Rule and remanded the rule to the EPA for further proceedings. EPA requested and was granted an extension to the deadline for appeal of the ruling, until March 22, 2007. The EPA, as well as industry participants and plaintiffs, subsequently appealed. The Phase I rule specified requirements for the preparation, adoption, and submittal of SIPs for the eight-hour ozone standard, in addition to revoking the one-hour ozone standard for an area one year after the effective date of the designation of an area for the eight-hour standard. Since this ruling is being appealed, the full impact of this ruling will not be known until the ruling is final and EPA has promulgated new rules. While it is likely that SIP planning efforts will be impacted, the commission has no information regarding how control strategies may be impacted by this decision. The commission is proceeding with adoption of this rulemaking to implement the control strategies for the Dallas-Fort Worth eight-hour ozone attainment demonstration. However, the commission will continue to evaluate the D.C. Circuit Court opinion and follow the issue as it proceeds.

The emission reduction requirements from this rulemaking will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour nonattainment area and help make progress toward compliance with the eight-hour ozone NAAQS. Based on comments received, the commission has determined that the proposed compliance date of March 1, 2009, for the new rules associated with the Dallas-Fort Worth eight-hour ozone attainment demonstration does not provide sufficient time for a number of sources to implement controls and begin compliance with testing, monitoring, recordkeeping, and other requirements associated with the rules. Therefore, a two-step compliance schedule has been adopted based on source category. Some source categories must comply with the original proposed date of March 1, 2009, and other source categories must comply by March 1, 2010. The selection of the source categories for the two compliance schedules was based on the number of sources in each category, the type of controls likely to be implemented to meet the adopted emission specifications, the time required to implement those controls, and the amount of reductions expected from each source category.

CHAPTER 117 REFORMAT

The commission is repealing Chapter 117, Control of Air Pollution from Nitrogen Compounds, in its entirety and adopting a new reformatted Chapter 117. This repeal and reformatting of Chapter 117 is necessary to accommodate new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration and to provide for future potential rulemaking.

Subchapters, divisions, and key sections with new requirements or modifications associated with the Dallas-Fort Worth eight-hour ozone attainment demonstration include: Subchapter A, Definitions, §117.10; Subchapter B, Combustion Control at Major Industrial, Commercial, and Institutional Sources in Ozone Nonattainment Areas, Division 4, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, §§117.400, 117.403, 117.410, 117.423, 117.425, 117.430, 117.435, 117.440, 117.445, 117.450, 117.454, and 117.456; Subchapter C, Combustion Control at Major Utility Electric Generation Sources in Ozone Nonattainment Areas, Division 4, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, §§117.1300, 117.1303, 117.1310, 117.1325, 117.1335, 117.1340, 117.1345, 117.1350, 117.1354, and 117.1356; Subchapter D, Combustion Control at Minor Sources in Ozone Nonattainment Areas, Division 2, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources, §§117.2100, 117.2103, 117.2110, 117.2125, 117.2130, 117.2135, and 117.2145; Subchapter E, Multi-Region Combustion Control, Division 2, Cement Kilns, §§117.3103, 117.3123, 117.3125, 117.3142, and 117.3145; Subchapter E, Multi-Region Combustion Control, Division 4, East Texas Combustion, §§117.3300, 117.3303, 117.3310, 117.3325, 117.3330, 117.3335, and 117.3345; and Subchapter H, Administrative Provisions, Division 1, Compliance Schedules, §§117.9030, 117.9130, 117.9210, 117.9320, and 117.9340.

Demonstrating Noninterference under Federal Clean Air Act, Section 110(l)

The commission provides the following information to clarify that the repeal and reformatting of 30 TAC Chapter 117 will not negatively impact the status of the state's attainment and maintenance of the ozone NAAQS. All existing rules remain effective until the effective date of the reformatted 30 TAC Chapter 117. All requirements in the existing rules for the one-hour ozone NAAQS have been incorporated into the new formatted rules. As noted previously in this preamble, the repeal and reformatting is necessary to accommodate new rules. Other minor technical changes and corrections have been made that do not affect the stringency or enforceability of the rules. Therefore, there will be no backsliding or lapse in the enforcement or effectiveness of the current requirements in 30 TAC Chapter 117.

SUBCHAPTER B: COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

The commission is adopting a new Subchapter B, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, with new emission control requirements for major industrial, commercial, or institutional (ICI) sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. This rulemaking is a part of the Dallas-Fort Worth eight-hour ozone attainment demonstration and the emission reductions associated with this rulemaking will help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward compliance with the eight-hour ozone NAAQS.

The new Subchapter B, Division 4 will require owners or operators of major ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area to reduce NO _X emissions from a wide variety of stationary sources. A major NO _X source in the Dallas-Fort Worth eight-hour ozone nonattainment area is any stationary source or group of sources located within a contiguous area and under common control that emits or has the potential to emit equal to or greater than 50 tons per year (tpy) of NO _X . The stationary source type categories controlled in the rulemaking include the following: ICI boilers and gas turbines; duct burners used in turbine exhaust ducts; process heaters and furnaces; stationary internal combustion engines; brick, ceramic, and lime kilns; metallurgical heat treating and reheat furnaces; lead smelting blast (cupola) and reverberatory furnaces; glass melting furnaces; fiberglass and mineral wool fiber melting furnaces; fiberglass and wool fiber curing ovens; heaters and ovens, and dryers used in organic solvent, printing ink, and ceramic tile, clay, and brick drying, and calcining and vitrifying; and incinerators. The emission specifications adopted for some of these source categories are consistent with the current emission specifications effective in this chapter for the Houston-Galveston-Brazoria ozone nonattainment area. New emission specifications are adopted for certain source categories in the Dallas-Fort Worth eight-hour ozone nonattainment area, for which there are currently no emission specifications established in Chapter 117 for any ozone nonattainment area. Source categories that are newly regulated under Chapter 117 include: brick and ceramic kilns; lead smelting blast (cupola) and reverberatory furnaces; heaters, ovens, and dryers; and glass, fiberglass, and mineral wool melting furnaces and curing ovens.

New Subchapter B, Division 4 also includes monitoring, testing, recordkeeping, reporting, and other requirements associated with the emission specifications necessary to ensure compliance with the emission specifications and to ensure the necessary NO _X emission reductions. Specific discussion associated with the emission specifications and other requirements in new Subchapter B, Division 4 is provided in the SECTION BY SECTION DISCUSSION section.

The commission estimates that this rule will result in approximately 8.40 tons per day (tpd) reduction of NO _X from major ICI sources in the Dallas-Fort Worth eight-hour ozone nonattainment area by March 1, 2009. An additional 0.48 tpd reductions will be achieved from major sources by March 1, 2010, for a total of approximately 8.88 tpd. The emission reductions from compliance with this rulemaking will reduce ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area and help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision that the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS. The new rules in Subchapter B, Division 4 are one step toward meeting the state's obligations under the FCAA.

Section 182(b)(2) and (f) of the FCAA require implementation of reasonably available control technology (RACT) for major sources of NO _X covered by the Alternative Controls Techniques (ACT) documents for ozone nonattainment areas classified as moderate and above. The previous Chapter 117 NO _X rules associated with the one-hour ozone NAAQS contain a specific section, §117.205, for RACT emission specifications for these unit types. These RACT requirements for the four-county Dallas-Fort Worth ozone nonattainment area are retained in the reformatted Chapter 117 and are incorporated in a new §117.205. For the Dallas-Fort Worth eight-hour ozone nonattainment area, the commission is not expanding the applicability of new §117.205 to the nine-county area. Furthermore, the new Subchapter B, Division 4 does not include an equivalent NO _X RACT section for the Dallas-Fort Worth eight-hour ozone nonattainment area. The emission specifications in new §117.410 that are necessary for the Dallas-Fort Worth eight-hour ozone attainment demonstration are equivalent or stricter NO _X emission specifications than would be required under RACT for all unit and industry types specified in the EPA ACT documents for those industries in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission therefore considers the FCAA NO _X RACT requirement fulfilled by the emission specifications for attainment demonstration in §117.410 for the Dallas-Fort Worth eight-hour ozone nonattainment area.

SUBCHAPTER C: COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

The commission is adopting a new Subchapter C, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, with new requirements for utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. New Subchapter C, Division 4 applies to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts used in an electric power generating system owned or operated by a municipality or a Public Utility Commission of Texas (PUC) -regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or an electric cooperative, municipality, river authority, or public utility located within the Dallas-Fort Worth eight-hour ozone nonattainment area. The rule establishes a unit-by-unit approach for compliance with the existing emission specifications for units subject to the rule. The rule also provides a new efficiency, or output-based, emission specification as an option for utility boilers. This new rule for electric generating units for the Dallas-Fort Worth eight-hour attainment demonstration retains the existing heat input-based emission specifications. The rule does not allow alternative system-wide emission specifications or system cap options as alternative means of compliance. However, based on comments received, the commission has revised the rule to allow a system-wide heat input average. The commission estimates that this rule, which has a compliance date of March 1, 2009, will result in approximately 0.4 tpd NO _X reductions from major utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area, based on 2009 future case modeling.

In addition, to satisfy RACT requirements for the five new counties, the existing RACT emission specifications for auxiliary steam boilers and stationary gas turbines from existing §117.105, applicable in the four-county Dallas-Fort Worth ozone nonattainment area, are adopted as emission specifications for attainment demonstration for the nine-county Dallas-Fort Worth eight-hour ozone nonattainment area. The commission is not changing these RACT emission specifications; however, under the adopted rule, owners or operators are not able to use the system cap or alternative system-wide emission specifications for compliance with the RACT emission specifications.

Specific discussion associated with the specifications and other requirements in new Subchapter C, Division 4 is provided in the SECTION BY SECTION DISCUSSION section of this preamble. The emission reduction requirements that result from this rulemaking will help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision that the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS. The new rules in Subchapter C, Division 4 are one step toward meeting the state's obligations under the FCAA.

SUBCHAPTER D: COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 2: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

The commission is adopting a new Subchapter D, Division 2, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources, with new requirements for minor stationary sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. The existing Subchapter D, Division 2, is reformatted as a new Subchapter D, Division 1, entitled Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources. This rule supports the Dallas-Fort Worth eight-hour ozone nonattainment area attainment demonstration by requiring a variety of stationary sources of NO _X emissions in the Dallas-Fort Worth eight-hour ozone nonattainment area to meet new emission specifications and other reductions of NO _X emissions. Because of the large amounts of NO _X reductions necessary to attain the NAAQS, all reasonable control strategies to achieve NO _X reductions must be pursued. A minor NO_X source in the Dallas-Fort Worth eight-hour ozone nonattainment area is any stationary source or group of sources located within a contiguous area and under common control that emits or has the potential to emit less than 50 tpy of NO _X . This rulemaking will require owners or operators of minor sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area to reduce NO _X emissions from affected stationary internal combustion engines. As proposed, the rule would have also applied to boilers, process heaters, and gas turbines at minor sources. However, as discussed elsewhere in this preamble, the commission has determined that boilers, process heaters, and gas turbines at minor NO _X sources in the Dallas-Fort Worth eight-hour ozone nonattainment area should not be included in the adopted rule. The commission estimates that the total NO_X emissions from minor sources with process heaters and gas turbines are not significant and the controls included in the proposed rule for these sources would not help further attainment for the area. While approximately 1.3 tpd of NO _X reductions might be achieved from implementing controls on boilers at minor sources in the Dallas-Fort Worth eight-hour ozone nonattainment area, implementing these controls prior to the 2010 attainment date would place a significant burden on many small businesses. Although these reductions might ultimately be achievable by 2011 or 2012, this timing would not help advance attainment by the attainment date. The rule, as proposed, would have regulated units at sites including small businesses and industries, hospitals, hotels, public and private office and administrative buildings, and school districts that were previously unregulated. Many of these small businesses, institutions, and other minor sources will likely be exempt from the adopted rule, at least with regard to minor source owners or operators of stationary boilers, process heaters, and gas turbines. Based on analysis of the available information, the commission estimates that the adopted rule will result in approximately 1.2 tpd in NO _X emission reductions by March 1, 2009, and an additional 1.7 tpd by March 1, 2010, for a total of 2.9 tpd reductions. For modeling purposes, these emission reductions are accounted for in the area source inventory.

SUBCHAPTER E: MULTI-REGION COMBUSTION CONTROL

DIVISION 2: CEMENT KILNS

On April 22, 2005, a settlement agreement was entered into by the TCEQ and Blue Skies Alliance, et al., to resolve a lawsuit brought by the Blue Skies Alliance, et al ., against the EPA (2004). The settlement agreement required the commission to conduct a study of technologies for controlling NO _X emissions from cement kilns, in consultation with the parties to the settlement. The report, entitled Assessment of NO_X Emissions Reduction Strategies for Cement Kilns--Ellis County: Final Report , was submitted to the TCEQ on July 14, 2006, and is available on the commission's Web site at www.tceq.state.tx.us/implementation/air/sip/BSA_settle.html .

The study evaluated the applicability, availability, and cost-effectiveness of potential NO _X control technologies for cement kilns located in the Dallas-Fort Worth eight-hour ozone nonattainment area that could provide additional NO _X reductions beyond the requirements of Chapter 117 in effect in 2006. The report primarily focused on three active or potential types of control technologies for cement kilns: selective catalytic reduction (SCR), selective non-catalytic reduction (SNCR), and low temperature oxidation (LoTOx). Based on the results of this study, the commission conducted modeling sensitivity studies for two levels of control to evaluate the potential ozone reduction benefit from possible cement kiln control strategies. The first control level modeling run was performed based on 35 - 50% control, and the second control level modeling run was performed based on 80 - 85% control.

After reviewing the final report of the control technology study, modeling sensitivity run results, and other available information, the commission has determined that the 35 - 50% control level is the most appropriate control level that can reasonably be in place by the 2009 ozone season for this rulemaking. This control level is based on using SNCR controls on cement kilns. SNCR control technology is applicable to both dry preheater-precalciner or precalciner kilns and long wet kilns. While SCR and LoTOx control technologies may be applicable to cement kilns, these control technologies are not as well established for cement kilns as SNCR control. These technologies have not yet been demonstrated on the types of cement kilns located in Ellis County.

To implement this control strategy, the commission is adopting a source cap approach to establish a maximum NO _X emission cap for each account. This approach provides flexibility for owners or operators to achieve the reductions modeled for this control strategy. A source cap allows an owner or operator to choose the most applicable and cost-effective control technology available to a particular kiln while still achieving the overall reductions modeled for the Dallas-Fort Worth eight-hour attainment demonstration. Owners or operators may use any applicable control technologies to achieve reductions for compliance with the source cap. In addition, the intent of the source cap approach is to establish a maximum cap on the total NO _X emissions from cement kilns at each account. As discussed elsewhere in this preamble, the commission has changed the calculation approach for the source cap. The source cap under the adopted rule is calculated based on a pound per ton of clinker emission factor for each type of kiln and the average annual production rate for the kilns for calendar years 2003, 2004, and 2005, plus one standard deviation of total production at an account. The provisions of the new rule will prohibit expanding the source cap based on new units installed after calendar year 2005. Before an increase in NO_X emissions from a change in operation from one unit or the installation of a new kiln could occur, a corresponding decrease in NO _X emissions will be required from another existing unit, unless the account's NO _X emissions were already sufficiently below the source cap.

Compliance with the source cap is determined on a 30-day rolling average basis. The 30-day rolling average basis for the source cap provides flexibility to account for the inherent variability in NO _X emissions from cement kiln operations. Owners or operators must demonstrate compliance with the source cap using new monitoring, testing, reporting, and recordkeeping requirements in the rule, as described elsewhere in this preamble. The commission estimates that this rule will result in approximately 9.69 tpd NO _X emission reductions.

DIVISION 3: WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

On April 19, 2000, the commission adopted rules, published in the May 5, 2000, issue of the Texas Register (25 TexReg 4101), that require water heaters, small boilers, and process heaters statewide to meet specific NO _X emission specifications. These rules were part of a SIP control strategy for attainment with the one-hour ozone NAAQS.

Under the previously adopted rules, manufacturers, distributors, retailers, and installers of natural gas-fired water heaters with a maximum rated capacity of no more than 75,000 British thermal units per hour (Btu/hr), designated as a Type 0 unit in the adopted rules, were required to meet the emission specifications in §117.465. Specifically, Type 0 units manufactured, distributed, sold, or installed on or after July 1, 2002, but no later than December 31, 2004, were required to meet a 40 nanogram per joule (ng/J) heat output limit. Type 0 units manufactured, distributed, sold, or installed on or after January 1, 2005, were required to meet a 10 ng/J heat output limit.

Type 0 units that meet the 40 ng/J emission standard have been developed and made available by manufacturers. However, in a rulemaking effective December 23, 2004, the commission proposed a one-year delay for conventional Type 0 water heaters with a capacity equal to or less than 50 gallons, and a two-year delay for conventional Type 0 water heaters with a capacity that exceeds 50 gallons, to meet the 10 ng/J emission standard. Subsequent to the initiation of the rulemaking proposal, the commission received a petition from the Gas Appliance Manufacturers Association (GAMA) on June 22, 2004, regarding the water heater rules. GAMA petitioned the commission to adopt a rule that would amend §117.465 to delay implementation of the 10 ng/J NO _X emission limit for some categories of gas water heaters and to provide an exclusion for two other specific categories of water heaters. For conventional water heaters with storage volumes of 50 gallons or less, the petitioner requested a delay in the implementation of the 10 ng/J NO _X emission limit from January 1, 2005, to January 1, 2006. For conventional water heaters with storage volumes greater than 50 gallons, the petitioner requested a delay in the implementation of the 10 ng/J NO _X emission limit from January 1, 2005, to January 1, 2007. Based on the comments received and uncertainties of equipment manufacturers' ability to meet the Type 0 emission standards, the commission adopted a rule revision to allow a two-year delay for all conventional Type 0 units.

During the 79th legislative session, the Texas Legislature adopted HB 965, requiring the commission to conduct a study to determine the technical and economic feasibility of regulating residential water heaters. According to HB 965, if the study indicated that regulating residential water heaters is technically or economically infeasible, the executive director shall recommend to the commission that the rules be repealed no later than December 31, 2006. Residential water heaters are currently regulated by 30 TAC Chapter 117, Subchapter D, Division 1. Section 117.465(b)(2) establishes a NO _X emission limit of 10 ng/J for residential natural gas-fired water heaters with a maximum rated capacity of 75,000 Btu/hr. Additionally, HB 965 specified that the study be completed by December 31, 2005. As part of the study, the commission surveyed residential water heater manufacturers to determine the practicality of implementing the 10 ng/J NO _X emission limit by the January 1, 2007, compliance date.

The commission is repealing and reformatting all of Chapter 117. In addition to the reformatting of existing Subchapter D, Division 1 in new Subchapter E, Division 3, this rulemaking repeals the current 10 ng/J NO _X emission standard for Type 0 water heaters in existing §117.465(b)(2) due to comments received and uncertainties in the water heater manufacturers' ability to produce water heaters compliant with the current rule.

In addition, the amendments to Chapter 117 delete the definitions of "Power-vent unit" and "Direct-vent unit." With the repeal of the 10 ng/J NO _X emission standard in existing §117.465(b)(2), the emission specifications for power-vent unit and direct-vent unit are duplicated in §117.465(b)(1) and (3). The commission retains the emission standard found in §117.465(b)(1) that requires all equipment manufacturers to comply with the current 40 ng/J NO _X emission specification.

Demonstrating Noninterference under Federal Clean Air Act, Section 110(l)

The commission provides the following information to clarify why the repeal of the emission specification in existing §117.465(b)(2) will not negatively impact the status of the state's attainment with the ozone NAAQS. EPA issued draft guidance on June 8, 2005, "Demonstrating Noninterference Under Section 110(l) of the Clean Air Act When Revising a State Implementation Plan." The guidance states (page 6) that ". . . areas have two options available to demonstrate noninterference for the affected pollutant(s)." The commission is using option one by identifying existing measures to show compliance with EPA's guidance: substitution of one measure by another with equivalent or greater emissions reduction/air quality benefits.

Background

On April 19, 2000, the commission adopted rules in Chapter 117 to regulate NO _X emissions from gas-fired residential water heaters statewide. These rules were part of the one-hour control strategy for the Houston-Galveston-Brazoria SIP and the Dallas-Fort Worth SIP to demonstrate attainment with the NAAQS for ozone. In November 2004, the commission adopted Early Action Compacts for the Austin and San Antonio near-nonattainment areas to assist those areas in compliance with the federal ozone standard. The commission adopted changes that delayed the January 1, 2005, emission standard compliance date to January 1, 2007, in order to provide manufacturers additional time to comply. The 79th Legislature in 2005 enacted HB 965 requiring the TCEQ to perform a study regarding the technical and economic feasibility of regulating residential water heaters.

HB 965 required the commission to conduct a survey to determine whether the residential water heater manufacturers could meet the 10 ng/J emission specification in the applicable regulations by the January 1, 2007, compliance date. Staff completed the technical and economic feasibility study in cooperation with industry and trade associations by December 31, 2005.

As part of the study, the commission was provided a list of seven manufacturers of natural gas-fired residential water heaters. Of the seven manufacturers, three indicated that they would not formally respond to the survey because they do not manufacture residential water heaters affected by the 10 ng/J NO _X emission standard in §117.465(b)(2). The four remaining water heater manufacturers indicated that they could not manufacture a residential natural gas-fired water heater compliant with the 10 ng/J NO _X emission limit by January 1, 2007.

As required by HB 965, the commission held a public hearing on the findings of the technical and economic feasibility study for residential water heaters on February 28, 2006. The requirement for reasonable notice and public hearing was satisfied through the hearing held on February 28, 2006, and the public comment period, which was held from January 30, 2006, to March 1, 2006. The purpose of the hearing was to accept written and oral comments on the water heater survey results and study. Written and oral comments were submitted by the Honorable Patrick B. Haggerty, State Representative from El Paso, District 78 (Representative Haggerty); Houston Regional Group of the Sierra Club (HSC); CPS Energy; ATMOS Energy; CenterPoint Energy; Texas Gas Service; GAMA; and American Gas Association. All commenters advocated the repeal of the 10 ng/J NO _X emission specification on natural gas-fired residential water heaters.

HB 965 also required emission reductions to offset the loss of SIP credits due to the rule repeal. The commission is using reductions from a currently effective rule that were not claimed for the Houston-Galveston-Brazoria one-hour ozone attainment demonstration to offset the 0.5 tpd shortfall in the Houston-Galveston-Brazoria area. Specifically, 30 TAC Chapter 117, Subchapter D, Division 2, was adopted in April 2000 and applies to minor NO _X sources in the Houston-Galveston-Brazoria area. While the rule is included in the Houston-Galveston-Brazoria SIP, specific reductions associated with the rule from sites that are not subject to the NO _X Mass Emission Cap and Trade (MECT) program were not claimed or modeled for the Houston-Galveston-Brazoria one-hour ozone attainment demonstration. The commission estimates that a minimum of 0.7 tpd NO _X reductions were achieved from these sources through implementation of the rule. This estimate is based only on gas-fired boilers subject to 30 TAC Chapter 117, Subchapter D, Division 2, that were not included in the MECT program. Therefore, the 0.7 tpd estimate is conservative because it does not include reductions from other sources subject to this rule that were also excluded from the MECT program.

The commission is using surplus reductions from the 5% IOP SIP submittal dated April 27, 2005, to offset the 0.5 tpd shortfall in the Dallas-Fort Worth four-county ozone nonattainment area. This SIP provided information and control measures to provide for a 5% IOP from the area's 2002 emissions baseline that are in addition to federal measures and state measures already approved by EPA. As shown in Table 1 of this preamble, the 5% IOP SIP contained an overall surplus of 0.68%, or 4.23 tpd NO _X reductions. Because the reductions exceeded the required 5%, the commission will use 0.5 tpd of reductions in NO _X emissions from the nine-county lean-burn and rich-burn engine rule to offset the shortfall. According to the 5% IOP SIP, this rule will achieve a 1.87 tpd NO _X reduction by June 15, 2007, which is sufficient to offset the 0.5 tpd shortfall. The reduction requirement for the 5% IOP SIP is based on total NO_X and VOC emission reduction percent combined; therefore, adjustment to the 5% IOP SIP should not be necessary.

Figure: 30 TAC Chapter 117--Preamble

Conclusion

Based upon all data presently before the commission, the commission has determined that there are sufficient credits in place to offset the shortfall from repealing the 10 ng/J emission specification for Type 0 water heaters. Furthermore, the replacement reductions identified by the commission in this rulemaking are achieved from combustion sources that are ground-level NO_X emission sources and will satisfy the requirement in HB 965 to use replacement reductions from the same category. Finally, this repeal only applies to the 10 ng/J emission specification for Type 0 water heaters. The 40 ng/J emission specification for Type 0 water heaters, as well as the emission limits for Type 1 and 2 water heaters and Type 1, 2, and 3 process heaters and small boilers, are still in effect and reductions are being achieved.

DIVISION 4: EAST TEXAS COMBUSTION

Point source NO_X emissions in Dallas-Fort Worth eight-hour ozone nonattainment area account for about one-eighth of the total Dallas-Fort Worth NO_X inventory. The majority of NO_X in the nonattainment area comes from on-road and non-road mobile sources, which are not directly regulated by the commission. Therefore, the commission has elected to pursue reductions in emissions from transported pollutants in order to make progress toward attainment with the eight-hour ozone NAAQS. The commission's emissions inventory, as well as initial information from studies being conducted by the TCEQ and Houston Advanced Research Center (HARC), indicates that stationary gas-fired engines in some attainment counties of the Northeast Texas area represent a significant source of NO _X emissions. The adopted new Subchapter E, Division 4 will require owners and operators of stationary, rich-burn gas-fired, reciprocating internal combustion engines, unless exempted, located in the specified counties in the Northeast Texas area to meet NO<"sub>X emission specifications and other requirements to reduce NO _X emissions and ozone transport into the Dallas-Fort Worth eight-hour ozone nonattainment area. Based on comments received, the commission has decided not to include stationary, lean-burn gas-fired, reciprocating internal combustion engines at this time. The commission may include lean-burn engines in the East Texas Combustion rule at a later date. The specific counties included in the applicability for this rulemaking include the following counties: Anderson, Brazos, Burleson, Camp, Cass, Cherokee, Franklin, Freestone, Gregg, Grimes, Harrison, Henderson, Hill, Hopkins, Hunt, Lee, Leon, Limestone, Madison, Marion, Morris, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, Shelby, Smith, Titus, Upshur, Van Zandt, and Wood Counties. Based on comments received, Bosque, Cooke, Grayson, Hood, Somervell, and Wise Counties have been removed from the applicability of the rule. The commission is not applying this rule to engines located in the Dallas-Fort Worth eight-hour ozone nonattainment area. Engines located in the Dallas-Fort Worth eight-hour nonattainment area are either currently regulated by equivalent or more stringent requirements under other divisions of Chapter 117 or regulated in separate divisions adopted in this rulemaking.

The commission conducted modeling sensitivity studies at control levels similar to this rule to all counties within or traversed by the 200 kilometer perimeter from the Dallas-Fort Worth eight-hour ozone nonattainment area, excluding the Dallas-Fort Worth nine-county area. Results of the initial sensitivity study, which estimated a NO _X reduction of 40.9 tpd, based on 2009 future case modeling, indicated the reductions realized by this rule would benefit the Dallas-Fort Worth area by reducing ozone an average of 0.2 to 0.3 parts per billion. As discussed elsewhere in this preamble, the adopted East Texas Combustion rule only applies to rich-burn engines 240 horsepower (hp) and larger. Based on the revised list of 33 counties considered for this rule, the commission estimates that implementation of this rule will result in an overall reduction of approximately 22.4 tpd in NO _X emissions in the Northeast Texas area by March 1, 2010. This rulemaking applies to engines in the point source inventory, as well as engines that are categorized in the area source inventory. Approximately 16.5 tpd of these reductions are from point source engines and approximately 5.9 tpd of these reductions are from area source engines. The commission estimates that the 22.4 tpd reductions in NO _X emissions in the 33 counties subject to the adopted rule will still benefit the Dallas-Fort Worth area by reducing ozone an average of approximately 0.2 parts per billion. While this rulemaking is a part of the Dallas-Fort Worth Attainment Demonstration SIP, the commission anticipates that the Tyler-Longview area (Northeast Texas Early Action Compact Area) in East Texas will also benefit from NO _X reductions achieved by this rule.

SECTION BY SECTION DISCUSSION

The commission repeals Chapter 117 in its entirety. A new Chapter 117, Control of Air Pollution from Nitrogen Compounds, is adopted that incorporates existing rule language from Chapter 117, additional new rule language for the Dallas-Fort Worth eight-hour attainment demonstration, and rule changes that implement HB 965, concerning residential water heaters.

Reformatting Chapter 117 has resulted in numerous changes in section numbering, cross-references, as well as section, division, and subchapter titles. Section-by-section discussion associated with the reformatting and renumbering of Chapter 117 is primarily limited to the new subchapters, divisions, and sections, and indicating the origin of the rule language from existing Chapter 117. Unless otherwise specified in this preamble, changes to section, division, and subchapter numbers and title cross-references are only to update the reference to the corresponding reformatting section numbers and new section, division, and subchapter titles. Such changes are non-substantive and will not be specifically discussed in this preamble.

Also associated with the reformatting of Chapter 117 are various stylistic non-substantive changes to update rule language to current Texas Register style and format requirements, as well as establish more consistency in the rules. Such changes include appropriate and consistent use of acronyms, section references, equation style and formatting, scientific units of measure, and certain terminology such as "that" and "which," "shall" and "must," and "specification" and "limit." References to Houston-Galveston ozone nonattainment area have been updated to Houston-Galveston-Brazoria ozone nonattainment area to be consistent with current terminology for the region. Certain equations previously written out in paragraph and sentence form are adopted as mathematical equations for consistency and to ensure clarity and proper calculation in accordance with the commission's intent. Such changes are non-substantive and generally are not specifically discussed in this preamble.

Some changes to existing rule language of Chapter 117 are necessary to make minor corrections to rule language and are discussed later in this preamble in the appropriate section discussion. Comments received regarding sections and rule language associated only with reformatting and minor stylistic changes were not considered and no changes were made based on such comments. Section by section discussion is presented in the order of the new section numbering order.

SUBCHAPTER A, DEFINITIONS

The commission adopts a new Chapter 117, Subchapter A, entitled Definitions, that incorporates the definitions in the existing Chapter 117, Subchapter A, relating to definitions.

Section 117.10, Definitions

The commission adopts a new §117.10 that incorporates the definitions in the existing §117.10, relating to definitions, with the following revisions. New §117.10(1) - (53) incorporate the definitions from existing §117.10(1) - (53), respectively. Specific changes to definitions are discussed as follows.

The commission revises §117.10(2), concerning applicable ozone nonattainment area. The commission moves the existing §117.10(2)(C), Houston/Galveston, to the new §117.10(2)(D) and revises the new §117.10(2)(D) to be Houston-Galveston-Brazoria ozone nonattainment area to be consistent with current terminology and other changes in this rulemaking. The commission adds the definition of Dallas-Fort Worth eight-hour ozone nonattainment area to the definition of applicable ozone nonattainment area in §117.10(2)(C). The new definition for the Dallas-Fort Worth eight-hour ozone nonattainment area includes Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant Counties. This change and subsequent changes to other definitions in this section to include Dallas-Fort Worth eight-hour ozone nonattainment area are necessary because the commission is adopting new rules for the Dallas-Fort Worth eight-hour ozone nonattainment area. The existing definition of Dallas-Fort Worth ozone nonattainment area will continue to apply only to Collin, Dallas, Denton, and Tarrant Counties.

The commission revises §117.10(14)(A), electric power generating system, to include systems that are owned or operated by an electric cooperative, municipality, river authority, public utility, or a PUC-regulated utility. This change more accurately reflects the definition of an electric power generating system and does not expand the definition. Based on comments received, independent power producers were removed from the proposed §117.10(14)(A) to avoid a potential expansion in the applicability. In addition, the commission adds "Dallas-Fort Worth eight-hour" to the list of ozone nonattainment areas included in the definition of electric power generating system in new §117.10(14)(A)(iii). Existing §117.10(14)(A)(iii), which includes "Houston-Galveston-Brazoria" in the list of ozone nonattainment areas, is incorporated into new §117.10(14)(A)(iv).

The commission revises the definition of emergency situation in §117.10(15)(A)(ii) to update the references to the Electric Reliability Council of Texas (ERCOT) Protocols, to the most recent published version of the ERCOT Protocols, April 25, 2006.

The commission changes large DFW system in §117.10(24) to large utility system to be consistent with Texas Register style and formatting requirements. In addition, the commission revises the definition in §117.10(24) to include systems located in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission revises the definition of major source in §117.10(29)(B) to include sources located in the Dallas-Fort Worth eight-hour ozone nonattainment area. In addition, Ellis and Parker Counties are removed from §117.10(29)(D) because these counties are classified as nonattainment and are included in the new §117.10(29)(B).

The commission revises the definition of parts per million by volume in §117.10(35) to include the equation that must be used to adjust pollutant concentrations to a specified oxygen (O ₂ ) correction basis. This change is necessary to ensure that all measured concentrations are corrected to the specified O ₂ correction basis, when required by an applicable rule, using a consistent methodology.

The commission changes plant-wide emission limit in §117.10(37) to plant-wide emission specification to be consistent with new section titles.

The commission changes small DFW system in §117.10(44) to small utility system to be consistent with Texas Register style and formatting requirements. In addition, the commission revises the definition in §117.10(44) to include the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission changes the term system-wide emission limit in §117.10(48) to system-wide emission specification to be consistent with new section titles.

The commission adopts several revisions to the definition of unit in existing §117.10(51). Adopted §117.10(51)(C) only incorporates the definition in existing §117.10(51)(C) to define unit when used in the new Subchapter D, Division 1, Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources. A new §117.10(51)(D) is adopted to define a unit reference to new §117.2110, relating to Emission Specifications for Eight-Hour Attainment Demonstration, to define unit when used in the new Subchapter D, Division 2, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources. New §117.10(51)(D) states that for the purposes of §117.2110, and each requirement of this chapter associated with §117.2110, a unit consists of any stationary internal combustion engine, as defined in §117.10, relating to definitions.

The proposed §117.10(51)(D) is adopted as §117.10(51)(E) to define unit for the purposes of new Subchapter E, Division 4, East Texas Combustion. New §117.10(51)(E) states that for the purposes of §117.3310, relating to emission specification for eight-hour attainment demonstration, and each requirement of this chapter associated with §117.3310, a unit consists of any stationary internal combustion engine, as defined in §117.10, relating to definitions.

The proposed §117.10(51)(E) is adopted as §117.10(51)(F) to define unit for the purposes of new Subchapter B, Division 4, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, and Subchapter C, Division 4, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources. The new §117.10(51)(F) specifies that for the purposes of new §117.410 and §117.1310, relating to emission specification for eight-hour attainment demonstration, and each requirement of this chapter associated with §117.410 and §117.1310, a unit consists of any boiler, process heater, stationary gas turbine, or stationary internal combustion engine, as defined in §117.10, relating to definitions, or any other stationary source of NO _X emissions at a major source, as defined in §117.10.

Finally, the commission revises the definition of utility boiler in existing §117.10(52). New §117.10(52) revises the definition to include equipment owned or operated by an electric cooperative, municipality, river authority, public utility, or PUC-regulated utility. This change is intended to clarify the definition and to be consistent with other changes in this rulemaking, but does not expand the applicability of the definition. Based on comments received, independent power producers were removed from the adopted §117.10(52) to avoid a potential expansion in the applicability.

SUBCHAPTER B, COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

The commission adopts a new Chapter 117, Subchapter B, entitled Combustion Control at Major Industrial, Commercial, and Institutional Sources in Ozone Nonattainment Areas, that incorporates the rule language in the existing Chapter 117, Subchapter B, Combustion at Major Sources, Division 3, Industrial, Commercial, and Institutional Combustion Sources in Ozone Nonattainment Areas. The structure of new Subchapter B is based on regional ozone nonattainment areas. Each new division applies only to a specific ozone nonattainment area. Rule language from the previous Subchapter B, Division 3 that is not applicable for the specific region is not included in the new division for that specific region. Unless otherwise specified in this preamble, such exclusions of rule language not applicable to the specific region are considered non-substantive changes and are not specifically discussed in the preamble.

In addition, the commission adopts a new Subchapter B, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, that includes new rule language and requirements associated with major industrial, commercial, and institutional sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. The new Subchapter B, Division 4 is adopted as a part of the commission's eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area.

DIVISION 1, BEAUMONT-PORT ARTHUR OZONE NONATTAINMENT AREA MAJOR SOURCES

The commission adopts a new Chapter 117, Subchapter B, Division 1, entitled Beaumont-Port Arthur Ozone Nonattainment Area Major Sources, that incorporates the rule language in the existing Chapter 117, Subchapter B, Division 3 applicable to major industrial, commercial, and institutional sources in the Beaumont-Port Arthur ozone nonattainment area.

Section 117.100, Applicability

The commission adopts a new §117.100 that incorporates the rule language in the existing §117.201, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.100(1) - (3) incorporates the applicability rule language in existing §117.201(1) - (3).

Section 117.103, Exemptions

The commission adopts a new §117.103 that incorporates the exemption rule language in the existing §117.203 applicable to the Beaumont-Port Arthur ozone nonattainment area. The commission adopts a new §117.103(a)(1) - (7), relating to general exemptions, that incorporates the exemptions in the existing §117.203(a)(1) - (7). New §117.103(a)(8) incorporates the exemption in existing §117.203(a)(8)(B) and new §117.103(a)(9) and (10) incorporate the exemptions in existing §117.203(a)(10) and (13).

In addition, the commission adopts a new §117.103(b) and (c) to incorporate exemptions from existing §117.205 and §117.206. This change consolidates the applicable exemptions for the Beaumont-Port Arthur ozone nonattainment area under a single section. The commission adopts a new §117.103(b)(1) - (5) consisting of the provisions in the existing §117.205(h)(1) - (5), concerning exemptions for RACT, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.103(b)(6) - (8) incorporates the exemptions in existing §117.205(h)(7) - (9), and new §117.103(b)(9) incorporates the exemption in existing §117.205(h)(10)(B). The commission adopts a new §117.103(c), relating to attainment demonstration exemptions, that incorporates the exemption in existing §117.206(g) and (g)(2). The exemption in existing §117.206(g)(1), for boilers or process heaters with a maximum rated capacity less than 40 million British thermal units per hour (MMBtu/hr), is redundant because the general exemption in new §117.103(a)(2) is identical.

Section 117.105, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.105 that incorporates rule language in existing §117.205, relating to emission specifications for RACT, applicable to the Beaumont-Port Arthur ozone nonattainment area.

The commission adopts a new §117.105(a) - (c) consisting of the provisions in the existing §117.205(a) - (c). In addition, the commission adopts a new equation in §117.105(b)(6) that incorporates the calculation for the NO _X emission limit for gas-fired boilers and process heaters using hydrogen-rich fuel in the existing §117.205(b)(6). The new equation in §117.105(b)(6) is identical in content to the existing equation in §117.205(b)(6). The new equation in §117.105(b)(6) presents the equation in a format consistent with other figures and equations in Chapter 117 and provides a written description of all the terms used in the equation.

The commission adopts a new §117.105(d) consisting of the provisions in existing §117.205(d) and (d)(2). New §117.105(e) - (g) incorporates the provisions in the existing §117.205(e) - (g). Exemptions applicable in the Beaumont-Port-Arthur ozone nonattainment area in existing §117.205(h) are incorporated in new §117.103. The commission adopts a new §117.105(h) consisting of the provisions in the existing §117.205(i) and (i)(1).

Section 117.110, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.110 that incorporates the rule language in existing §117.206, relating to emission specifications for attainment demonstrations, applicable to the Beaumont-Port Arthur ozone nonattainment area.

The commission adopts a new §117.110(a) that incorporates the NO_X emission specifications for the Beaumont-Port Arthur ozone nonattainment area in existing §117.206(a). The commission adopts a new §117.110(b), relating to NO _X averaging time, that incorporates the rule language in the existing §117.206(d)(1). New §117.110(b)(1) incorporates the requirements in existing §117.206(d)(1)(A), and new §117.110(b)(2) incorporates the requirements in existing §117.206(d)(1)(B).

The commission adopts a new §117.110(c), concerning related emissions, that incorporates the rule language in existing §117.206(e). New §117.110(c)(1) and (2) incorporate the carbon monoxide (CO) and ammonia emissions specifications in the existing §117.206(e)(1) and (2). New §117.110(c)(3) incorporates the provisions regarding correction of CO emissions in existing §117.206(e)(3) and (3)(B). The commission also adopts a new §117.110(c)(4) that incorporates the rule language regarding applicability of the CO emission specifications from existing §117.206(e)(4) and (4)(A). Finally, the commission adopts a new §117.110(d) that incorporates the rule language regarding compliance flexibility from the existing §117.206(f)(1) - (3).

Section 117.115, Alternative Plant-Wide Emission Specifications

The commission adopts a new §117.115 that incorporates the rule language in existing §117.207, relating to alternative plant-wide emission specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.115(a) - (f) incorporates the rule language in the existing §117.207(a) - (f), relating to alternative plant-wide emission specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area.

New §117.115(g) incorporates the rule language from existing §117.207(g). In addition, existing §117.207(g)(1) - (3) include required calculations written in paragraph form rather than in equation form. The commission is reformatting the calculations in a mathematical formula rather than the paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new formulas are identical in content to the existing required calculations in paragraph form. The new equation in §117.115(g)(1) incorporates the calculation for the allowable NO _X emission rate for each affected boiler and process heater in the existing §117.207(g)(1). The new equation in §117.115(g)(2) incorporates the calculation for the allowable NO _X emission rate for each affected stationary internal combustion engine in the existing §117.207(g)(2). The commission also adds new equations to §117.115(g)(3) that incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.207(g)(3). The new §117.115(g)(3) presents the equation for determining the plant-wide emission specification for stationary gas turbines from the required calculation in existing §117.207(g)(3). New §117.115(g)(3) also includes a new equation in §117.115(g)(3) that incorporates the existing equation for calculating the in-stack NO _X concentration term used in calculating the plant-wide emission specification.

Finally, the commission adopts a new §117.115(h) that incorporates the rule language from existing §117.207(h), and a new §117.115(i) that incorporates the rule language from existing §117.207(i) and (i)(1).

Section 117.123, Source Cap

The commission adopts a new §117.123 that incorporates the rule language in existing §117.223, relating to source cap, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.123(a) - (k) incorporate the rule language in existing §117.223(a) - (k). In addition, the commission adopts new equations in §117.123(b) that incorporate the equations in existing §117.223(b) to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new equations in §117.123(b) include only the information applicable to the Beaumont-Port Arthur ozone nonattainment area. The new equation in §117.123(b)(1) incorporates the equation for the rolling 30-day average emission cap in existing §117.223(b)(1). As discussed elsewhere in this preamble, variable "i" used in the equation for §117.123(b)(1) has been revised to be a lowercase "i" throughout the equation and terms to be consistent. The commission adopts a new equation in §117.123(b)(2) that incorporates the equation for the maximum daily emission cap in existing §117.223(b)(2).

For new §117.123(k), the commission replaces upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions)." This change is necessary to update the rule to current terminology used by the commission.

Section 117.125, Alternative Case Specific Specifications

The commission adopts a new §117.125 that incorporates the rule language in existing §117.221, relating to alternative case specific specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.125(a) and (b) incorporate the rule language in existing §117.221(a) and (b). In addition, new §117.125(a) omits the existing §117.221(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.130, Operating Requirements

The commission adopts a new §117.130 that incorporates the rule language in existing §117.208, relating to operating requirements, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.130(a) - (d) incorporate the rule language in existing §117.208(a) - (d). In addition, the commission is concurrently adopting a new §117.8140(b) that incorporates the engine testing requirements in the existing §117.208(d)(7). Therefore, the engine testing requirements in existing §117.208(d)(7) have been omitted from the new §117.130(d)(7) and replaced with a reference to the new §117.8140(b).

Section 117.135, Initial Demonstration of Compliance

The commission adopts a new §117.135 that incorporates the rule language in existing §117.211, relating to initial demonstration of compliance, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.135(a) - (d) incorporate the rule language in existing §117.211(a) - (d). The commission is concurrently adopting a new §117.8000 that incorporates the requirements in the existing §117.211(e). Therefore, the commission adopts a new §117.135(e) that replaces specific requirements from existing §117.211(e) with a reference to the new §117.8000.

In addition, while existing §117.211(a) and new §117.135(a) specify that units that inject urea or ammonia for NO _X control must be tested for ammonia emissions, existing §117.211(e) does not specify the methods to be used for the required ammonia initial demonstration of compliance. New §117.8000 includes a requirement that specifies the methods required for ammonia testing during the initial demonstration of compliance. Specific discussion related to this change is included in the section-by-section discussion associated with new §117.8000.

New §117.135(f) incorporates the rule language from existing §117.211(f), regarding initial demonstration of compliance for units operating with continuous emissions monitoring systems (CEMS) or predictive emissions monitoring systems (PEMS). Finally, the commission is concurrently adopting a new §117.8010 that incorporates the report content requirements in the existing §117.211(g). Therefore, new §117.135(g) omits the compliance stack reports content requirements and references new §117.8010.

Section 117.140, Continuous Demonstration of Compliance

The commission adopts a new §117.140 that incorporates the rule language in the existing §117.213, relating to continuous demonstration of compliance, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.140(a) incorporates the totalizing fuel flow meter requirements and alternative provisions from existing §117.213(a), (a)(1)(A), and (a)(2). New §117.140(b) incorporates the rule language from existing §117.213(b) concerning O₂ monitors. In addition, existing §117.213(b)(1)(B)(i) requires O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, and clause (ii) requires O ₂ monitors on process heaters greater than or equal to 200 MMBtu/hr except as provided in §117.213(f). Because existing §117.213(b)(1)(B)(i) and (ii) are overlapping requirements, the new §117.140(b)(1)(B) incorporates both existing §117.213(b)(1)(B)(i) and (ii) into a single requirement for O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, except as provided in subsection (f).

The commission adopts a new §117.140(c) incorporating the rule language from existing §117.213(c), regarding requirements for NO _X monitors, applicable to the Beaumont-Port Arthur ozone nonattainment area. In addition, the §117.113(f) reference in existing §117.213(c)(3)(C)(ii) is revised in new §117.140(c)(3)(C)(ii) to reference new §117.8110(b) because the applicable provisions in §117.113(f) are incorporated in new §117.8110.

The commission adopts a new §117.140(d), concerning CO monitoring requirements. The commission is concurrently adopting a new §117.8120 that incorporates the CO monitoring methods in the existing §117.213(d)(1) - (4). Therefore, new §117.140(d) omits the existing CO monitoring methods specified in §117.213(d)(1) - (4) and references new §117.8120.

The commission adopts a new §117.140(e), concerning requirements for CEMS. The commission is concurrently adopting a new §117.8100(a) that incorporates the general requirements for CEMS in the existing §117.213(e)(1) - (3), (5), and (6). Existing §117.213(e)(4) is a region-specific requirement applicable only in the Houston-Galveston-Brazoria ozone nonattainment area. Therefore, new §117.140(e) omits existing §117.213(e)(1) - (6) and references new §117.8100(a).

The commission adopts a new §117.140(f), concerning requirements for PEMS. New §117.140(f)(1) incorporates rule language from existing §117.213(f)(1). The commission is concurrently adopting a new §117.8100(b) that incorporates the general requirements for PEMS in the existing §117.213(f)(2) - (7). Therefore, new §117.140(f) omits existing §117.213(f)(2) - (7) and new §117.140(f)(2) references new §117.8100(b).

The commission adopts a new §117.140(g) concerning testing requirements for stationary gas engines. The commission is concurrently adopting a new §117.8140(a) that incorporates the engine testing requirements in existing §117.213(g)(1). Therefore, new §117.140(g) omits existing §117.213(g)(1) and references new §117.8140(a). In addition, existing §117.213(g)(2) requires that engines that use a chemical reagent for reduction of NO _X must be monitored for NO _X in accordance with existing §117.213(c)(1)(E) and must comply with applicable requirements for CEMS and PEMS. Existing §117.213(c)(1)(E) and new §117.140(c)(1)(E) require that the owner or operator of any unit that uses a chemical reagent for NO _X control install, calibrate, maintain, and operate a CEMS or PEMS to monitor NO _X . Also, the applicable requirements for CEMS or PEMS in existing §117.213(e) or (f), or new §117.140(e) or (f) automatically apply to any CEMS or PEMS required by the section. Therefore, because the existing §117.213(g)(2) is redundant, the commission is not incorporating the rule language in existing §117.213(g)(2) into new §117.140(g).

Finally, the commission adopts new §117.140(h) - (m) that incorporate the rule language from existing §117.213(h) - (m) applicable to the Beaumont-Port Arthur ozone nonattainment area.

Section 117.145, Notification, Recordkeeping, and Reporting Requirements

The commission adopts new §117.145 that incorporates the rule language in existing §117.219, concerning notification, recordkeeping, and reporting. New §117.145(a) - (f) incorporate the rule language from existing §117.219(a) - (f) requirements applicable to the Beaumont-Port Arthur ozone nonattainment area. In addition, for new §117.145(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to 30 TAC §101.222 and the change is necessary to clarify new §117.145(a).

Section 117.150, Initial Control Plan Procedures

The commission adopts new §117.150 that incorporates the rule language in existing §117.209, concerning initial control plan procedures applicable to the Beaumont-Port Arthur ozone nonattainment area.

Section 117.152, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.152 that incorporates the requirements in the existing §117.215, relating to final control plan procedures for RACT, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.152(a) - (c) incorporates the provisions in the existing §117.215(a) - (c). New §117.152(a)(2)(A) and (B) incorporate the rule language from existing §117.215(a)(2)(A) and (B). New §117.152(a)(2)(C) incorporates the rule language from existing §117.215(a)(2)(D), and new §117.152(a)(2)(D) incorporates the rule language from existing §117.215(a)(2)(C). New §117.152(a)(2)(E) incorporates the rule language from existing §117.215(a)(2)(E). In addition, for new §117.152(a)(6)(B), concerning the information required in the final control plan for gas turbines with a megawatt (MW) rating less than 10 MW, the commission is changing the word "ten" to the numeral "10.0" because this is the appropriate exemption MW rating from existing §117.205(h)(7) and new §117.103(b)(6).

New §117.152 does not include existing §117.215(d), concerning the requirement to submit the control plan electronically and on hard copy using forms provided by the executive director. Existing §117.215 and new §117.152 specify the content requirements for the control plans. Therefore, a mandatory format for the control plan information is not necessary. Finally, new §117.152(d) incorporates rule language in existing §117.215(e).

Section 117.154, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.154 that incorporates the rule language in existing §117.216, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.154(a) incorporates the rule language in existing §117.216(a). New §117.154(a)(1)(A) consists of the provisions in existing §117.216(a)(1)(A). New §117.154(a)(1)(B) consists of the provisions in existing §117.216(a)(1)(D). New §117.154(a)(1)(C) and (D) consist of the provisions in existing §117.216(a)(1)(B) and (C), respectively. The commission adopts a new §117.154(a)(2) - (5) that incorporate the rule language from existing §117.216(a)(2) - (5). The commission also adopts a new §117.154(b) and (c) that incorporate the rule language in existing §117.216(b) and (c), respectively. In addition, new §117.154(b)(2)(A) and (B) exclude the references to new §117.123(k) or (l) because there is no heat input information specified in these subsections in either the existing §117.223 or new §117.123.

Section 117.156, Revision of Final Control Plan

The commission adopts a new §117.156 that incorporates the rule language in existing §117.217, concerning revisions of final control plans.

DIVISION 2, DALLAS-FORT WORTH OZONE NONATTAINMENT AREA MAJOR SOURCES

The commission adopts a new Chapter 117, Subchapter B, Division 2, entitled Dallas-Fort Worth Ozone Nonattainment Area Major Sources, that incorporates the rule language in the existing Chapter 117, Subchapter B, Division 3 applicable to major industrial, commercial, and institutional sources in the Dallas-Fort Worth ozone nonattainment area.

Section 117.200, Applicability

The commission adopts a new §117.200 that incorporates the applicability rule language in existing §117.201 applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.200(a) incorporates the applicability rule language in existing §117.201(1) - (3). In addition, the commission adopts a new §117.200(b) specifying that Chapter 117, Subchapter B, Division 2 will no longer apply to any units that are subject to the emission specifications in new §117.410 and located at any major stationary source of NO_X within Collin, Dallas, Denton, and Tarrant Counties after the compliance dates in new §117.9030. The emissions specifications in §117.410 and all other associated requirements in the new Subchapter B, Division 4, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, will supersede the requirements of Subchapter B, Division 2. Therefore, the commission adopts new §117.200(b) to avoid overlapping requirements from the two separate divisions.

Section 117.203, Exemptions

The commission adopts a new §117.203, relating to general exemptions, that incorporates the exemptions in the existing §117.203 applicable to the Dallas-Fort Worth ozone nonattainment area. The commission adopts a new §117.203(a), relating to general exemptions, that incorporates the exemptions in the existing §117.203(a). New §117.203(a)(1) - (7) incorporate the rule language in existing §117.203(a)(1) - (7). New §117.203(a)(8) incorporates the exemption in existing §117.203(a)(8)(B). New §117.203(a)(9) incorporates the exemption in existing §117.203(a)(10).

In addition, the commission adopts a new §117.203(b) and (c) to incorporate exemptions from existing §117.205 and §117.206. This change consolidates the applicable exemptions for the Dallas-Fort Worth ozone nonattainment area under a single section. New §117.203(b)(1) - (9) incorporates the exemptions in the existing §117.205(h)(1) - (9), concerning exemptions for RACT, applicable to the Dallas-Fort Worth ozone nonattainment area. The commission adopts a new §117.203(b)(10) consisting of the provisions in the existing §117.205(h)(10)(B).

The commission adopts a new §117.203(c), relating to attainment demonstration exemptions, that incorporates the exemptions in existing §117.206(g)(2) applicable to the Dallas-Fort Worth ozone nonattainment area. The exemption in existing §117.206(g)(1), for boilers or process heaters with a maximum rated capacity less than 40 MMBtu/hr, is redundant because the general exemption in new §117.203(a)(2) is identical.

Section 117.205, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.205 that incorporates rule language in existing §117.205, relating to emission specifications for RACT, applicable to the Dallas-Fort Worth ozone nonattainment area. The commission adopts a new §117.205(a) - (c) consisting of the provisions in the existing §117.205(a) - (c). In addition, the language regarding initial control plans in existing §117.205(a)(1)(B) is omitted in the new §117.205(a)(1)(B) because the requirement for initial control plans was not applicable in the Dallas-Fort Worth ozone nonattainment area.

Also, the commission adopts a new equation in §117.205(b)(6) that incorporates the calculation for the NO _X emission limit for gas-fired boilers and process heaters using hydrogen-rich fuel in the existing §117.205(b)(6). The new equation in §117.205(b)(6) is identical in content to the existing equation in existing §117.205(b)(6). The new §117.205(b)(6) presents the equation in a format consistent with other figures in Chapter 117 and provides a written description of all the terms used in the equation.

The commission adopts a new §117.205(d) consisting of the rule language in existing §117.205(d) and (d)(2). New §117.205(e) and (f) incorporate the rule language in existing §117.205(f) and (g). As previously indicated in this preamble, the exemptions in existing §117.205(h) applicable to the Dallas-Fort Worth ozone nonattainment area are incorporated in new §117.203(b).

Section 117.210, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.210 that incorporates the rule language in the existing §117.206, relating to emission specifications for attainment demonstration, applicable to the Dallas-Fort Worth ozone nonattainment area.

The commission adopts a new §117.210(a), relating to NO _X emission specifications, that incorporates the specifications in existing §117.206(b). New §117.210(a)(1) and (2) incorporate the emission specifications from existing §117.206(b)(1) and (2). The emission specifications for stationary gas-fired internal combustion engines in existing §117.206(b)(3) are incorporated in new Subchapter B, Division 4, §117.410(a). These emission specifications are applicable to the nine-county Dallas-Fort Worth eight-hour ozone nonattainment area as a part of the commission's IOP demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area. Because the emission specifications in existing §117.206(b)(3) apply to the Dallas-Fort Worth eight-hour ozone nonattainment area, new Subchapter B, Division 4 is the most appropriate location for the emission specifications.

The commission adopts a new §117.210(b), relating to NO _X averaging time, that incorporates the rule language in existing §117.206(d)(1). New §117.210(b)(1) incorporates the requirements in existing §117.206(d)(1)(A), and new §117.210(b)(2) incorporates the requirements in existing §117.206(d)(1)(B). The commission adopts a new §117.210(c), concerning related emissions, that incorporates the rule language in existing §117.206(e). New §117.210(c)(1) and (2) incorporate the CO and ammonia emissions specifications in the existing §117.206(e)(1) and (2). New §117.210(c)(3) incorporates the provisions regarding correction of CO emissions in existing §117.206(e)(3) and (3)(B). The commission also adopts a new §117.210(c)(4) that incorporates the rule language regarding applicability of the CO emission specifications from existing §117.206(e)(4) and (4)(A). Finally, the commission adopts a new §117.210(d) that incorporates the rule language regarding compliance flexibility from the existing §117.206(f)(1) - (3). As previously indicated in this preamble, the exemptions in existing §117.206(g) applicable to the Dallas-Fort Worth ozone nonattainment area are incorporated in new §117.203(c).

Section 117.215, Alternative Plant-Wide Emission Specifications

The commission adopts a new §117.215 that incorporates the rule language in existing §117.207, relating to alternative plant-wide emission specifications, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.215(a) - (f) incorporate the rule language in existing §117.207(a) - (f).

New §117.215(g) incorporates the rule language from existing §117.207(g). In addition, existing §117.207(g)(1) - (3) include required calculations written in paragraph form rather than in equation form. The commission is reformatting the calculations in a mathematical formula rather than paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new formulas are identical in content to the existing required calculations in paragraph form. The new equation in §117.215(g)(1) incorporates the calculation for the allowable NO _X emission rate for each affected boiler and process heater in the existing §117.207(g)(1). The new equation in §117.215(g)(2) incorporates the calculation for the allowable NO _X emission rate for each affected stationary internal combustion engine in the existing §117.207(g)(2). The commission also adds new equations to §117.215(g)(3) that incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.207(g)(3). The new §117.215(g)(3) presents the equation for determining the plant-wide emission specification for stationary gas turbines from the required calculation in existing §117.207(g)(3). New §117.215(g)(3) also includes a new equation in §117.215(g)(3) that incorporates the existing equation for calculating the in-stack NO _X concentration term used in calculating the plant-wide emission specification.

Finally, the commission adopts a new §117.215(h) that incorporates the rule language from existing §117.207(h), and a new §117.215(i) that incorporates the rule language from existing §117.207(i) and (i)(2).

Section 117.223, Source Cap

The commission adopts a new §117.223 that incorporates the rule language in the existing §117.223, relating to source cap, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.223(a) - (k) incorporate the rule language in existing §117.223(a) - (k). In addition, the commission adopts new equations in new §117.223(b) that incorporate the equations in existing §117.223(b) to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new equations in §117.223 include only the information applicable to the Dallas-Fort Worth ozone nonattainment area. The new equation in §117.223(b)(1) incorporates the equation for the rolling 30-day average emission cap in the existing §117.223(b)(1). As discussed elsewhere in this preamble, variable "i" used in the equations for new §117.223(b)(1) and (2) has been revised to be a lowercase "i" throughout the equations and terms to be consistent. The new equation in §117.223(b)(2) incorporates the equation for the rolling 30-day average NO _X emission cap in the existing §117.223(b)(2).

In addition, the commission revises the language regarding initial control plans in new §117.223(i) and (j). As discussed later in this preamble, the commission is not adopting a section for the Dallas-Fort Worth ozone nonattainment area that includes the requirements for initial control plans from existing §117.209. Therefore, the commission changes the language in the new §117.223(i) and (j) to reference final control plans for RACT instead of initial control plans.

Finally, for new §117.223(k), the commission replaces upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions)." This change is necessary to update the rule to current terminology used by the commission.

Section 117.225, Alternative Case Specific Specifications

The commission adopts a new §117.225 that incorporates the rule language in the existing §117.221, relating to alternative case specific specifications, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.225(a) and (b) incorporate the rule language in the existing §117.221(a) and (b). In addition, new §117.225(a) omits the existing §117.221(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.230, Operating Requirements

The commission adopts a new §117.230 that incorporates the rule language in existing §117.208, relating to operating requirements, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.230(a) - (d) incorporate the rule language in existing §117.208(a) - (d). In addition, the commission is concurrently adopting a new §117.8140(b) that incorporates the engine testing requirements in existing §117.208(d)(7). Therefore, the engine testing requirements in existing §117.208(d)(7) have been omitted from new §117.230(d)(7) and replaced with a reference to new §117.8140(b).

Section 117.235, Initial Demonstration of Compliance

The commission adopts a new §117.235 that incorporates the rule language in existing §117.211, relating to initial demonstration of compliance, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.235(a) - (d) incorporate the rule language in existing §117.211(a) - (d). The commission is concurrently adopting a new §117.8000 that incorporates the requirements in the existing §117.211(e). Therefore, the commission adopts a new §117.235(e) that replaces specific requirements from existing §117.211(e) with a reference to new §117.8000. In addition, while existing §117.211(a) and new §117.235(a) specify that units that inject urea or ammonia for NO _X control must be tested for ammonia emissions, existing §117.211(e) does not specify the methods to be used for the required ammonia initial demonstration of compliance. New §117.8000 includes a requirement that specifies the methods required for ammonia testing during the initial demonstration of compliance. Specific discussion related to this change is included in the section-by-section discussion associated with new §117.8000.

New §117.235(f) incorporates the rule language from existing §117.211(f), regarding initial demonstration of compliance for units operating with CEMS or PEMS. Finally, the commission is concurrently adopting a new §117.8010 that incorporates the report content requirements in the existing §117.211(g). Therefore, the new §117.235(g) omits the compliance stack reports content requirements and references new §117.8010.

Section 117.240, Continuous Demonstration of Compliance

The commission adopts a new §117.240 that incorporates the rule language in existing §117.213, relating to continuous demonstration of compliance, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.240(a) incorporates the totalizing fuel flow meter requirements and alternative provisions from existing §117.213(a), (a)(1)(A), and (a)(2). New §117.240(b) incorporates the rule language from existing §117.213(b) concerning O₂ monitors. In addition, existing §117.213(b)(1)(B)(i) requires O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, and clause (ii) requires O ₂ monitors on process heaters greater than or equal to 200 MMBtu/hr except as provided in §117.213(f). Because existing §117.213(b)(1)(B)(i) and (ii) are overlapping requirements, the new §117.240(b)(1)(B) incorporates both existing §117.213(b)(1)(B)(i) and (ii) into a single requirement for O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, except as provided in subsection (f).

The commission adopts a new §117.240(c) incorporating the rule language from existing §117.213(c), regarding requirements for NO _X monitors, applicable to the Dallas-Fort Worth ozone nonattainment area. In addition, the reference in existing §117.213(c)(3)(C)(ii) to §117.113(f) is revised in new §117.240(c)(3)(C)(ii) to reference new §117.8110(b) because the applicable provision in §117.113(f) is incorporated in new §117.8110.

The commission adopts a new §117.240(d), concerning CO monitoring requirements. The commission is concurrently adopting a new §117.8120 that incorporates the CO monitoring methods in the existing §117.213(d)(1) - (4). Therefore, the new §117.240(d) omits the existing CO monitoring methods specified in §117.213(d)(1) - (4) and references new §117.8120.

The commission adopts a new §117.240(e), concerning requirements for CEMS. The commission is concurrently adopting a new §117.8100(a) that incorporates the general requirements for CEMS in the existing §117.213(e)(1) - (3), (5), and (6). Existing §117.213(e)(4) is a region-specific requirement applicable only in the Houston-Galveston-Brazoria ozone nonattainment area. Therefore, the new §117.240(e) omits existing §117.213(e)(1) - (6) and references new §117.8100(a).

The commission adopts a new §117.240(f), concerning requirements for PEMS. New §117.240(f)(1) incorporates rule language from existing §117.213(f)(1). The commission is concurrently adopting a new §117.8100(b) that incorporates the general requirements for PEMS in the existing §117.213(f)(2) - (7). Therefore, the new §117.240(f) omits existing §117.213(f)(2) - (7) and new §117.240(f)(2) references new §117.8100(b).

The commission adopts a new §117.240(g) concerning testing requirements for stationary gas engines. The commission is concurrently adopting a new §117.8140(a) that incorporates the engine testing requirements in existing §117.213(g)(1). Therefore, the new §117.240(g) omits existing §117.213(g)(1) and references new §117.8140(a). In addition, existing §117.213(g)(2) requires that engines that use a chemical reagent for reduction of NO_X must be monitored for NO _X in accordance with existing §117.213(c)(1)(E) and must comply with applicable requirements for CEMS and PEMS. Existing §117.213(c)(1)(E) and new §117.240(c)(1)(E) require that the owner or operator of any unit that uses a chemical reagent for NO _X control install, calibrate, maintain, and operate a CEMS or PEMS to monitor NO _X . Also, the applicable requirements for CEMS or PEMS in existing §117.213(e) or (f), or new §117.240(e) or (f) automatically apply to any CEMS or PEMS required by the section. Therefore, because the existing §117.213(g)(2) is redundant, the commission is not incorporating §117.213(g)(2) into the new §117.240(g).

Finally, the commission adopts new §117.240(h) - (m) that incorporate the rule language from existing §117.213(h) - (m) applicable to the Dallas-Fort Worth ozone nonattainment area.

Section 117.245, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.245 that incorporates the rule language in the existing §117.219, relating to notification, recordkeeping, and reporting requirements. New §117.245(a) - (f) incorporate the rule language from existing §117.219(a) - (f) requirements applicable to the Dallas-Fort Worth ozone nonattainment area. In addition, for new §117.245(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.245(a).

Section 117.252, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.252 that incorporates the rule language in the existing §117.215, relating to final control plan procedures for RACT, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.252(a) - (c) incorporates the provisions in the existing §117.215(a) - (c). New §117.252(a)(2)(A) and (B) incorporate the rule language from existing §117.215(a)(2)(A) and (B). New §117.252(a)(2)(C) incorporates the rule language from existing §117.215(a)(2)(D), and new §117.252(a)(2)(D) incorporates the rule language from existing §117.215(a)(2)(C). New §117.252(a)(2)(E) incorporates the rule language from existing §117.215(a)(2)(E). In addition, for new §117.252(a)(6)(B), concerning the information required in the final control plan for gas turbines with a MW rating less than 10 MW, the commission is changing the word "ten" to the numeral "10.0" because this is the appropriate exemption MW rating from existing §117.205(h)(7) and new §117.203(b)(7). As discussed elsewhere in this preamble, the use of the numeral "10.0" will ensure consistent enforcement of the rule.

New §117.252 does not include existing 117.215(d), concerning the requirement to submit the control plan electronically and on hard copy using forms provided by the executive director. Existing §117.215 and new §117.252 specify the content requirements for the control plans. Therefore, a mandatory format for the control plan information is not necessary. New §117.252(d) incorporates the rule language in existing §117.215(e).

In addition, the commission is not adopting a section corresponding to the existing §117.209, concerning initial control plan procedures for RACT, for the new Subchapter B, Division 2, Dallas-Fort Worth Ozone Nonattainment Area Major Sources. The requirement in §117.209 to submit an initial control plan was applicable only to the Beaumont-Port Arthur and Houston-Galveston-Brazoria ozone nonattainment areas.

Section 117.254, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.254 that incorporates the rule language in existing §117.216, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.254(a) incorporates the rule language in existing §117.216(a). New §117.254(a)(1)(A) consists of the provisions in existing §117.216(a)(1)(A). New §117.254(a)(1)(B) consists of the provisions in existing §117.216(a)(1)(D). New §117.254(a)(1)(C) and (D) consist of the provisions in existing §117.216(a)(1)(B) and (C), respectively.

The commission adopts new §117.254(a)(2) - (5) that incorporate the rule language from existing §117.216(a)(2) - (5). New §117.254(b) and (c) incorporate the rule language in existing §117.216(b) and (c), relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Dallas-Fort Worth ozone nonattainment area. In addition, new §117.254(b)(2)(A) and (B) exclude the references to new §117.223(k) or (l) because there is no heat input information specified in these subsections in either the existing §117.223 or new §117.223.

Section 117.256, Revision of Final Control Plan

The commission adopts a new §117.256 that incorporates the rule language in existing §117.217, concerning revisions of final control plans.

DIVISION 3, HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA MAJOR SOURCES

The commission adopts a new Chapter 117, Subchapter B, Division 3, entitled Houston-Galveston-Brazoria Eight-Hour Ozone Nonattainment Area Major Sources, that incorporates the rule language in the existing Chapter 117, Subchapter B, Division 3 applicable to major industrial, commercial, and institutional sources in the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.300, Applicability

The commission adopts a new §117.300 that incorporates the applicability rule language in the existing §117.201 applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.303, Exemptions

The commission adopts a new §117.303 that incorporates the exemptions in the existing §117.203 and §117.205 applicable to the Houston-Galveston-Brazoria ozone nonattainment area. The new §117.303 consolidates the exemptions applicable to the Houston-Galveston-Brazoria ozone nonattainment area under a single section. New §117.303(a), concerning general exemptions, incorporates exemptions in existing §117.203(a)(1) - (9), (11), and (12). In addition, the provision in existing §117.203(b), regarding revocation of exemptions in existing §117.203(a)(1), (2), (7), and (8), is merged with the applicable exemptions for clarity. New §117.303(a)(1) incorporates the exemption in the existing §117.203(a)(1) and the revocation of exemption language from §117.203(b). New §117.303(a)(2) incorporates the exemptions in the existing §117.203(a)(2) and the revocation of exemption language from §117.203(b). New §117.303(a)(3) - (6) incorporate the exemptions in the existing §117.203(a)(3) - (6).

The commission adopts a new §117.303(a)(7) that incorporates the exemption in the existing §117.203(a)(7) and the revocation of exemption language from §117.203(b). New §117.303(a)(8) incorporates the exemptions in the existing §117.203(a)(8)(A) and the revocation of exemption language from §117.203(b). New §117.303(a)(9) incorporates the exemptions in existing §117.203(a)(9). New §117.303(a)(10) and (11) incorporate the exemptions in the existing §117.203(a)(11) and (12), respectively. Finally, the commission adopts new §117.303(b)(1) - (10) that incorporate the exemptions associated with RACT in the existing §117.205(h)(1) - (10)(A).

Section 117.305, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.305 that incorporates the specifications in the existing §117.205, relating to emission specifications for RACT, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

The commission adopts a new §117.305(a) - (c) consisting of the provisions in the existing §117.205(a) - (c). In addition, the commission adopts a new equation in §117.305(b)(6) that incorporates the calculation for the NO _X emission limit for gas-fired boilers and process heaters using hydrogen-rich fuel in the existing §117.205(b)(6). The new equation in §117.305(b)(6) is identical in content to the existing equation in existing §117.205(b)(6). The new §117.305(b)(6) presents the equation in a format consistent with other figures in Chapter 117 and provides a written description of all the terms used in the equation.

The commission adopts a new §117.305(d) consisting of the rule language in the existing §117.205(d) and (d)(1). New §117.305(e) and (f) incorporate the rule language in existing §117.205(f) and (g). New §117.305(g) incorporates the rule language in existing §117.205(i) and (i)(2).

Section 117.310, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.310 that incorporates the specifications in the existing §117.206, relating to emission specifications for attainment demonstrations, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

The commission adopts a new §117.310(a) that incorporates the emission specifications in the existing §117.206(c). The catchline for subsection (a) is also changed to "Emission specifications for the Mass Emission Cap and Trade Program" to more accurately reflect the purpose of the emission specifications in combination with the MECT Program in Chapter 101, Subchapter H, Division 3. The commission adopts a new §117.310(a)(9)(D) and (E) that incorporate and reformat the specifications for diesel engines from the existing §117.206(c)(9)(D). New §117.310(a)(9)(D) includes the emission specification from existing §117.206(c)(9)(D)(i) and new §117.310(a)(9)(E) includes the emissions specifications from the existing §117.206(c)(9)(D)(ii).

The commission adopts a new §117.310(b) that incorporates the rule language regarding NO _X averaging time in the existing §117.206(d)(2).

The commission adopts a new §117.310(c), concerning related emissions, that incorporates the rule language in existing §117.206(e) applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.310(c)(1) - (3) incorporate the rule language in existing §117.206(e)(1) - (3). New §117.310(c)(4)(A) and (B) incorporate the rule language in the existing §117.206(e)(4) and (4)(B) and (C), concerning the applicability of the CO emission specifications. In addition, for new §117.310(c)(2), the commission changes the emissions specification for ammonia from the word "ten" to the numeral "10." Consistent with EPA guidance, the commission normally enforces emission test and monitoring results to the same significant figures as the emission specifications. Using the numeral "10" for the ammonia emission specification will ensure consistent enforcement of the emission specification.

The commission adopts a new §117.310(d) that incorporates the rule language in existing §117.206(f), relating to compliance flexibility. New §117.310(d)(1) - (3) incorporate the rule language from existing §117.206(f)(2) - (4).

The commission adopts a new §117.310(e) that incorporates the rule language in existing §117.206(h), relating to prohibition of circumvention. Finally, new §117.310(f) incorporates the rule language in existing §117.206(i), relating to operating restrictions.

Section 117.315, Alternative Plant-Wide Emission Specifications

The commission adopts a new §117.315 that incorporates the rule language in existing §117.207, relating to alternative plant-wide emission specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

New §117.315(a) - (f) incorporate the rule language in existing §117.207(a) - (f), relating to compliance with plant-wide emission specifications.

New §117.315(g) incorporates the rule language from existing §117.207(g). In addition, existing §117.207(g)(1) - (3) include required calculations written in paragraph form rather than in equation form. The commission has reformatted the calculations in a mathematical formula rather than the paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The mathematical formulas are identical in content to the existing required calculations in paragraph form. The new equation in §117.315(g)(1) incorporates the calculation for the allowable NO _X emission rate for each affected boiler and process heater in the existing §117.207(g)(1). The new equation in §117.315(g)(2) incorporates the calculation for the allowable NO _X emission rate for each affected stationary internal combustion engine in the existing §117.207(g)(2). The commission also adds new equations to §117.315(g)(3) that incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.207(g)(3). The new §117.315(g)(3) presents the equation for determining the plant-wide emission specification for stationary gas turbines from the required calculation in existing §117.207(g)(3). New §117.315(g)(3) also includes a new equation in §117.315(g)(3) that incorporates the existing equation for calculating the in-stack NO _X concentration term used in calculating the plant-wide emission specification.

The commission adopts a new §117.315(h) that incorporates the rule language in the existing §117.207(h), relating to gas-fired boilers or process heaters using fuel that contains more than 50% hydrogen by volume. New §117.315(i) that incorporates the rule language in existing §117.207(j), concerning applicability of the section after the compliance dates for emission specifications for attainment demonstration applicable in the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.320, System Cap

The commission adopts a new §117.320 that incorporates the rule language in the existing §117.210, concerning system cap requirements for electric generation facilities in the Houston-Galveston-Brazoria ozone nonattainment area. New §117.320(a) - (k) incorporate the rule language in existing §117.210(a) - (k).

Also, for new §117.320(b), the commission is revising the language in existing §117.210(b) that specifies "Each EGF that is subject to the NO _X emission rates of §117.206 . . .." New §117.320(b) specifies "Each EGF that is subject to §117.310 . . .." While compliance with the emission specifications in existing §117.206(c) is achieved through the MECT Program and an individual unit may not necessarily be required to meet the applicable emission specification in §117.206(c), an electric generating facility (EGF) subject to existing §117.206(c) is still required to comply with the system cap in existing §117.210. This change for new §117.320(b) will clarify the commission's intent and avoid misinterpretation of the rule requirements for an EGF subject to the MECT Program.

In addition, the commission adopts new equations in §117.320(c)(1) - (3) that incorporate the equations in existing §117.210(c)(1) - (3). The new equations in §117.320(c)(1) - (3) present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equations. The new equation in §117.320(c)(1) incorporates the equation for the rolling 30-day average NO _X emission cap during the months of July, August, and September in the existing §117.210(c)(1). Also, the commission revises variable (C) in the term H _i for §117.320(c)(1). The commission adds the language "after the end of the adjustment period as defined in §101.350 of this title (relating to Definitions)" to the definition of variable (C). This change is to clarify that the allowance for the adjustment period described in variable (D) also applies in variable (C). The new equation in §117.320(c)(2) incorporates the equation for the rolling 30-day average NO _X emission cap during months other than July, August, and September in the existing §117.210(c)(2). Consistent with the change for new §117.320(c)(1), the commission revises variable (C) in the term H _i for §117.320(c)(2). The commission adds the language "after the end of the adjustment period as defined in §101.350 of this title (relating to Definitions)" to the definition of variable (C). This change is to clarify that the allowance for the adjustment period described in variable (D) also applies in variable (C). The new equation in §117.320(c)(3) incorporates the equation for the NO _X maximum daily emission cap in the existing §117.210(c)(3).

For new §117.320(e), the language in existing §117.210(e)(3)(B) that references existing §117.213(f) is changed to reference new §117.8100(b), because the applicable rule language from existing §117.213(f) is incorporated in a new §117.8100.

Finally, for new §117.320(k), the commission replaces upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions)." This change is necessary to update the rule to current terminology used by the commission.

Section 117.323, Source Cap

The commission adopts a new §117.323 that incorporates the rule language in existing §117.223, relating to source cap, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.323(a) and (b) incorporate the rule language in existing §117.223(a) and (b). In addition, the commission adopts new equations in new §117.323(b) that incorporate the equations in existing §117.223(b) to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equations. The new equations in §117.323 include only the provisions applicable to the Houston-Galveston-Brazoria ozone nonattainment area. The new equation in §117.323(b)(1) incorporates the equation for the rolling 30-day average emission cap in the existing §117.223(b)(1). As discussed elsewhere in this preamble, variable "i" used in the equation for §117.323(b)(1) has been revised to be a lowercase "i" throughout the equation and terms to be consistent. The new equation in §117.323(b)(2) incorporates the equation for the rolling 30-day average NO _X emission cap in the existing §117.223(b)(2).

The commission adopts new §117.323(c) - (g) that incorporate the rule language in existing §117.223(c) - (g). New §117.323(h) incorporates the rule language in existing §117.223(i) and (i)(1). New §117.323(i) - (k) incorporate the rule language in existing §117.223(j) - (l), respectively. Finally, for new §117.323(j), the commission replaces upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions)." This change is necessary to update the rule to current terminology used by the commission.

Section 117.325, Alternative Case Specific Specifications

The commission adopts a new §117.325 that incorporates the rule language in the existing §117.221, relating to alternative case specific specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.325(a) and (b) incorporate the provisions in existing §117.221(a) and (b). In addition, new §117.325(a) omits the existing §117.221(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.330, Operating Requirements

The commission adopts a new §117.330 that incorporates the rule language in existing §117.208, relating to operating requirements, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.330(a) - (d) incorporate the rule language in existing §117.208(a) - (d). In addition, the commission is concurrently adopting a new §117.8140(b) that incorporates the engine testing requirements in the existing §117.208(d)(7). Therefore, the engine testing requirements in existing §117.208(d)(7) have been omitted from the new §117.330(d)(7) and replaced with a reference to the new §117.8140(b).

Section 117.335, Initial Demonstration of Compliance

The commission adopts a new §117.335 that incorporates the rule language in existing §117.211, relating to initial demonstration of compliance, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.335(a) - (d) incorporate the rule language in existing §117.211(a) - (d). Also, for new §117.335(a), the commission is revising the language in existing §117.211(a) that specifies ". . . all units which are subject to the emission limitations of this division . . ." must be tested. New §117.335(a) specifies ". . . any unit subject to §117.305 or §117.310 of this title . . ." must be tested. While compliance with the emission specifications in existing §117.206(c) is achieved through the MECT Program and an individual unit may not necessarily be required to meet the applicable emission specification in §117.206(c), units subject to existing §117.206(c) are still required to be tested according to existing §117.211. Similarly, for new §117.335(b), the commission revises the language to specify initial compliance with the requirements of this division instead of initial compliance with the emission limits of this division. These changes for new §117.335(a) and (b) will clarify the commission's intent and avoid misinterpretation of the rule requirements for units subject to the MECT Program.

The commission is concurrently adopting a new §117.8000 that incorporates the requirements in the existing §117.211(e). Therefore, the commission adopts a new §117.335(e) that replaces specific requirements from existing §117.211(e) with a reference to the new §117.8000. In addition, while existing §117.211(a) and new §117.335(a) specify that units that inject urea or ammonia for NO _X control must be tested for ammonia emissions, existing §117.211(e) does not specify the methods to be used for the required ammonia initial demonstration of compliance. New §117.8000 includes a requirement that specifies the methods required for ammonia testing during the initial demonstration of compliance. Specific discussion related to this change is included in the section-by-section discussion associated with new §117.8000.

New §117.335(f) incorporates the rule language from existing §117.211(f), regarding initial demonstration of compliance for units operating with CEMS or PEMS. Finally, the commission is concurrently adopting a new §117.8010 that incorporates the report content requirements in the existing §117.211(g). Therefore, the new §117.335(g) omits the compliance stack reports content requirements and references new §117.8010.

Section 117.340, Continuous Demonstration of Compliance

The commission adopts a new §117.340 that incorporates the rule language and requirements in existing §117.213 and §117.214 applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.340(a) incorporates the rule language concerning totalizing fuel flow meters in existing §117.213(a).

The commission adopts a new §117.340(b) that incorporates the rule language in existing §117.213(b), relating to O ₂ monitors. In addition, existing §117.213(b)(1)(B)(i) requires O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, and clause (ii) requires O ₂ monitors on process heaters greater than or equal to 200 MMBtu/hr, except as provided in existing §117.213(f). Because existing §117.213(b)(1)(B)(i) and (ii) are overlapping requirements, the new §117.340(b)(1)(B) incorporates both existing §117.213(b)(1)(B)(i) and (ii) into a single requirement for O ₂ monitors on process heaters greater than or equal to 100 MMBtu/hr, except as provided in subsection (g).

The commission adopts a new §117.340(c) that incorporates the requirements in the existing §117.213(c), relating to NO _X monitors. New §117.340(c)(1)(A) and (B) incorporate the requirements in the existing §117.213(c)(1)(A) and (B). New §117.340(c)(1)(C) - (H) incorporate the requirements in the existing §117.213(c)(1)(D) - (I).

The commission adopts a new §117.340(c)(2) and (3) that incorporate the requirements in the existing §117.213(c)(2) and (3). In addition, for new §117.340(c)(3), the commission adopts a new §117.340(c)(3)(E) to add an additional option for substitute emissions compliance data during periods when the NO _X monitor is off-line. The new §117.340(c)(3)(E)(i) specifies that for monitor downtime periods less than 24 consecutive hours, the owner or operator shall substitute the maximum block one-hour NO _X emission rate, in pounds per million British thermal units (lb/MMBtu), from the previous 24 operational hours of the monitor. New §117.340(c)(3)(E)(ii) specifies that for monitor downtime periods equal to or greater than 24 consecutive hours, the owner or operator shall substitute the maximum block one-hour NO_X emission rate, in lb/MMBtu, from the previous 720 operational hours of the monitor. New §117.340(c)(3)(E)(iii) specifies that if the fuel flow or stack exhaust monitor and the NO _X monitor are simultaneously off-line, the owner or operator shall use the maximum block one-hour NO _X pounds per hour emission rate for the substitute data in the new §117.340(c)(3)(E)(i) and (ii) in lieu of the lb/MMBtu emission rate. The provisions in new §117.340(c)(3)(E) are optional; however, the new data substitution procedures are more consistent with the requirements of the Mass Emissions Cap and Trade Program in the Houston-Galveston-Brazoria ozone nonattainment area.

The commission adopts a new §117.340(d) that incorporates the rule language and ammonia monitoring requirements in the existing §117.214(a)(1)(D). New §117.340(d) specifies that the owner or operator of units subject to the ammonia emission specifications in the new §117.310(c)(2) shall comply with the ammonia monitoring requirements of the new §117.8130. The specific ammonia monitoring procedures in existing §117.214(a)(1)(D) are incorporated in the new §117.8130.

The commission adopts a new §117.340(e) that incorporates the requirements in the existing §117.213(d) relating to CO monitoring. The specific requirements and method for CO monitoring in the existing §117.213(d)(1) and (2) appear in the new §117.8120, and subsequently have been omitted from the new §117.340(e) and replaced with a reference to the new §117.8120.

The commission adopts a new §117.340(f), concerning requirements for CEMS. The commission is concurrently adopting a new §117.8100(a) that incorporates the general requirements for CEMS in the existing §117.213(e)(1) - (3), (5), and (6). Therefore, new §117.340(f) omits existing §117.213(e)(1) - (3), (5), and (6) and references new §117.8100(a) in new §117.340(f)(1). New §117.340(f)(2) incorporates the rule language and CEMS requirements in existing §117.213(e)(4) that are specific to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.340(f)(2)(A) incorporates the rule language regarding monitoring of bypass stacks from existing §117.213(e)(4)(A). New §117.340(f)(2)(B) incorporates the rule language regarding monitoring of exhaust streams that vent to a common stack from existing §117.213(e)(4)(C).

The commission adopts a new §117.340(g) that incorporates the rule language in the existing §117.213(f), relating to requirements for PEMS. New §117.340(g)(1) incorporates the rule language from existing §117.213(f)(1). The commission is concurrently adopting a new §117.8100(b) that incorporates the general requirements for PEMS in the existing §117.213(f)(2) - (7). Therefore, the new §117.340(g) omits existing §117.213(f)(2) - (7) and new §117.340(g)(2) references new §117.8100(b).

The commission adopts a new §117.340(h) concerning testing requirements for stationary gas engines. For new §117.340(h), the commission revises the rule language "stationary gas engine subject to the emission specifications of this division" to specify "stationary gas engine subject to §117.305 of this title." The commission is concurrently adopting a new §117.8140(a) that incorporates the engine testing requirements in existing §117.213(g)(1). Therefore, the new §117.340(h) omits specific testing procedures in existing §117.213(g)(1) and references new §117.8140(a). In addition, new §117.340(h) also specifies that the owner or operator of any stationary internal combustion engines subject to new §117.310 that are not equipped with NO _X CEMS or PEMS shall test the engines for NO _X and CO emissions as specified in new §117.8140(a) and (b). This change incorporates the testing requirements for engines from existing §117.214(b)(2). In addition, as previously indicated in this preamble, the requirement in existing §117.213(g)(2), regarding installation of CEMS or PEMS engines that use a chemical reagent for reduction of NO _X , is redundant and the commission is not incorporating §117.213(g)(2) into the new §117.340(h).

The commission adopts new §117.340(i) - (n) that incorporate the rule language in the existing §117.213(h) - (m), respectively. New §117.340(o) incorporates rule language from existing §117.214(b). New §117.340(o)(1) incorporates rule language from existing §117.214(b)(1), and new §117.340(o)(2) incorporates the rule language from existing §117.214(b)(3). The commission adopts a new §117.340(p) that incorporates the requirements of the existing §117.214(c), concerning provisions for emission allowances.

The provisions in existing §117.214(a)(1)(A) - (C), concerning monitoring requirements for NO _X , CO, and totalizing fuel flow meters, are redundant with existing requirements in §117.213 and new §117.340. Therefore, existing §117.214(a)(1)(A) - (C) are not incorporated in the new §117.340. Similarly, the requirement in existing §117.214(a)(2), concerning run time meters for diesel engines claimed exempt under existing §117.203(a)(6)(D), (11), or (12), is redundant with the requirement in existing §117.213(i) and new §117.340(j). Therefore, existing §117.214(a)(2) is not incorporated in the new §117.340.

Section 117.345, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.345 that incorporates the rule language in the existing §117.219, relating to notification, recordkeeping, and reporting requirements, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.345(a) - (f) incorporate the rule language from existing §117.219(a) - (f), respectively. In addition, for new §117.345(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.345(a). Finally, the commission adopts a new §117.345(f)(11) that incorporates the ammonia recordkeeping requirements from existing §117.214(a)(1)(D)(v).

Section 117.350, Initial Control Plan Procedures

The commission adopts a new §117.350 that incorporates the rule language in the existing §117.209, relating to initial control plan procedures, applicable to the Houston-Galveston-Brazoria nonattainment area.

Section 117.352, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.352 that incorporates the requirements in the existing §117.215, relating to final control plan procedures for RACT, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

New §117.352(a) incorporates the rule language in existing §117.215(a). New §117.352(a)(2)(A), (B), and (E) incorporate the rule language in existing §117.215(a)(2)(A), (B), and (E), respectively. New §117.352(a)(2)(C) incorporates the rule language in existing §117.215(a)(2)(D), and new §117.352(a)(2)(D) incorporates the rule language in existing §117.215(a)(2)(C). New §117.352(a)(3) - (6) incorporate the rule language in existing §117.215(a)(3) - (6), respectively. In addition, for new §117.352(a)(6)(B), concerning the information required in the final control plan for gas turbines with a MW rating less than 10 MW, the commission is changing the word "ten" to the numeral "10.0" because this is the appropriate exemption MW rating from existing §117.205(h)(7) and new §117.303(b)(7). As discussed elsewhere in this preamble, the use of the numeral "10.0" will ensure consistent enforcement of the rule.

The commission adopts a new §117.352(b) and (c) that incorporate the rule language in existing §117.215(b) and (c), respectively. New §117.352 does not include existing 117.215(d), concerning the requirement to submit the control plan electronically and on hard copy using forms provided by the executive director. Existing §117.215 and new §117.352 specify the content requirements for the control plans. Therefore, a mandatory format for the control plan information is not necessary. Finally, the commission adopts a new §117.352(d) that incorporates rule language in existing §117.215(e), relating to report submittal dates.

Section 117.354, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.354 that incorporates the rule language in the existing §117.216, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.354(a) incorporates the rule language in the existing §117.216(a). New §117.354(a)(1)(A) incorporates the rule language in existing §117.216(a)(1)(E), and new §117.354(a)(1)(B) incorporates the rule language in existing §117.216(a)(1)(C). Existing §117.216(a)(1)(A), (B), and (D) are not applicable to the Houston-Galveston-Brazoria ozone nonattainment area and are not incorporated in the new §117.354. New §117.354(a)(2) - (6) incorporate the rule language from existing §117.216(a)(2) - (6). For new §117.354(a)(5), the commission removes the language "the emission specification of." As previously discussed in this preamble, this change is necessary to clarify the commission's intent regarding units subject to the MECT Program.

Existing §117.216(b) is not incorporated in the new §117.354 because the source cap option in existing §117.223 is not a compliance option for sources in the Houston-Galveston-Brazoria ozone nonattainment area subject to existing §117.206(c) and the MECT Program. Finally, the commission adopts a new §117.354(b) that incorporates the rule language in existing §117.216(c), relating to report submittal dates.

Section 117.356, Revision of Final Control Plan

The commission adopts a new §117.356 that incorporates the requirements in the existing §117.217, relating to revisions of final control plans, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

DIVISION 4, DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

The commission is adopting a new Subchapter B, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, that includes new rules applicable to any major stationary ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. The definition of a major source of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area is in new §117.10(29) and includes any stationary source or group of sources located within a contiguous area and under common control that emits or has the potential to emit at least 50 tpy of NO _X . These new rules are one part of the commission's Dallas-Fort Worth eight-hour ozone attainment demonstration and are necessary for the area to demonstrate attainment.

Section 117.400, Applicability

New §117.400, concerning applicability, specifies that the new Subchapter B, Division 4 applies to the following unit types at major ICI stationary sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area: ICI boilers and process heaters; stationary gas turbines; stationary internal combustion engines; duct burners used in turbine exhaust ducts; lime kilns; metallurgical heat treating furnaces and reheat furnaces; incinerators; glass, fiberglass, and mineral wool melting furnaces; fiberglass and mineral wool curing ovens; natural gas-fired ovens and heaters; natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic tile, calcining, and vitrifying processes; brick and ceramic kilns; and lead smelting reverberatory and blast (cupola) furnaces. Based on comments received, fiberglass and mineral wool forming ovens and electric arc melting furnaces used in steel production have been removed from the applicability of the adopted rule. The paragraphs under §117.400 have been renumbered accordingly. In addition, for §117.400(11), the commission has revised the language to say natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic tile, calcining, and vitrifying processes. While the commission interprets this language in the same manner as the proposed language, comments were received that might indicate some confusion as to whether all processes were natural-gas fired. The revised language should avoid any misinterpretation of the commission's intent.

Section 117.403, Exemptions

New §117.403 specifies the unit types, sizes, or uses that are exempted from the requirements of the division. Units where the unit type, maximum rated capacity, or specific use would be technically or economically infeasible to comply with the specifications or are regulated under another division are exempted from the provisions of this division.

New §117.403(a) specifies those units exempt from the division, except as specified in new §§117.440(i), 117.445(f)(4) and (9), 117.450, and 117.454. The exceptions to the exemptions are related to monitoring, recordkeeping, and control plan requirements associated with exempted units. Based on comments received, the commission has revised the exemption limit threshold for process heaters for reasons discussed elsewhere in this preamble. New §117.403(a)(1)(A) specifies that ICI boilers with a maximum rated capacity of 2.0 MMBtu/hr or less are exempt. New §117.403(a)(1)(B) specifies that process heaters with a maximum rated capacity equal to or less than 5.0 MMBtu/hr are exempt. Natural gas-fired units with a maximum rated capacity of 2.0 MMBtu/hr or less are already regulated under existing Subchapter B, Division 1, that is incorporated in new Subchapter E, Division 3.

New §117.403(a)(2) specifies an exemption for heat treating furnaces and reheat furnaces less than 20 MMBtu/hr. This exemption level is consistent with the exemption in existing §117.203(a)(3) for similar sources in the Houston-Galveston-Brazoria area and is adopted for the Dallas-Fort Worth eight-hour ozone nonattainment area due to the low level of NO _X emissions from units of this size and the impracticality of installing and maintaining NO _X controls on such units.

New §117.403(a)(3) specifies exemptions for flares and incinerators with a maximum rated capacity of 40 MMBtu/hr due to the low level of NO_X emissions from these units and the impracticality of installing and maintaining NO _X controls on such units. This exemption is consistent with existing exemptions in the specifications for the Houston-Galveston-Brazoria area of §117.203(a)(4). In addition, new §117.403(a)(3) specifies that pulping liquor recovery furnaces, sulfur recovery units, sulfuric acid regeneration units, molten sulfur oxidation furnaces, and sulfur plant reaction boilers are also exempt. This addition is consistent with the existing exemptions in the specifications for the Houston-Galveston-Brazoria area for units that commingle fuel and process chemicals and are not large sources of NO _X emissions.

New §117.403(a)(4) specifies dryers, heaters, or ovens with a maximum rated capacity of 5.0 MMBtu/hr or less are exempt. This exemption level is adopted due to the relatively small contribution of NO _X emissions from units of this size and the impracticality of installing and maintaining NO _X controls on such units.

New §117.403(a)(5) specifies dryers, heaters, or ovens fired on fuels other than natural gas are exempt. The commission is adopting this exemption due to the limited number, if any, of these unit types fired on fuels other than natural gas and their insignificant contribution to NO _X levels in the area. The adopted §117.403(a)(5) is also revised to reflect the changes made to §117.400(9) and (11). New §117.403(a)(6) specifies that any glass, fiberglass, or mineral wool melting furnaces with a maximum rated capacity of 2.0 MMBtu/hr or less are exempt from the specifications of this division. This exemption level is adopted due to the relatively small contribution to NO _X emissions in the area from units of this size and the impracticality of installing and maintaining NO_X controls on such units.

In addition, the following stationary internal combustion engines and stationary gas turbines are exempt under the new §117.403(a)(7)(A) - (G): engines and stationary gas turbines used in research and testing; used for purposes of performance verification and testing; used solely to power other engines or gas turbines during startups; used exclusively in emergency situations (except that operation for testing or maintenance purposes is allowed for up to 100 hours per year, based on a rolling 12-month average); used in response to and during the existence of any officially declared disaster or state of emergency; used directly and exclusively by the owner or operator for agricultural operations necessary for the growing of crops or raising of fowl or animals; or used as chemical processing gas turbines. Based on comments received, the adopted exemption in §117.403(a)(7)(D) was revised to allow up to 100 hours of use for testing or maintenance purposes, instead of the 52 hours allowed under the proposed §117.403(1)(7)(D). Any new, modified, reconstructed, or relocated stationary diesel engine placed into service on or after June 1, 2007, is not eligible for the emergency use exemption in §117.403(a)(7)(D). These exemptions are due to the relatively small NO _X emissions contribution in the area from these sources due to their limited use or the impracticality of using NO _X emissions controls during such limited operating times. The exemptions in new §117.403(a)(7)(A) - (G) are similar to existing exemptions in the Houston-Galveston-Brazoria area.

New §117.403(a)(8) specifies an exemption for any stationary diesel engine placed into service before June 1, 2007, that operates less than 100 hours per year, based on a rolling 12-month average, and has not been modified, reconstructed, or relocated on or after June 1, 2007. New §117.403(a)(9) exempts any new, modified, reconstructed, or relocated stationary diesel engine placed into service on or after June 1, 2007, that operates less than 100 hours per year, in other emergency situations, and meets the corresponding emission standard for non-road engines listed in 40 Code of Federal Regulations (CFR) §89.112(a), Table 1 (October 23, 1998) and in effect at the time of installation, modification, reconstruction, or relocation. These exemptions are consistent with existing exemptions applicable in the Houston-Galveston-Brazoria ozone nonattainment area for emergency back-up diesel engines and are adopted for the Dallas-Fort Worth eight-hour ozone nonattainment area because of the limited use of emergency back-up diesel engines.

New §117.403(a)(10) exempts boilers and industrial furnaces that were regulated as existing facilities by the EPA, 40 CFR Part 266, Subpart H, as was in effect on June 9, 1993. This exemption is consistent with existing exemptions applicable in the Houston-Galveston-Brazoria ozone nonattainment area and is necessary to avoid overlapping regulatory requirements for cement kilns regulated by new Chapter 117, Subchapter E, Division 2.

New §117.403(a)(11) exempts brick or ceramic kilns with a maximum rated capacity less than 5.0 MMBtu/hr. This exemption is adopted due to the relatively small NO _X emissions contribution in the area from these smaller kilns.

New §117.403(a)(12) has been added in response to comments received and exempts curing ovens used in mineral wool-type fiberglass manufacturing in which nitrogen-bound chemical additives are used. The addition of nitrogen-bound chemical additives contributes to the creation of non-combustion related thermal NO _X which cannot be controlled using the control methodologies the commission has identified as appropriate for curing ovens used in mineral wool type fiberglass manufacturing. In addition, the amount of NO _X from curing ovens of this type are estimated to be a small contribution to the total NO _X emissions from this industry.

New §117.403(a)(13) has been added in response to comment and exempts stationary, gas-fired, reciprocating internal combustion engines with a horsepower (hp) rating less than 50hp. This revision has been adopted due to the relatively small NO _X emissions contribution in the area from these smaller engines.

New §117.403(a)(14) has been added to specify that electric arc melting furnaces used in steel production are exempt from the rule. A new §117.403(a)(15) has also been added that exempts all forming ovens and forming processes used in mineral wool type fiberglass manufacturing. These exemptions have been added based on comments received that are discussed elsewhere in this preamble. New §117.403(a)(16) has been added to clarify that heaters used exclusively to heat air for physical comfort in an occupational space are exempt and were not intended to be regulated under this rulemaking.

The §117.403(b), concerning IOP exemptions, exempts stationary, reciprocating internal combustion engines with a maximum rated capacity of less than 300 horsepower (hp) from the emission specification in new §117.410(a). This exemption is consistent with the current exemption applicable to the engines subject to existing §117.206(b)(3) and is necessary to ensure that engines not previously subject to existing §117.206(b)(3) are inadvertently made subject to the emission specifications in §117.410(a). New §117.403(b) also specifies that the specifications of §117.410(a) no longer apply to any stationary, reciprocating internal combustion engine subject to the emission specifications of §117.410(b) after the compliance date specified in §117.9030(b). This exemption is to prevent units subject to the 5% IOP emission specifications from being regulated by two overlapping requirements once the more stringent emission specifications in §117.410(b) become applicable. In addition, while no comments were received regarding the exemptions in §117.403(b), it has come to the commission's attention that an applicable exemption that might apply to engines that would otherwise be subject to the existing §117.206(b)(3) was inadvertently omitted from the proposed version of §117.403(b). The exemption in existing §117.205(h)(9) that exempts engines that are demonstrated to operate less than 850 hours per year, based on a 12-month average, is referenced from existing §117.206(g)(2). The commission is adopting a new §117.403(b)(3) that includes this exemption. The exemption for engines demonstrated to operate less than 850 hours per year is not applicable to the new adopted standards for engines in §117.410(b) and is therefore not included in the general exemptions in §117.403(a).

In response to comments received, the commission adopts a new §117.403(c) to provide an emergency fuel oil firing exemption for gas-fired boilers. New subsection (c) specifies that the emission specifications in §117.410(b)(1) and (d) do not apply to gas-fired boilers during periods that the owner or operator is required to fire fuel oil on an emergency basis due to natural gas curtailment or other emergency, provided the conditions in paragraphs (1) and (2) are met. Paragraph (1) specifies that the fuel oil firing must have occurred during November, December, January, or February, and paragraph (2) limits the fuel oil firing to a total of 72 hours in any of these months. These provisions are intended to limit the emergency fuel oil firing to as limited amount of time as possible and to non-ozone season only.

Section 117.410, Emission Specifications for Eight-Hour Attainment Demonstration

The commission adopts a new section §117.410, relating to Emission Specifications for Eight-Hour Attainment Demonstration. The new §117.410 establishes NO _X emissions specifications for units in the Dallas-Fort Worth eight-hour ozone nonattainment area that are subject to this rulemaking. New §117.410(a), concerning emission specifications for increment of progress, incorporates the emissions specifications for gas-fired engines with a maximum capacity greater than 300 hp established under the 5% IOP from the existing one-hour specifications in existing §117.206(b)(3) into the eight-hour attainment demonstration. The 5% IOP specifications in existing §117.206(b)(3) apply to all nine counties in the Dallas-Fort Worth eight-hour ozone nonattainment area and are therefore more consistent with the new Subchapter B, Division 4. The existing emission specifications and rule language from existing §117.206(b)(3) are incorporated in new §117.410(a) without change, except for non-substantive changes associated with reformatting and renumbering.

New §117.410(b) includes the new emission specifications for the Dallas-Fort Worth eight-hour ozone attainment demonstration. New §117.410(b)(1) specifies a NO _X emission specification for non-utility gas-fired boilers depending on maximum capacity. Gas-fired boilers with a maximum rated capacity equal to or greater than 100 MMBtu/hr are limited to 0.020 lb/MMBtu. Gas-fired boilers with a maximum rated capacity equal to or greater than 40 MMBtu/hr but less than 100 MMBtu/hr are limited to 0.030 lb/MMBtu. The emission limit for gas-fired boilers with a maximum rated capacity less than 40 MMBtu/hr is 0.036 lb/MMBtu, or alternatively, 30 parts per million by volume (ppmv), at 3.0% O ₂ , dry basis. The 0.020 lb/MMBtu emission specification for gas-fired boilers greater than 100 MMBtu/hr is expected to require the installation of SCR. Owners or operators of gas-fired boilers equal to or greater than 40 MMBtu/hr but less than 100 MMBtu/hr may be able meet the 0.030 lb/MMBtu emission specification through combustion modifications, such as installation of low-NO _X burners or burner modifications; however, SCR may be required in some cases to meet this emission specification. The emission specification of 0.036 lb/MMBtu for boilers less than 40 MMBtu/hr is expected to be achievable through installation of low-NO _X burners or burner modifications.

New §117.410(b)(2) specifies a NO _X emission specification of 2.0 pounds per 1,000 gallons of liquid burned for liquid-fired boilers. The commission anticipates that this emission specification is achievable through installation of SCR.

New §117.410(b)(3) includes NO _X emission specifications of 0.025 lb/MMBtu for process heaters with a maximum rated capacity equal to or greater than 40 MMBtu/hr and 0.036 lb/MMBtu (or alternatively, 30 ppmv, at 3.0% O ₂ , dry basis) for process heaters with a maximum rated capacity less than 40 MMBtu/hr. SCR may be necessary for process heaters with a maximum rated capacity equal to or greater than 40 MMBtu/hr to comply with the 0.025 lb/MMBtu emission specification. Owners or operators of gas-fired process heaters with maximum rated capacities less than 40 MMBtu/hr may be required to install low-NO _X burners or make other combustion modifications to comply with the 0.036 lb/MMBtu emission specification. No liquid-fired process heaters were identified in the inventory in the Dallas-Fort Worth eight-hour ozone area; however, SCR may be necessary for a liquid-fired process heater to comply with the emission specification.

New §117.410(b)(4) provides NO _X emission specifications for stationary reciprocating internal combustion engines. The language in §117.410(b)(4)(A) and (B) establishes NO _X emission specifications for stationary, gas-fired rich-burn and lean-burn, reciprocating internal combustion engines. Gas-fired engines fired on landfill gas are limited to 0.60 grams per horsepower-hour (g/hp-hr) and all other gas-fired engines are limited to 0.50 g/hp-hr. Nonselective catalytic reduction (NSCR) is expected to be the primary control technology for rich-burn gas-fired engines. In some cases, the addition of a secondary catalyst module may be required to meet the emission specification.

Based on comments received, the commission has revised the emission specifications for lean-burn gas-fired engines under §117.410(b)(4)(B). Lean-burn engines placed into service before June 1, 2007, that have not been modified, reconstructed, or relocated on or after June 1, 2007, are limited to 0.70 g/hp-hr under §117.410(b)(4)(B)(i). New §117.410(b)(4)(B)(ii) establishes emission specifications for lean-burn gas-fired engines installed, modified, reconstructed, or relocated on or after June 1, 2007. New §117.410(b)(4)(B)(ii)(I) establishes a limit of 0.60 g/hp-hr for lean-burn engines fired on landfill gas, and new §117.410(b)(4)(B)(ii)(II) establishes a limit of 0.50 g/hp-hr for all other lean-burn engines. For lean-burn gas-fired engines, the commission has identified two possible control methodologies to achieve the emission standards. One control technology available for lean-burn engines is the application of an exhaust gas recirculation (EGR) kit combined with NSCR control. While NSCR is not normally applied to lean-burn engines, the use of the EGR kit reduces exhaust gas O ₂ and allows NSCR to be installed. Owners or operators of some lean-burn engines may not be able to apply EGR coupled with NSCR. In these cases, SCR may be necessary to meet the emission specification. The commission has identified only one engine located at a major source in the Dallas-Fort Worth eight-hour ozone nonattainment area that is fired on land-fill gas. The emission specification of 0.60 g/hp-hr is expected to be achievable through combustion modifications.

New §117.410(b)(4)(C) limits stationary, dual-fuel, reciprocating internal combustion engines to 0.50 g/hp-hr. There are three possible dual-fuel engines identified at major sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission anticipates that SCR may be necessary to comply with the 0.50 g/hp-hr emission specification.

New §117.410(b)(4)(D) and (E) establish NO _X emission specifications for stationary diesel reciprocating internal combustion engines. While the date associated with the emission specifications in §117.410(b)(4)(D) and (E) was not specifically commented on, the commission has determined that March 1, 2009, the compliance date specified for diesel engines in §117.9030, is more appropriate to use as a basis for the tiered emission specification under §117.410(b)(4)(D) and (E). Aligning the date with the compliance date in §117.9030 will simplify the emission specification schedule and make compliance with the rule easier for owners or operators of engines that were ordered prior to the rule proposal but would not be installed by June 1, 2007. This revision also provides relief for emergency diesel engines installed after June 1, 2007, that might not qualify for exemption under §117.403(a)(8) or (9). The new §117.410(b)(4)(D) establishes NO _X emission specifications for stationary diesel reciprocating internal combustion engines placed into service before March 1, 2009, and that have not been modified, reconstructed, or relocated on or after March 1, 2009, as the lower of 11.0 g/hp-hr or the emission rate established by testing, monitoring, manufacturer's guarantee, or manufacturer's other data. In addition, the definitions of modification, reconstruction, and relocated that were proposed in §117.410(b)(4)(D) are moved to a new §117.410(b)(4)(F) because these definitions apply to all §117.410(b)(4). The new §117.410(b)(4)(E) establishes the NO _X emission specifications for stationary diesel engines installed, modified, reconstructed, or relocated on or after March 1, 2009. The emission specifications in §117.410(b)(4)(E) are tiered based on engine horsepower and are consistent with the final standards for stationary diesel engines in the Houston-Galveston-Brazoria nonattainment area.

The commission expects that, initially, the majority of stationary diesel engines at major sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area will qualify for exemption under §117.403(a)(9). When owners or operators modify, reconstruct, or relocate existing stationary diesel engines on or after March 1, 2009, if used exclusively in emergency situations, these engines will continue to be exempt from the new emission specifications, but will be required to meet the EPA Tier 1, Tier 2, and Tier 3 emission standards for non-road diesel engines in effect at the time of installation, modification, reconstruction, or relocation. This requirement will ensure that as turnover of older, higher-emitting stationary diesel engines occurs, the replacements will be cleaner engines. For engines that do not qualify for exemption, the commission does not anticipate that engines placed into service prior to March 1, 2009, will require combustion modifications to meet the 11.0 g/hp-hr emission specification. The cost of combustion modifications to stationary diesel engines to meet the emission standards in §117.410(b)(4)(D) is expected to be near the cost of a new engine; therefore, the commission anticipates that for engines placed into service on or after March 1, 2009, the owner or operator will likely purchase new equipment rather than retrofit or modify existing equipment.

As discussed elsewhere in this preamble, new §117.410(b)(4)(F) provides the definitions of the terms modification, reconstruction, and relocated that were originally proposed in §117.410(b)(4)(D). Because these terms are used in new §117.410(b)(4)(B), this change is necessary to clarify the meaning of the terms for all of paragraph (4).

New §117.410(b)(5) establishes NO _X emission specifications for stationary gas turbines. Stationary gas turbines rated at 10 MW or greater are limited to 0.032 lb/MMBtu; stationary gas turbines rated at 1.0 MW or greater, but less than 10 MW, are limited to 0.15 lb/MMBtu; and stationary gas turbines less than 1.0 MW are limited to 0.26 lb/MMBtu. The new §117.410(b)(6) specifies that duct burners used in turbine exhaust ducts are limited to the corresponding gas turbine emission specifications of §117.410(b)(5). Compliance with the emission specification of 0.032 lb/MMBtu for stationary gas turbines and duct burners used in turbine exhaust ducts may require the installation of SCR. The emission specifications for all stationary gas turbines less than 10 MW and duct burners used in associated turbine exhaust ducts are expected to be achievable through combustion modifications such as water or steam injection or other modifications.

The new §117.410(b)(7) establishes emission specifications for lime, brick, and ceramic kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area. In response to comments received and discussed further elsewhere in this preamble, the commission has revised the emission specification for lime kilns in §117.410(b)(7)(A) to 3.7 pounds per ton (lb/ton) of calcium oxide (CaO) produced. In addition, the commission has provided two compliance options in new clauses (i) and (ii) for lime kilns to meet this emission specification. New §117.410(b)(7)(A)(i) provides lime kiln owners and operators with the option of complying with the 3.7 lb/ton CaO on a unit-by-unit basis, i.e., on an individual kiln basis. New §117.410(b)(7)(A)(ii) allows owners or operators to demonstrate compliance on a site-wide production rate weighted average basis. New §117.410(b)(7)(A)(ii) specifies an equation for determining the site-wide production rate weighted average NO _X emission rate. The equation calculates the daily site-wide production rate weighted average based on the daily average NO _X emission rate for each kiln multiplied by that kiln's daily production rate in tons/day, then summing these products for all kilns to calculate total NO _X emissions for the day and dividing by the total site-wide production in tons/day. The emission limit of 3.7 lb/ton of CaO is based on good combustion practices and proper kiln operation, possibly combined with low-NO _X burners, as specified by the EPA as Best Available Control Techniques (BACT) for lime kilns.

Based on comments received and discussed elsewhere in this preamble, new §117.410(b)(7)(B) allows two compliance options for brick and ceramic kilns. New §117.410(b)(7)(B)(i) allows the option of a 40% reduction from the daily NO _X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 Emissions Inventory. To ensure that this emission specification will result in a real 40% reduction in actual emissions, a consistent methodology must be used to calculate the 40% reduction. New §117.410(b)(7)(B)(ii) establishes a NO _X emission specification of 0.175 pounds per ton of product for brick kilns. New §117.410(b)(7)(B)(iii) establishes a NO _X emission specification of 0.27 pounds per ton of product for ceramic kilns. Compliance with these control requirements is anticipated to be achievable through combustion and process modifications, installation of low-NO _X burners or staged combustion, or some combination of these control measures.

New §117.410(b)(8) establishes NO _X emission specifications for metallurgical furnaces. Heat treating furnaces are limited to 0.087 lb/MMBtu under subparagraph (A), and reheat furnaces are limited to 0.10 lb/MMBtu under subparagraph (B). The emission specification for heat-treat furnaces is based on the emission specifications for heat treating in the Houston-Galveston-Brazoria ozone nonattainment area and is expected to be achievable through combustion modifications or installation of low-NO_X burners combined with flue gas recirculation (FGR). The emission specification for reheat furnaces is based on the permitted BACT limits for similar units and is anticipated to require the owners or operators of affected units to make combustion modifications, install ultra low-NO_X burners, and possibly install FGR units to meet the specifications. In addition, based on comments received, the commission has revised subparagraphs (A) and (B) to specify that furnaces equipped with NO_X CEMS or PEMS are only required to meet these emission specifications from March 1 to October 31. This provision allows owners and operators the ability to shift production of high heat input products to non-ozone season as a potential means of assisting compliance with the emission standards.

As discussed elsewhere in this preamble, the commission is exempting electric arc melting furnaces used in steel production; therefore, proposed subparagraph (C) is not adopted with this rulemaking. The emission specification for lead smelting blast and reverberatory furnaces used in conjunction, proposed as subparagraph (D), is adopted as subparagraph (C). The emission specification of a combined rate of 0.45 pounds per ton of product for lead smelting blast and reverberatory furnaces used in conjunction is unchanged from the proposed rule. Owners or operators may be required to use a combination of low-NO_X burners and FGR or possibly post-combustion controls such as SNCR to meet this emission specification.

New §117.410(b)(9) establishes NO _X emission specifications for incinerators and provides two options. The first option is to achieve an 80% reduction from the daily NO _X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 Emissions Inventory. To ensure that this emission specification will result in a real 80% reduction in actual emissions, a consistent methodology must be used to calculate the 80% reduction. The second option is to comply with a 0.030 lb/MMBtu emission specification. While these emission specifications for incinerators may be achievable through installation of low-NO _X burners or making other combustion modifications, SCR may be necessary to achieve the 80% reduction or the 0.030 lb/MMBtu emission specification.

Proposed §117.410(b)(10) established emission specifications for glass and fiberglass melting furnaces. Based on comments received and discussed in detail elsewhere in this preamble, the emission specifications for glass and fiberglass melting furnaces under paragraph (10) have been revised to address technical feasibility issues associated with different furnace types, designs, and operations. New §117.410(b)(10)(A)(i) changes the emission specification for container glass melting furnaces operating equal to or more than 25% of the permitted glass production capacity to 4.0 lb/ton glass pulled. New §117.410(b)(10)(A)(ii) provides for "idling" situations in which the furnace is required to operate at less than 25% of its permitted glass production capacity and sets the emission rate during this operation at the applicable maximum allowable pound per hour NO _X permit limit in a permit issued before June 1, 2007. As discussed elsewhere in this preamble, this distinction regarding emission specifications is necessary to address an operational requirement known as "idling" when the furnace is required to operate at very low production rates.

Due to comments received and discussed elsewhere in this preamble, proposed subparagraph (B) has been revised to clarify the electric furnaces regulated under this subparagraph as "cold top" electric furnaces and change the emission limit to 4.0 lb/ton product. Subparagraph (C) regulating mineral wool-type fiberglass regenerative furnaces at a NO _X emission specification of 1.45 lb/ton of product remains unchanged and is adopted as proposed. Due to comments received and discussed elsewhere in this preamble, new subparagraph (D) has been added to differentiate mineral wool-type fiberglass non-regenerative gas-fired furnaces from those regulated under subparagraph (C). The emission specification for mineral wool-type fiberglass non-regenerative gas-fired furnaces is 3.1 lb/ton product based on permitted emission rates.

The commission anticipates that most of the affected glass and fiberglass melting furnaces will require low-NO _X burners, oxy-firing, SCR, SNCR, or a combination of these control technologies to reach the emission specifications. Informal stakeholder comments indicated that SCR is not an appropriate control technology for glass and fiberglass melting furnaces due to wide variations in furnace operating temperatures. In addition, NO _X emissions from glass melting furnaces, especially electric glass melting furnaces, are typically thermal NO _X emissions formed from the combustion air and high operating temperatures of the furnace and will therefore require oxy-firing for compliance.

New §117.410(b)(11) and (12) establish a 0.036 lb/MMBtu NO _X emission specification for the following units, respectively: gas-fired curing ovens used for the production of mineral wool-type or textile-type fiberglass; natural gas-fired ovens and heaters used in industrial processes; and natural gas-fired dryers used in organic solvent, printing, clay, brick, ceramic tile, calcining, and vitrifying processes. As discussed elsewhere in this preamble, §117.410(b)(11) excludes forming ovens used in mineral wool-type fiberglass manufacturing because this source category is exempt under the adopted rule. In addition, §117.410(b)(13) is revised to clarify the applicability of these types of dryers consistent with the changes discussed elsewhere regarding §117.400(11). These emission specifications are anticipated to be achieved through combustion modifications, such as burner modifications or installation of low-NO _X burners.

New §117.410(b)(13)(A) establishes a NO _X emission specification of 0.036 lb/MMBtu for natural gas-fired dryers used in organic solvent, printing, clay, brick, ceramic tile, calcining, and vitrifying processes. In addition, §117.410(b)(13)(A) is revised to clarify the applicability of these types of dryers consistent with the changes discussed elsewhere regarding §117.400(11). New §117.410(b)(13)(B) establishes a 0.15 lb/MMBtu NO _X emission specification for spray dryers used in ceramic tile manufacturing processes. These emission specifications are anticipated to be achieved through combustion modifications, such as burner modifications or installation of low-NO _X burners.

New §117.410(b)(14) provides an alternative to the emission specifications in paragraphs (1) - (13) of §117.410(b) for units with an annual capacity factor of 0.0383 or less. The alternative NO _X emission specification for qualifying units is 0.060 lb/MMBtu. This low annual capacity factor and alternative emission specification are consistent with a similar provision specified for the Houston-Galveston-Brazoria ozone nonattainment area in existing §117.206(c)(2). The capacity factor as of December 31, 2000, must be used to determine whether the unit is eligible for the alternative emission specification. A 12-month rolling average must be used to determine the annual capacity factor for units placed into service after December 31, 2000.

New §117.410(c), concerning NO _X averaging time, specifies the averaging times for compliance with the emission specifications. New §117.410(c)(1) specifies the averaging times for units equipped with CEMS or PEMS and provides three options under subparagraphs (A), (B), and (C). Subparagraph (A) specifies a rolling 30-day average, in the units of the applicable standard. Subparagraph (B) specifies a block one-hour average basis, in the units of the applicable standard. Subparagraph (C) specifies a block one-hour average, in pounds per hour, for boilers and process heaters, calculated based on the maximum rated capacity and the applicable emission specification. For units not equipped with CEMS or PEMS, new §117.410(c)(2) requires the averaging time to be a block one-hour average in the units of the applicable standard, but allows the emission specifications for boilers and process heaters to be applied in pounds per hour as specified in new §117.410(c)(1)(C).

New §117.410(d) establishes ammonia and CO emission specifications for any unit subject to the emission specifications in §117.410(a) or (b) as applicable. These ammonia and CO emission specifications are necessary to ensure that the NO _X reduction strategies of this rulemaking do not result in an excessive increase in emissions of other pollutants. New §117.410(d)(1) establishes a CO emission specification of 400 ppmv at 3% O ₂ , dry basis (or alternatively, 3.0 g/hp-hr for stationary internal combustion engines) on a rolling 24-hour averaging period for units equipped with CEMS and PEMS for CO, and on a one-hour average for units not equipped with CEMS or PEMS. New §117.410(d)(2) specifies that units that inject urea or ammonia into the exhaust stream for NO _X control must meet a 10 ppmv ammonia emission specification. The 10 ppmv ammonia emission specification is corrected to 3.0% O ₂ for boilers and process heaters, 15% O ₂ for stationary gas turbines and gas-fired lean-burn engines, 7.0% O ₂ for incinerators, and 3.0% O ₂ for all other units. The specified averaging time for the ammonia emission specification is on a rolling 24-hour averaging period for units equipped with CEMS and PEMS for ammonia, and on a one-hour average for units not equipped with CEMS or PEMS. New §117.410(d)(3) specifies that the correction of CO emissions to 3.0% O ₂ , dry basis, does not apply to boilers and process heaters operating at less than 10% maximum load and stack O ₂ more than 15%. New §117.410(d)(4) lists cases where the CO emission specification in new §117.410(d)(1) does not apply, including stationary internal combustion engines subject to new §117.410(a), and incinerators subject to CO limits under 30 TAC §111.121 or §113.2072, or 40 CFR Part 264 or 265, Subpart O, for hazardous waste incinerators.

New §117.410(e) specifies conditions for compliance flexibility with the NO _X emission specifications of new §117.410. New §117.410(e)(1) specifies that owners or operators may use the source cap option under new §117.423 or emission reduction credits as specified in new §117.9800 to comply with the NO _X emission specifications of new §117.410. New §117.410(e)(2) prohibits using new §117.425, concerning alternative case specific specifications, as a method of compliance with the NO _X emission specifications of new §117.410. This prohibition is necessary to ensure that the NO _X reductions anticipated from this rulemaking will be realized. New §117.410(e)(3) specifies that owners or operators may petition the executive director for an alternative to the CO and ammonia emission specifications according to new §117.425.

New §117.410(f) establishes the provisions for prohibition of circumvention to ensure the anticipated NO _X reductions modeled for this rulemaking will be realized. The new §117.410(f)(1) establishes that the maximum rated capacity used to determine the applicability of the emissions specifications, initial compliance demonstration, monitoring, testing requirements, and final control plan in §§117.410, 117.435, 117.440, and 117.454 must be the greater of the maximum rated capacity as of December 31, 2000, or the maximum rated capacity authorized by a permit issued under 30 TAC Chapter 116 after December 31, 2000. New §117.410(f)(2) specifies that a unit's classification for the purposes of Subchapter B, Division 4, is determined by the most specific classification applicable to the unit as of December 31, 2000.

While no comments were received regarding §117.410(f)(3), the commission has become aware of a discrepancy between the prohibition of circumvention provision in subsection (f)(3) and similar provisions in §117.2110 for minor sources in the Dallas-Fort Worth eight-hour ozone nonattainment area and in §117.310 and §117.2010 for the Houston-Galveston-Brazoria ozone nonattainment area. As proposed, §117.410(f)(3) would not allow any changes to a unit subject to §117.410(b) that would result in an increase of NO _X emissions at a unit not subject to §117.410(b). The provision as proposed is too restrictive and possibly could cause an owner or operator to be in a position in which compliance would not be possible. Therefore, the commission has revised new §117.410(f)(3) to specify that changes after December 31, 2000, to a unit subject to an emission specification in §117.410(b) that result in increased NO _X emissions from a unit not subject to an emission specification of §117.410(b) are only allowed if the provisions in new §117.410(f)(3)(A) and (B) are met. New subparagraph (A) requires that the increase in NO _X emissions at the unit not subject to §117.410(b) must be determined using CEMS or PEMS according to §117.440 or through testing according to §117.435. New subparagraph (B) requires that emission credits equal to the increase in NO _X emissions at the unit not subject to §117.410 must be obtained and used in accordance with §117.9800. The provisions in subparagraphs (A) and (B) are consistent with the prohibition of circumvention provisions in §§117.310, 117.2010, and 117.2110.

The new §117.410(f)(4) specifies that a source that met the definition of a major source as of December 31, 2000, is always classified as a major source for the purposes of Subchapter B, Division 4. A source that did not meet the definition of major source on December 31, 2000, but at any time after December 31, 2000, becomes a major source, will from that time forward always be classified as a major source for purposes of Subchapter B, Division 4.

New §117.410(f)(5) specifies that the availability under §117.410(b)(14) of an alternative emission specification for units with an annual capacity factor of 0.0383 or less is based on the unit's status on December 31, 2000. Reduced operation after December 31, 2000, cannot be used to qualify for a more lenient emission specification under §117.410(b)(14) than would otherwise apply to the unit. New §117.410(f)(6) specifies that prohibition of circumvention of §117.410(f) does not apply to stationary, reciprocating internal combustion engines subject to the IOP emission specifications in §117.410(a) until the compliance date specified in §117.9030(b). These engines are not currently subject to the prohibition of circumvention under existing §117.206, and new §117.410(f)(6) ensures that the provisions of this subsection are not imposed on the owners or operators of these engines until the engines become subject to the new emission specifications in §117.410(b).

New §117.410(g), relating to operating restrictions, specifies that no person may start or operate any stationary diesel or dual-fuel engine for testing or maintenance between the hours of 6:00 a.m. and noon, except for specific manufacturer's recommended testing requiring a run of over 18 consecutive hours, to verify reliability of emergency equipment (e.g., emergency generators or pumps) immediately after unforeseen repairs or firewater pumps for emergency response training conducted from April 1 through October 31. For the purposes of this provision, new §117.410(g) also specifies that routine maintenance such as an oil change is not considered to be an unforeseen repair. This provision is identical to a requirement implemented for the Houston-Galveston-Brazoria ozone nonattainment area. The requirement will delay emissions of NO_X from testing of these engines until after noon in order to help limit ozone formation.

Section 117.423, Source Cap

The commission adopts a new §117.423 to provide an optional source cap approach to demonstrating compliance with emission specifications of new §117.410. This source cap option is similar to the source cap allowed under existing §117.223 for major sources in ozone nonattainment areas. New §117.423(a) specifies that the owner or operator may achieve compliance with the emission specifications of §117.410 by achieving equivalent NO _X emission reductions obtained by compliance with a source cap emission limitation. If an owner or operator elects this option, any equipment category included in the source cap must include all emission units belonging to that category. All emission units not included in the source cap must comply with the requirements of §117.410.

New §117.423(b) specifies the equations and procedures for determining the source cap allowable NO _X mass emission rate. The equation in new §117.423(b)(1) specifies how to calculate the 30-day rolling average emission cap in pounds per day. This equation is similar to the source cap equation in existing §117.223(b)(1) as it is applicable to the Dallas-Fort Worth ozone nonattainment area. However, the averaging period for determining the historical average daily heat input, variable H_i in the equation, is defined as the 24 consecutive months between January 1, 2000, and December 31, 2001. In addition, the effective date for an applicable permit emission limit for clause (ii) of variable R_i of the equation is December 31, 2000. As discussed elsewhere in this preamble, variable "i" used in the equation for §117.423(b)(1) has been revised to be a lowercase "i" throughout the equation and terms to be consistent. New §117.423(b)(2) specifies the equation for calculating the maximum daily cap, in pounds per day, for all units included in the source cap. The equation in new §117.423(b)(2) is identical to the equation for the maximum daily cap in existing §117.223(b)(2).

New §117.423(b)(3) specifies that each emission unit in the source cap is subject to the requirements of both subsection (b)(1) and (b)(2). In the existing source cap provisions in §117.223, existing §117.223(b)(4) allows the owner or operator to opt in entire classes of exempted units. The commission is not allowing this option under new §117.423 because it would have limited or no benefit to sources in the Dallas-Fort Worth eight-hour ozone nonattainment area due to the relatively few exempted units under the rule.

New §117.423(b)(4) specifies the equation for calculating the source cap allowable emission rate, in pounds per hour, for stationary internal combustion engines. The equations in new §117.423(b)(4) and (5) for calculation of the source cap allowable emission rate for stationary internal combustion engines and stationary gas turbines, respectively, are similar to the calculations referenced in existing §117.223(b)(5) and (6). Rather than reference a separate division, the applicable equations are in new §117.423(b)(4) and (5). The equations in new §117.423(b)(4) and (5) are identical in content to the original calculations referenced for stationary internal combustion engines and stationary gas turbines under the source cap option in existing §117.223, except that the resultant titles are changed to reflect the source cap option in §117.423 and the section cross-reference in the equation in §117.423(b)(5) references new §117.410(b).

New §117.423(c) specifies the continuous emissions monitoring and testing requirements for each source included in the source cap. New §117.423(c)(1)(A) and (B) specifies that for each unit included in the source cap, the owner or operator must comply with the NO _X , CO, O₂ (or carbon dioxide), and fuel monitoring requirements of new §117.440, either using a CEMS or a PEMS. Both §117.423(c)(1)(A) and (B) specify that the CEMS or PEMS and the fuel flow meters must be used to demonstrate compliance with the source cap. New §117.423(c)(1)(C) specifies that for units not subject to continuous monitoring requirements, the owner or operator may use the maximum emission rate as measured during testing conducted according to new §117.435(d). New §117.423(c)(1)(C) also specifies that the emission rates for such units are limited to the maximum emission rates obtained from the testing. New §117.423(c)(2) specifies that for each unit equipped with a CEMS, the owner or operator shall either use a PEMS or the maximum emission rate measured by testing according to §117.435(d) to provide substitute emissions data when the CEMS is off-line. Methods specified in 40 CFR §75.46 are required for providing substitute data for PEMS.

New §117.423(d) requires daily records of NO _X emissions and total fuel usage for each unit under the source cap, as well as records of the total NO _X emissions summation and total fuel usage for all units under the source cap. In addition, the records must be maintained in accordance with the requirements of §117.445.

New §117.423(e) establishes procedures for the reporting of any emission exceedances of the source cap. The procedures are consistent with the reporting requirements under the existing source cap provisions of existing §117.223, including notification of the appropriate regional office within 48 hours, followed by a written report within 21 days, content requirements for the report, and semiannual reporting for monitoring systems. New §117.423(f) specifies that initial compliance with the source cap shall be demonstrated in accordance with the compliance schedule in §117.9030.

Conditions for including a permanently retired, decommissioned, or rendered inoperable unit in the source cap are specified in new §117.423(g). Paragraph (1) specifies that the shutdown must have occurred after December 31, 2000, and paragraph (2) specifies that the source cap emission limit must be calculated according to subsection (b). Paragraph (3) specifies that the actual heat input must be calculated according to subsection (b)(1). However, if the unit was not in service 24 consecutive months between January 1, 2000, and December 31, 2001, paragraph (3) specifies that the actual heat input must be the heat input used to represent the unit's emissions in the attainment demonstration modeling inventory. Also, the maximum heat input must be the maximum heat input certified by the executive director, allowed or possible (whichever is lower) in a 24-hour period. Paragraph (4) requires the owner or operator to certify the operational level and maximum rated capacity of the unit. Paragraph (5) prohibits emission reductions from shutdowns or curtailments used for netting or offsetting purposes under Chapter 116 from being included in the baseline for establishing the cap.

New §117.423(h) specifies that owners or operators who choose to use the source cap for compliance with §117.410 must include a plan for compliance in the initial control plan required in new §117.450. In addition, the owner or operator must include the identification of election to use the source cap option, identification of all sources included in the source cap, and the method of calculating the annual heat input for each unit included in the source cap. New §117.423(i) specifies the procedures for calculating the contributions from each affected unit under the source cap during a startup, shutdown, or emissions event as defined in §101.1.

Finally, the existing rules for major sources of NO _X in the Dallas-Fort Worth ozone nonattainment area provide an additional compliance option using the alternative plant-wide emission specification provisions of existing §117.207. The commission is not allowing the alternative plant-wide emission specifications approach for new Subchapter B, Division 4. A source cap approach provides more flexibility than the alternative plant-wide emission specifications because the owner or operator can choose which source categories to include under the source cap approach. The source cap option in new §117.423 provides sufficient flexibility that providing an additional alternative plant-wide emission specification option would have little or no benefit.

Section 117.425, Alternative Case Specific Specifications

The commission adopts a new §117.425 that provides procedures concerning alternative case specific specifications. New §117.425(a) specifies that where it can be demonstrated that an affected unit cannot attain the applicable requirements of the CO or ammonia specifications of new §117.410(c), the executive director may approve emission specifications different from the CO or ammonia specifications in §117.410(c) under the guidelines of new §117.425(a)(1) - (3). New paragraph (1) specifies that the executive director shall consider, on a case-by-case basis, the technological and economic circumstances of the individual unit. New paragraph (2) requires the executive director to determine whether the alternative emission specifications are the lowest specification the unit is capable of achieving after application of controls to meet the NO _X emission specifications of new §117.410. New paragraph (3) allows the executive director to consider plant-wide averaging to meet the emission specifications.

Finally, §117.425(b) specifies that any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision, and that the requirements of 30 TAC §50.139 (Motion to Overturn Executive Director's Decision) apply to §117.425. New subsection (b) also specifies that executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for EPA approval in some cases.

Section 117.430, Operating Requirements

The new §117.430 establishes operating requirements for sources subject to new Subchapter B, Division 4. New §117.430(a) requires an owner or operator who has chosen to use the source cap option in new §117.423 to comply with the emission specifications to operate affected units in compliance with those limitations.

New §117.430(b) requires that all units subject to the emission specifications of §117.410(a) or (b) or §117.423 must be operated to minimize NO_X emissions, consistent with the emission control techniques selected, over the unit's operating or load range during normal operations and subject to the operating requirements detailed in new §117.430(b)(1) - (7). Paragraph (1) requires boilers, except for wood-fired boilers, to be operated with O ₂ , CO, or fuel trim. Paragraph (2) requires boilers and process heaters controlled with forced FGR to be operated such that the proportional design rate of FGR is maintained over the operating range. Paragraph (3) requires boilers and process heaters controlled with induced draft FGR to be operated such that FGR over the operating range is not restricted. New paragraphs (4) and (5) specify that units controlled with steam or water injection or with post-combustion control must be operated such that the steam or water injection rate or chemical agent injection rate is maintained to limit NO _X concentrations to less than or equal to concentrations at maximum rated capacity. Paragraph (6) requires an automatic air-fuel ratio (AFR) controller, based on O₂ or CO control, be installed on engines controlled with NSCR and that the controller maintain the AFR within the range required to meet the applicable emission specification. Finally, paragraph (7) requires that each stationary internal combustion engine be tested for proper operation according to new §117.8140(b), which includes quarterly testing of NO_X and CO emissions. These operating requirements are consistent with the operating requirements specified under existing §117.208 for the Dallas-Fort Worth ozone nonattainment area.

Section 117.435, Initial Demonstration of Compliance

New §117.435 specifies the requirements for owners or operators of units subject to this division for demonstrating initial compliance with the rule. New §117.435(a) specifies that the owner or operator of any unit subject to the emission specifications of the division must test the unit. Paragraphs (1) and (2) specify that units must be tested for NO _X , CO, and O ₂ and that units that inject urea or ammonia for NO _X control must be tested for ammonia emissions. Paragraph (3) specifies that the testing must be performed in accordance with the compliance schedule in new §117.9030.

New §117.435(b) specifies that compliance tests required by new §117.435(a) must be performed using the methods referenced in new §117.435(d) or (e) and used for determination of initial compliance with the emission specifications of the division and must be in the units of the applicable emission specifications and averaging periods. New §117.435(c) requires that any CEMS or PEMS required by new §117.440 must be installed and operational before conducting the initial demonstration of compliance testing and specifies the minimum requirements for verifying operational status of the CEMS or PEMS.

New §117.435(d) references new §117.8000 for the compliance test requirements for units operating without CEMS or PEMS. New §117.435(e) specifies the requirements of initial compliance testing for units operating with CEMS or PEMS in accordance with §117.440. The initial demonstration of compliance is performed using the CEMS or PEMS after monitor certification.

New paragraphs (1) - (4) specify the procedures for the initial demonstration of compliance using CEMS or PEMS, depending on the unit type, pollutant, applicable averaging time, or whether the unit is included in the optional source cap in new §117.423.

New §117.435(f) references the information that must be included in compliance stack reports as specified by §117.8010 (Compliance Stack Reports).

Section 117.440, Continuous Demonstration of Compliance

The commission adopts a new §117.440, concerning continuous demonstration of compliance, that specifies the operating, monitoring, and testing required by owners and operators of units subject to the emissions specifications of §117.410 and §117.423. New §117.440(a) requires the installation, calibration, maintenance, and operation of totalizing fuel flow meters for owners and operators of affected units. Based on comments received, the commission has revised §117.440(a) to specify that the owner or operator must continuously operate the totalizing fuel flow meter at least 95% of the time when the unit is operating, averaged over a calendar year. As discussed elsewhere in this preamble, the provision is to allow owners and operators time to perform maintenance and calibration on the fuel meters. Adopted §117.440(a)(1) specifies the units that are subject to the fuel metering requirements of new §117.440(a). These units include: boilers; process heaters; duct burners used in turbine exhaust ducts; stationary, reciprocating internal combustion engines; stationary gas turbines; lime kilns; brick and ceramic kilns; heat treating furnaces; reheat furnaces; lead smelting blast (cupola) and reverberatory furnaces; glass and fiberglass melting furnaces; incinerators (excluding vapor streams resulting from vessel cleaning routed to an incinerator); glass, fiberglass, and mineral wool curing ovens; natural gas-fired ovens and heaters; and natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic, calcining, and vitrifying processes. As discussed elsewhere in this preamble, electric arc furnaces used in steel production as well as fiberglass and mineral wool forming ovens are exempt from the adopted rule. Therefore, these unit types are excluded from §117.440(a)(1) and the subparagraphs have been renumbered accordingly. In addition, the language in proposed subparagraph (P), adopted as subparagraph (O), regarding types of natural gas-fired dryers is revised to be consistent with the changes in §117.400(11).

New §117.440(a)(2) lists the alternatives to the fuel flow monitoring requirements. Subparagraph (A) allows units operating with NO _X and diluent CEMS to monitor exhaust gas flow rate using 40 CFR Part 60, Appendix B, Performance Specification 6, or 40 CFR Part 75, Appendix A. Subparagraph (B) allows units that vent to a common stack with a NO _X and diluent CEMS to share a single totalizing fuel flow meter. Subparagraph (C) allows diesel engines operating with run time meters to satisfy the fuel monitoring requirements through monthly fuel use records maintained for each engine. In addition, based on comments received, the commission has added a new subparagraph (D) to provide an additional alternative to installing fuel meters for stationary reciprocating internal combustion engines. The new subparagraph (D) allows owners or operators to use a continuous monitoring system that continuously monitors horsepower and hours of operation as an alternative to the fuel meters. The monitoring system must be installed, calibrated, maintained, and operated according to the manufacturers' recommended procedures.

New §117.440(b) requires owners or operators to install, calibrate, maintain, and operate O ₂ monitors for certain units. New §117.440(b)(1) requires O ₂ monitors on units in subparagraphs (A) and (B) that are operated with an annual heat input greater than 2.2(10 ¹¹ ) British thermal units per year. Boilers with a rated heat input greater than or equal to 100 MMBtu/hr are included in paragraph (A). Process heaters with a rated heat input greater than or equal to 100 MMBtu/hr are specified in paragraph (B), with exceptions provided in clauses (i) and (ii). The O ₂ monitors required under new §117.440(b) are for process monitoring purposes and new §117.440(b)(2) specifies that the monitors are only required to meet the CEMS requirements of subsection (f) if O ₂ is the monitored diluent under subsection (f). If new monitors are required under new §117.440(b), the procedures referenced in §117.440(f) are the appropriate guidance for the monitor location and calibration.

New §117.440(c) specifies the units for which owners and operators shall install, calibrate, maintain, and operate a CEMS or PEMS to monitor NO _X exhaust. The units listed include: units with a rated heat input greater than or equal to 100 MMBtu/hr that are subject to new §117.410(b); stationary gas turbines with a MW rating greater than or equal to 30 MW operated more than 850 hours per year; units that use a chemical reagent for reduction of NO _X ; units that the owner or operator elects to comply with the NO _X emission specifications using a lb/MMBtu limit on a 30-day rolling average; lime kilns; and brick kilns and ceramic kilns. These new monitoring requirements are anticipated to require some owners or operators to install CEMS or PEMS on units that currently do not have CEMS or PEMS. The continuous NO _X monitoring requirements are necessary to ensure compliance with the emission specifications on certain larger units, units that use chemical agents for NO _X control, and units, such as kilns, that are anticipated to have variable emissions. New §117.440(c)(2) exempts units subject to the NO _X CEMS requirements of 40 CFR Part 75 because the Acid Rain NO_X monitoring requirements meet or exceed the minimum requirements in §117.440. In addition, new §117.440(c)(3) specifies the methods to be used to provide substitute emissions compliance data during periods when the NO _X monitors are off-line.

New subsection §117.440(d) adds an ammonia monitoring requirement for any unit subject to new §117.410(b) and (c)(2) and references §117.8130 for allowed ammonia monitoring methods. Engines subject to new §117.410(a), the emission specifications from existing §117.206(b)(3), are not currently subject to ammonia monitoring requirements under the existing rule. The commission is not retroactively imposing this ammonia monitoring requirement on sources subject to existing §117.206(b)(3). Therefore, new §117.440(d) excludes sources subject to new §117.410(a).

New §117.440(e) specifies that all owners or operators of unit types listed in §117.440(c)(1) shall monitor CO according to the requirements of new §117.8120. New §117.440(f) specifies that CEMS used for compliance with this section must be operated within the requirements of new §117.8100(a). New §117.440(g) specifies that PEMS used to satisfy the monitoring requirements of §117.440 must predict the pollutant emissions in the units of the applicable emission specification and comply with the requirements of new §117.8100(b). The CEMS and PEMS requirements in new §117.8100 are the existing requirements for CEMS and PEMS incorporated from existing §117.213.

New §117.440(h) specifies that the owner or operator of stationary internal combustion engines not equipped with a CEMS or PEMS must comply with the monitoring requirements of §117.8140(a). Under §117.8140(a), engines are required to be tested biennially, or within 15,000 hours of operation, similar to the current requirement under existing §117.213(g).

New §117.440(i) requires the owner or operator of any stationary gas turbine or stationary internal combustion engine claimed exempt using the exemption in new §117.403(a)(7)(D), (a)(8), or (a)(9) to record the operating time with a non-resettable elapsed run time meter. New §117.440(j), concerning data used for compliance, specifies that the methods required in new §117.440 must be used to demonstrate compliance with the emission specifications after the initial demonstration of compliance. The provisions of subsection (j) also specify that the executive director may use other commission compliance methods to determine compliance with the emission specifications.

Finally, new §117.440(k) specifies the testing and retesting requirements for units subject to the emission specifications of §117.410. Paragraph (1) specifies that the owner or operator of units that are subject to the emission specifications of §117.410(a) shall test the units as specified in §117.435 in accordance with the schedule specified in new §117.9030(a). Paragraph (2) requires the owner or operator of units subject to the emission specifications of new §117.410(b) to test the units as specified in §117.435 in accordance with the schedule specified in new §117.9030(b). A retesting requirement is specified in paragraph (3) that requires owners or operators to retest any unit subject to the emission specifications of new §117.410(b) after any modification that could be reasonably expected to increase the NO_X emission rate. This retesting provision only applies to units that are not equipped with CEMS or PEMS to monitor NO _X emissions.

Section 117.445, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.445 that specifies the notification, recordkeeping, and reporting requirements for units subject to the emission specifications of this division. New §117.445(a), concerning startup and shutdown records, specifies the recordkeeping requirements for units subject to the startup and/or shutdown provisions of §101.222. The record retention and minimum content requirements are specified in new subsection (a). Subsection (a) also specifies that records must be made available for inspection upon request by the executive director, EPA, and any local air pollution control agency having jurisdiction.

Notification requirements are specified in new §117.445(b). New §117.445(b) requires notification be provided to the appropriate regional office and any local air pollution agency having jurisdiction. The specific notification requirements are listed in new §117.445(b)(1) and (2). Paragraph (1) specifies the notification requirements for units subject to the emission specifications of §117.410(a). Section 117.445(b)(1)(A) requires verbal notification of the date of any testing conducted under new §117.435 at least 15 days prior to the date of testing followed by written notification within 15 days after testing is completed. Section 117.445(b)(1)(B) requires verbal notification of the date of any CEMS or PEMS relative accuracy test audit (RATA) conducted under §117.440 at least 15 days prior to such date followed by written notification within 15 days after testing is completed. The notification requirements specified in new §117.445(b)(2) are applicable to units subject to the emission specifications in new §117.410(b). Under new §117.445(b)(2), written notice is required at least 15 days in advance of the date of any RATA conducted under §117.440 or test conducted under §117.435. The commission is adopting the single written notification requirement under new §117.445(b)(2) to eliminate the requirement for redundant notifications for units subject to the emissions specification in §117.410(b). However, units subject to §117.410(a) are currently regulated under existing §117.206(b)(3) and subject to the existing notification requirements of existing §117.219(b). The notification requirements in new §117.445(b)(1) are identical to the requirements in existing §117.219(b) to maintain consistency with the current requirements applicable to owners or operators subject to new §117.410(a).

New §117.445(c), concerning reporting of test results, specifies the owner or operator of an affected unit shall furnish the Office of Compliance and Enforcement, the appropriate regional office, and any local air pollution control agency having jurisdiction a copy of any testing conducted under §117.435 and any CEMS or PEMS RATA conducted under §117.440. Reports must be submitted within 60 days after completion of such testing or evaluation and not later than the compliance schedule specified in new §117.9030.

New subsection §117.445(d), concerning semiannual reports, requires the owner or operator of a unit required to install a CEMS or PEMS under §117.440 to report in writing to the executive director on a semiannual basis any exceedance of the applicable emission specifications and the associated monitoring system performance. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. The information required in the reports is detailed in new §117.445(d)(1) - (5). Paragraph (1) requires the magnitude of excess emissions, computed according to 40 CFR §60.13(h), to be reported, as well as conversion factors used, time period of excess emissions, and unit operating time during the reporting period. Provisions for sources subject to the source cap in new §117.423 are also given. Paragraph (2) lists report requirements for excess emissions during startups, shutdowns, and malfunctions, and paragraph (3) lists report requirements for periods when continuous monitoring systems are inoperative. If no excess emissions or downtime have occurred during the reporting period, paragraph (4) specifies that the report must indicate that no excess emissions or monitoring downtime have occurred. Paragraph (5) provides conditions for summary reports if excess emissions and monitor downtime are limited.

New §117.445(e) specifies the semiannual reporting requirements for owners and operators of any gas-fired engines. Written reports of excess emissions and the air-fuel ratio monitoring system performance must be submitted to the executive director. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. Additional specific information required in the reports is detailed in paragraphs (1) and (2) similar to the current requirements specified in the existing §117.219(e)(1) and (2) for engine semiannual reports.

New §117.445(f), concerning recordkeeping, specifies requirements for written or electronic records for owners or operators of units subject to the requirements of this division. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, EPA, or local air pollution control agencies having jurisdiction. New §117.445(f)(1) specifies that for each unit subject to §117.440(a) the records must include records of annual fuel usage. For each unit using a CEMS or PEMS in accordance with §117.440, new §117.445(f)(2) requires monitoring records of hourly emissions and fuel usage for units complying on a block one-hour average or daily emissions and fuel usage for units complying with an emission specification enforced on a daily or rolling 30-day average.

For stationary internal combustion engines subject to the emission specifications of the division, new §117.445(f)(3) requires the owner or operator to maintain records of emissions measurements required by §117.430(b)(7) and §117.440(h), as well as catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken. In addition, adopted §117.445(f)(3) also includes a new subparagraph (C) that requires records of daily average horsepower and total daily hours of operation for each engine that the owner or operator elects to use the alternative monitoring system allowed under new §117.440(a)(2)(D). These new recordkeeping requirements are necessary to demonstrate compliance for owner or operators the choose to use the alternative monitoring system in lieu of the fuel metering requirements.

New §117.445(f)(4) specifies owners or operators of units claimed exempt from emission specifications using the exemption of §117.403(a)(7)(D), (a)(8), or (a)(9) must maintain records of monthly hours of operation for exemptions based on hours per year of operation. In addition, for each engine claimed exempt under §117.403(a)(7)(D), written records must be maintained of the purpose of engine operation and if operation was for an emergency situation, identification of the type, start and end times, and dates of the emergency situation.

New §117.445(f)(5) and (6) require owners or operators of applicable units to maintain records of ammonia and CO measurements specified in §117.440(d) and (e), respectively. New §117.445(f)(7) requires owners or operators of units operating with CEMS or PEMS to maintain records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance.

New §117.445(f)(8) requires owners or operators to maintain records of the results of performance testing, including initial demonstration of compliance testing conducted in accordance with new §117.435. New §117.445(f)(9) specifies owners or operators of each stationary diesel or dual-fuel engine to maintain records of each time the engine is operated for testing and maintenance, including dates of operation, start and end times of operation, identification of the engine, and total hours of operation for each month and for the most recent 12 consecutive months.

Adopted §117.445(f) also includes a new paragraph (10) that specifies recordkeeping requirements for lime kilns that comply with the site-wide production rate weighted average emission specification in §117.410(b)(7)(A)(ii). New §117.445(f)(10) requires daily records of average NO _X emission rates in lb/ton of CaO for each kiln, production rate of CaO for each kiln in tpd, and the site-wide production rate weighted average NO _X emission rate in lb/ton of CaO.

Section 117.450, Initial Control Plan Procedures

The commission adopts a new §117.450, concerning initial control plan procedures. New §117.450(a) requires the owner or operator of any unit at a major source of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area that is subject to §117.410(b) to submit an initial control plan. New §117.450(a)(1) specifies that the control plan must include a list of all combustion units at the account that are listed in §117.410(b). The list must include for each unit the maximum rated capacity, anticipated annual capacity factor, estimated or measured NO _X emission data in the units associated with the category of equipment from §117.410(b), the method of determination for the NO _X emission data, the facility identification number and emission point number as submitted to the Industrial Emissions Assessment Section of the commission, and the emission point number as listed on the Maximum Allowable Emissions Rate Table of any applicable commission permit.

New §117.450(a)(2) requires the initial control plan to include the identification of all units with a claimed exemption from the emission specifications in §117.410(b) and the rule basis for the claimed exemption. New §117.450(a)(3) requires the initial control plan to include the identification of the election to use the source cap emission limit in §117.423 to achieve compliance with this rule and a list of the units to be included in the source cap.

New §117.450(a)(4) requires the initial control plan to include a list of units to be controlled and the type of control to be applied for each unit, including an anticipated construction schedule. New §117.450(a)(5) requires the initial control plan to include a list of units requiring operating modifications to comply with §117.430(b) and the type of modification to be applied for each unit, including an anticipated construction schedule. New §117.450(a)(6) specifies that for units required to install totalizing fuel flow meters in accordance with §117.440(a), the initial control plan must indicate whether the fuel meters are currently in operation, and if so, whether they have been installed as a result of the requirements of this rule.

New §117.450(a)(7) specifies that for units required to install CEMS or PEMS in accordance with §117.440, the initial control plan must indicate whether the devices are currently in operation, and if so, whether they have been installed as a result of the requirements of this rule.

New §117.450(b) specifies the initial control plan must be submitted to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office by the applicable date specified for initial control plans in new §117.9030(b). Control plans submitted to the Chief Engineer's Office should be submitted to the attention of the Air Quality Planning Section.

Finally, new §117.450(c) specifies that for units located in Dallas, Denton, Collin, and Tarrant Counties, subject to new §117.210, the owner or operator may elect to submit the most recent revision of the final control plan required by new §117.254 in lieu of the initial control plan required by subsection (a).

Section 117.454, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.454 that requires the owner or operator of any unit subject to new §117.410(b) at a major source of NO _X to submit a final control report to show compliance with the requirements of §117.410.

New §117.454(a)(1) - (5) specify the content requirements of the report. The final control report must identify which sections are used to demonstrate compliance. In addition, the report must include: the method of NO _X control for each unit; the emissions measured by testing required in §117.435; the submittal date, and whether sent to the central or the regional office (or both), of any compliance stack test report or RATA report required by §117.435 not being submitted concurrently with the final compliance report; and the specific rule citation for any unit with a claimed exemption from the emission specifications of §117.410.

New §117.454(b)(1) - (3) specifies that for sources complying with §117.423, in addition to the requirements of subsection (a), the owner or operator shall submit: the calculations used to calculate the 30-day average and maximum daily source cap allowable emission rates; the average daily heat input, H_i , specified in §117.423(b)(1); the maximum daily heat input, H _mi , specified in §117.423(b)(1); the method of monitoring emissions; the method of providing substitute emissions data when the NO _X monitoring system is not providing valid data; and an explanation of the basis of the values of H _i and H _mi .

New §117.454(c) specifies the report must be submitted to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office by the applicable date specified for final control plans in §117.9030(b). Control plans submitted to the Chief Engineer's Office should be submitted to the attention of the Air Quality Planning Section. The plan must be updated with any emission compliance measurements submitted for units using CEMS or PEMS and complying with the source cap rolling 30-day average emission limit, according to the applicable schedule given in §117.9030.

Section 117.456, Revision of Final Control Plan

The commission adopts a new §117.456, concerning revision of final control plan, to specify the conditions under which a revised final control plan may be submitted by the owner or operator, along with any required permit applications. The section specifies that such a plan must adhere to the requirements and the final compliance dates of the division, and that for sources complying with §117.410, replacement new units may be included in the control plan. Also, for sources complying with §117.423, any new unit must be included in the source cap if the unit belongs to an equipment category that is included in the source cap. Finally, new §117.456 specifies that the revision of the final control plan is subject to the review and approval of the executive director.

SUBCHAPTER C, COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

The commission adopts a new Chapter 117, Subchapter C, entitled Combustion Control at Major Utility Electric Generation Sources in Ozone Nonattainment Areas, that incorporates the rule language from existing Chapter 117, Subchapter B, Combustion at Major Sources, Division 1, Utility Electric Generation in Ozone Nonattainment Areas. The new Subchapter C is structured based on regional nonattainment areas. Each new division applies only to a specific ozone nonattainment area. Rule language from existing Subchapter B, Division 1 that is not applicable for the specific region is not included in the new division for that specific region. Unless otherwise specified in this preamble, such exclusions of rule language not applicable to the specific region are considered non-substantive changes and are not specifically discussed in the preamble.

In addition, the commission adopts a new Subchapter C, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, that includes new rule language and requirements associated with major utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. The new Subchapter C, Division 4 is a part of the commission's eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area.

DIVISION 1, BEAUMONT-PORT ARTHUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

The commission adopts a new Chapter 117, Subchapter C, Division 1, entitled Beaumont-Port Arthur Ozone Nonattainment Area Utility Electric Generation Sources, that incorporates the provisions in the existing Chapter 117, Subchapter B, Division 1, applicable to utility electric generation sources in the Beaumont-Port Arthur ozone nonattainment area.

Section 117.1000, Applicability

The commission adopts a new §117.1000 that incorporates the applicability rule language in existing §117.101 applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1000(a) incorporates the rule language in the existing §117.101(a) and (a)(1) - (4). The list of applicable units in existing §117.101(a)(1) - (4), including utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts, is incorporated into the new §117.1000(a). New §117.1000(a)(1) and (2) incorporate the language regarding owners or operators of the applicable units. New §117.1000(a)(1) incorporates the rule language from existing §117.101(a) concerning the applicability related to units owned or operated by a municipality or a PUC-regulated utility. In addition, the commission adopts a new §117.1000(a)(2) concerning the applicability of the division to electric power generating systems owned or operated by an electric cooperative, municipality, river authority, or public utility. This change is intended to clarify the applicability of the rule and does not expand the applicability of the rule. Based on comments received and as discussed elsewhere in this preamble, independent power producers were removed from adopted §117.1000(a)(2) to avoid a potential expansion in the applicability. Finally, the commission also adopts a new §117.1000(b) that incorporates the rule language in existing §117.101(b).

Section 117.1003, Exemptions

The commission adopts a new §117.1003 that incorporates the exemptions in the existing §117.103 applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1003(a) - (c) incorporate the exemptions in the existing §117.103(a) - (c). In addition, for new §117.1003(c)(1), the commission revises the existing language in §117.103(c)(1) to expand the provisions relating to emergency fuel oil firing exemptions to emergency operating conditions declared by the Southeastern Electric Reliability Council, and to remove reference to the Southwest Power Pool. This change is necessary because the Southeastern Electric Reliability Council area overlaps the Beaumont-Port Arthur ozone nonattainment area. The Southwest Power Pool area does not apply to the Beaumont-Port Arthur ozone nonattainment area.

Section 117.1005, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.1005 that incorporates the rule language in the existing §117.105, relating to emission specifications for RACT, applicable to the Beaumont-Port Arthur ozone nonattainment area. The commission adopts a new §117.1005(a) - (l) that incorporates the rule language in the existing §117.105(a) - (l).

The commission adopts a new equation in §117.1005(d) that incorporates the existing equation for calculating the rolling 24-hour heat input weighted average emission specification in the existing §117.105(d). The new equation in §117.1005(d) presents the equation in a format consistent with other figures in Chapter 117 and provides a written description of all the terms used in the equation. In addition, for new §117.1005(e), the commission uses the term auxiliary steam boilers as opposed to auxiliary boilers used in the existing language to be consistent with the definition in §117.10. For new §117.1005(i), the commission changes the word "ten" to the numeral "10" regarding the MW rating for stationary gas turbines subject to the CO emission specification in new §117.1005(i). Finally, new §117.1005(l) incorporates the rule language from existing §117.105(l) and (l)(1).

Section 117.1010, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.1010 that incorporates the rule language in the existing §117.106, relating to emission specifications for attainment demonstrations, applicable to the Beaumont-Port Arthur ozone nonattainment area.

The commission adopts a new §117.1010(a), relating to NO _X emission specifications, that incorporates the rule language and emission specifications in the existing §117.106(a). New §117.1010(b) incorporates the rule language concerning related emissions in the existing §117.106(d). In addition, for new §117.1010(b)(2), the commission changes the emissions specification for ammonia from the word "ten" to the numeral "10." As previously discussed in this preamble, this change is necessary to ensure consistent enforcement of the emission specification. New §117.1010(c), relating to compliance flexibility, incorporates the rule language in the existing §117.106(e) and (e)(1) - (3).

Section 117.1015, Alternative System-Wide Emission Specifications

The commission adopts a new §117.1015 that incorporates the rule language in the existing §117.107, relating to alternative system-wide emission specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area. The commission adopts a new §117.1015(a) - (d) that incorporate the rule language in the existing §117.107(a) - (d). In addition, for new §117.1015, the commission is revising language in existing §117.107 referencing system-wide emission limit or system-wide emission limitation to specify system-wide emission specification. These changes are to provide consistency and clarity in new §117.1015 and to be consistent with the section title and the change to the definition of system-wide emission limit in §117.10 discussed previously in this preamble.

New §117.1015(d) incorporates the rule language from existing §117.107(d). In addition, existing §117.107(d)(1) and (2) include required calculations written in paragraph form rather than in equation form. The commission is reformatting the calculations in a mathematical formula rather than the paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new equations are identical in content to the existing required calculations in paragraph form. The new equation in §117.1015(d)(1) incorporates the calculation for allowable system-wide NO _X emission specification for each affected utility boiler in the existing §117.107(d)(1). The new equations in §117.1015(d)(2) incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.107(d)(2) as well as the existing equation for the in-stack NO _X concentration term in the existing §117.107(d)(2).

Section 117.1020, System Cap

The commission adopts a new §117.1020 that incorporates the rule language in the existing §117.108, relating to system cap, applicable to the Beaumont-Port Arthur ozone nonattainment area. The commission adopts new §117.1020(a) - (k) that incorporate the rule language in the existing §117.108(a) - (k). In addition, the commission adopts new equations in §117.1020(c) that incorporate the equations in existing §117.108(c) and present the equations in a format consistent with other equations in Chapter 117. The new equations in §117.1020(c) include only the information applicable to the Beaumont-Port Arthur ozone nonattainment area. The new equation in §117.1020(c)(1) incorporates the equation for the rolling 30-day average emission cap in the existing §117.108(c)(1). The new equation in §117.1020(c)(2) incorporates the equation for the maximum daily emission cap in the existing §117.108(c)(2).

The commission adopts a new §117.1020(k) that incorporates the requirements of the existing §117.108(k). The new §117.1020(k) changes source cap to system cap to be consistent with the section. Also, for new §117.1020(k), the commission replaces upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions) . . .." This change is necessary to update the rule to current terminology used by the commission.

The commission adopts a new §117.1020(l) relating to the use of emissions credits, that incorporates the rule language from existing §117.109, System Cap Flexibility. New §117.1020(m) relating to the sale and transfer of an electric generating system, incorporates the rule language from existing §117.110, Change of Ownership-System Cap.

Section 117.1025, Alternative Case Specific Specifications

The commission adopts a new §117.1025 that incorporates the rule language in the existing §117.121, relating to alternative case specific specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1025(a) and (b) incorporate the rule language in the existing §117.121(a) and (b). In addition, the new §117.1025(a) omits the provision in the existing §117.121(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.1035, Initial Demonstration of Compliance

The commission adopts a new §117.1035 that incorporates the rule language in the existing §117.111, relating to initial demonstration of compliance, applicable to the Beaumont-Port Arthur ozone nonattainment area.

Section 117.1040, Continuous Demonstration of Compliance

The commission adopts a new §117.1040 that incorporates the rule language in the existing §117.113, relating to continuous demonstration of compliance, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1040(a) incorporates the rule language in the existing §117.113(a), relating to NO _X monitoring. New §117.1040(b) incorporates the CO monitoring requirements from existing §117.113(b). The specific requirements and methods in the existing §117.113(b) appear in the new §117.8120, relating to CO monitoring, and subsequently have been omitted from new §117.1040(b) and replaced with a reference to the new §117.8120. Similarly, the requirements for CEMS in the existing §117.113(c)(1) and (2) appear in the new §117.8110(a), relating to emission monitoring system requirements for utility electric generation sources. Therefore, the new §117.1040(c) omits the specific requirements of existing §117.113(c)(1) and (2) and references to the new §117.8110(a).

New §117.1040(d) incorporates the rule language from existing §117.113(d), concerning acid rain peaking units. New §117.1040(e) incorporates the rule language from existing §117.113(e), concerning auxiliary boilers. In addition, for new §117.1040(e), the commission revises the term auxiliary boiler to auxiliary steam boiler to be consistent with the definition in §117.10.

The commission adopts a new §117.1040(f) that incorporates the requirements for PEMS from existing §117.113(f). New §117.1040(f)(1) incorporates the rule language from existing §117.113(f)(1). The requirements in the existing §117.113(f)(2) - (4) appear in the new §117.8110(b), relating to emission monitoring system requirements for utility electric generation sources, and subsequently have been omitted from the new §117.1040(f) and replaced with a reference to §117.8110(b) in new §117.1040(f)(2).

New §117.1040(g) - (j) incorporate the rule language applicable to the Beaumont-Port Arthur ozone nonattainment area from existing §117.113(g) - (j), respectively. New §117.1040(k) incorporates the rule language from existing §117.113(k) and (k)(1), and new §117.1040(l) incorporates the rule language from existing §117.113(l).

Section 117.1045, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.1045 that incorporates the requirements in the existing §117.119, relating to notification, recordkeeping, and reporting requirements, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1045(a) - (e) incorporate the rule language from existing §117.119(a) - (e). In addition, for new §117.1045(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.1045(a).

Section 117.1052, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.1052 that incorporates the rule language in the existing §117.115, relating to final control plan procedures for RACT, applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.1052(a), (b), and (c) incorporate the rule language from existing §117.115(a), (b) and (d), respectively. In addition, the commission revises the section title reference in new §117.1052(a)(2)(B) to reference the correct title "Alternative System-Wide Emission Specifications." Also, the commission omits the existing §117.115(c), relating to electronic submission and formatting requirements for the control plan, from the new §117.1052. Existing §117.115 and new §117.1052 specify the content requirements for the control plan. Therefore, a mandatory format for the control plan information is not necessary.

Section 117.1054, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.1054 that incorporates the rule language in the existing §117.116, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Beaumont-Port Arthur ozone nonattainment area.

Section 117.1056, Revision of Final Control Plan

The commission adopts a new §117.1056 that incorporates the rule language in the existing §117.117, relating to revision of final control plan, applicable to the Beaumont-Port Arthur ozone nonattainment area.

DIVISION 2, DALLAS-FORT WORTH OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

The commission adopts a new Chapter 117, Subchapter C, Division 2, entitled Dallas-Fort Worth Ozone Nonattainment Area Utility Electric Generation Sources, that incorporates the rule language in the existing Chapter 117, Subchapter B, Division 1 applicable to utility electric generation sources in the Dallas-Fort Worth ozone nonattainment area.

Section 117.1100, Applicability

The commission adopts a new §117.1100 that incorporates the applicability rule language in the existing §117.101 applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.1100(a) incorporates the rule language in the existing §117.101(a) and (a)(1) - (4). The list of applicable units in existing §117.101(a)(1) - (4), including utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts, is incorporated into the new §117.1100(a). New §117.1100(a)(1) and (2) incorporate the language regarding owners or operators of the applicable units. New §117.1100(a)(1) incorporates the rule language from existing §117.101(a) concerning the applicability related to units owned or operated by a municipality or a PUC-regulated utility. In addition, the commission adopts a new §117.1100(a)(2) concerning the applicability of the division to electric power generating systems owned or operated by an electric cooperative, independent power producer, municipality, river authority, or public utility. As previously indicated in this preamble, this change is intended to clarify the applicability of the rule and does not expand the applicability of the rule. Based on comments received and as discussed elsewhere in this preamble, independent power producers were removed from adopted §117.1100(a)(2) to avoid a potential expansion in the applicability. The commission adopts a new §117.1100(b) that incorporates the rule language in existing §117.101(b).

Finally, the commission adopts a new §117.1100(c) that specifies the provisions of the new Subchapter C, Division 2 no longer apply to any electric generating facility in Collin, Dallas, Denton, and Tarrant Counties that is subject to the emission specifications in new §117.1310, after the appropriate date in the new §117.9130, relating to the compliance schedule for Dallas-Fort Worth eight-hour ozone nonattainment area utility electric generation sources. The emission specifications in new §117.1310 and all other associated requirements in the new Subchapter C, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, discussed later in this preamble, supersede the requirements of Subchapter C, Division 2 after the compliance date for the new rules in Subchapter C, Division 4. Therefore, the commission adopts new §117.1100(c) to avoid overlapping requirements from the two separate divisions.

Section 117.1103, Exemptions

The commission adopts a new §117.1103 that incorporates the exemptions in the existing §117.103, relating to exemptions for utility electric generation sources in ozone nonattainment areas, applicable to the Dallas-Fort Worth ozone nonattainment area. The commission adopts a new §117.1103(a) - (c) that incorporate the rule language in the existing §117.103(a) - (c). In addition, for new §117.1103(c)(1), relating to emergency fuel oil firing exemptions, the commission omits reference to the Southwest Power Pool for the emergency fuel oil firing exemption provisions because the Southwest Power Pool area does not apply to the Dallas-Fort Worth ozone nonattainment area.

Section 117.1105, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.1105 that incorporates the rule language in the existing §117.105, relating to emission specifications for RACT, applicable to the Dallas-Fort Worth ozone nonattainment area. The commission adopts a new §117.1105(a) - (l) that incorporate the rule language in the existing §117.105(a) - (l).

The commission adopts a new equation in §117.1105(d) that incorporates the existing equation for calculating the rolling 24-hour heat input weighted average emission specification in the existing §117.105(d). The new equation in §117.1105(d) presents the equation in a format consistent with other figures in Chapter 117 and provides a written description of all the terms used in the equation. In addition, for new §117.1105(e), the commission uses the term auxiliary steam boilers as opposed to auxiliary boilers used in the existing language to be consistent with the definition in §117.10. For new §117.1105(i), the commission changes the word "ten" to the numeral "10" regarding the MW rating for stationary gas turbines subject to the CO emission specification in new §117.1105(i). Finally, new §117.1105(l) incorporates the rule language from existing §117.105(l) and (l)(2).

Section 117.1110, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.1110 relating to emission specifications for attainment demonstration, that incorporates the rule language in the existing §117.106, relating to emission specifications for attainment demonstrations, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.1110(a), relating to NO _X emission specifications, incorporates the emission specifications and rule language in the existing §117.106(b). In addition, for new §117.1110(a)(1) and (2), the commission changes the terms large DFW system and small DFW system in existing §117.106(b) to large utility system and small utility system to be consistent with the changes to the definitions in new §117.10(24) and (44). New §117.1110(a)(1) incorporates the existing emission specification for boilers that are part of a large utility system, as defined in the new §117.10(24), and new §117.1110(a)(2) incorporates the existing emission specification for boilers that are part of a small utility system, as defined in new §117.10(44). Both new §117.1110(a)(1) and (2) incorporate the provisions from existing §117.106(b) concerning use of system cap and use of emission credits for compliance. In addition, new §117.1110(a)(2) incorporates the provision in existing §117.106(b) that specifies that the annual heat input exemption is not applicable to a small utility system. The reference in existing §117.106(b) also incorrectly references §117.103(2) for this heat input exemption. Therefore, for new §117.1110(a)(2), the commission revises the reference to cite new §117.1103(a)(2), the correct reference for the annual heat input exemption.

The commission adopts a new §117.1110(b) that incorporates the rule language concerning related emissions in the existing §117.106(d). In addition, for new §117.1110(b)(2), the commission changes the emissions specification for ammonia from the word "ten" to the numeral "10." As previously discussed in this preamble, this change is necessary to ensure consistent enforcement of the emission specification. Finally, new §117.1110(c), relating to compliance flexibility, incorporates the rule language in the existing §117.106(e) and (e)(1) - (3).

Section 117.1115, Alternative System-Wide Emission Specifications

The commission adopts a new §117.1115 that incorporates the specifications in the existing §117.107, relating to alternative system-wide emission specifications, applicable to the Dallas-Fort Worth ozone nonattainment area.

The commission adopts a new §117.1115(a) - (d) that incorporates the rule language in the existing §117.107(a) - (d). In addition, for new §117.1115, the commission is revising language in existing §117.107 referencing system-wide emission limit or system-wide emission limitation to specify system-wide emission specification. These changes are to provide consistency and clarity in new §117.1115 and to be consistent with the section title and the change to the definition of system-wide emission limit in §117.10 discussed previously in this preamble.

New §117.1115(d) incorporates the rule language from existing §117.107(d). In addition, existing §117.107(d)(1) and (2) include required calculations written in paragraph form rather than in equation form. The commission is reformatting the calculations in a mathematical formula rather than the paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new equations are identical in content to the existing required calculations in paragraph form. The new equation in §117.1115(d)(1) incorporates the calculation for allowable system-wide NO _X emission specification for each affected utility boiler in the existing §117.107(d)(1). The new equations in §117.1115(d)(2) incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.107(d)(2), as well as the existing equation for the in-stack NO _X concentration term in the existing §117.107(d)(2).

Section 117.1120, System Cap

The commission adopts a new §117.1120 that incorporates the requirements in the existing §117.108, relating to system cap, applicable to the Dallas-Fort Worth ozone nonattainment area.

The commission adopts new §117.1120(a) - (k) that incorporate the rule language in the existing §117.108(a) - (k). In addition, the commission adopts new equations in §117.1120(c) that incorporate the equations in existing §117.108(c) and present the equations in a format consistent with other equations in Chapter 117. The new equations in §117.1120(c) include only the information applicable to the Dallas-Fort Worth ozone nonattainment area. The new equation in §117.1120(c)(1) incorporates the equation for the rolling 30-day average emission cap in the existing §117.108(c)(1). The new equation in §117.1120(c)(2) incorporates the equation for the maximum daily emission cap in the existing §117.108(c)(2).

The commission adopts a new §117.1120(k) that incorporates the requirements of the existing §117.108(k). The new §117.1120(k) changes source cap to system cap to be consistent with the section. Also, for new §117.1120(k), the commission replaces the term upset period with the language "emissions events, as defined in §101.1 of this title (relating to Definitions)." This change is necessary to update the rule to current terminology used by the commission.

The commission adopts a new §117.1120(l) relating to the use of emissions credits, that incorporates the rule language from existing §117.109, concerning system cap flexibility. New §117.1120(m), relating to the sale and transfer of an electric generating system, incorporates the rule language from existing §117.110, concerning change of ownership.

Section 117.1125, Alternative Case Specific Specifications

The commission adopts a new §117.1125 that incorporates the specifications in the existing §117.121, relating to alternative case specific specifications, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.1125(a) and (b) incorporate the rule language in the existing §117.121(a) and (b). In addition, the new §117.1125(a) omits the provision in the existing §117.121(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.1135, Initial Demonstration of Compliance

The commission adopts a new §117.1135 that incorporates the requirements in the existing §117.111, relating to initial demonstration of compliance, applicable to the Dallas-Fort Worth ozone nonattainment area.

Section 117.1140, Continuous Demonstration of Compliance

The commission adopts a new §117.1140 that incorporates the rule language in existing §117.113, relating to continuous demonstration of compliance, applicable to the Dallas-Fort Worth ozone nonattainment area.

New §117.1140(a) incorporates the rule language in the existing §117.113(a), relating to NO _X monitoring. New §117.1140(b) incorporates the CO monitoring requirements from existing §117.113(b). The specific requirements and methods in the existing §117.113(b) appear in new §117.8120, relating to CO monitoring, and subsequently have been omitted from new §117.1140(b) and replaced with a reference to the new §117.8120. Similarly, the requirements for CEMS in the existing §117.113(c)(1) and (2) appear in the new §117.8110(a), relating to emission monitoring system requirements for utility electric generation sources. Therefore, the new §117.1140(c) omits the specific requirements of existing §117.113(c)(1) and (2) and references the new §117.8110(a).

New §117.1140(d) incorporates the rule language from existing §117.113(d), concerning acid rain peaking units. New §117.1140(e) incorporates the rule language from existing §117.113(e), concerning auxiliary boilers. In addition, for new §117.1140(e), the commission revises the term auxiliary boiler to auxiliary steam boiler to be consistent with the definition in §117.10.

The commission adopts a new §117.1140(f) that incorporates the requirements for PEMS from existing §117.113(f). New §117.1140(f)(1) incorporates the rule language from existing §117.113(f)(1). The requirements in the existing §117.113(f)(2) - (4) appear in the new §117.8110(b), relating to emission monitoring system requirements for utility electric generation sources and subsequently have been omitted from the new §117.1140(f) and replaced with a reference to §117.8110(b) in new §117.1140(f)(2).

New §117.1140(g) - (j) incorporate the rule language applicable to the Dallas-Fort Worth ozone nonattainment area from existing §117.113(g) - (j), respectively. New §117.1140(k) incorporates the rule language from existing §117.113(k) and (k)(1), and new §117.1140(l) incorporates the rule language from existing §117.113(l).

Section 117.1145, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.1145 that incorporates the rule language in the existing §117.119, relating to notification, recordkeeping, and reporting requirements, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.1145(a) - (e) incorporate the rule language from existing §117.119(a) - (e). In addition, for new §117.1145(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.1145(a).

Section 117.1152, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.1152 that incorporates the requirements in the existing §117.115, relating to final control plan procedures for RACT, applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.1152(a), (b), and (c) incorporate the rule language from existing §117.115(a), (b) and (d), respectively. In addition, the commission revises the section title reference in new §117.1152(a)(2)(B) to reference the correct title "Alternative System-Wide Emission Specifications." Also, the commission omits the existing §117.115(c), relating to electronic submission and formatting requirements for the control plan, from the new §117.1152. Existing §117.115 and new §117.1152 specify the content requirements for the control plan. Therefore, a mandatory format for the control plan information is not necessary.

Section 117.1154, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.1154 that incorporates the rule language in existing §117.116, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Dallas-Fort Worth ozone nonattainment area.

Section 117.1156, Revision of Final Control Plan

The commission adopts a new §117.1156 that incorporates the requirements in the existing §117.117, relating to revision of final control plan, applicable to the Dallas-Fort Worth ozone nonattainment area.

DIVISION 3, HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

The commission adopts a new Chapter 117, Subchapter C, Division 3, entitled Houston-Galveston-Brazoria Ozone Nonattainment Area Utility Electric Generation Sources, that incorporates the provisions in existing Chapter 117, Subchapter B, Division 1 applicable to utility electric generation sources in the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.1200, Applicability

The commission adopts a new §117.1200, that incorporates the provisions in the existing §117.101, relating to applicability, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1200(a) incorporates the rule language in the existing §117.101(a) and (a)(1) - (4). The list of applicable units in existing §117.101(a)(1) - (4), including utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts, is incorporated into the new §117.1200(a). New §117.1200(a)(1) and (2) incorporate the language regarding owners or operators of the applicable units. New §117.1200(a)(1) incorporates the rule language from existing §117.101(a) concerning the applicability related to units owned or operated by a municipality or a PUC-regulated utility. In addition, the commission adopts a new §117.1200(a)(2) concerning the applicability of the division to electric power generating systems owned or operated by an electric cooperative, independent power producer, municipality, river authority, or public utility. As indicated elsewhere in this preamble, this change is intended to clarify the applicability of the rule and does not expand the applicability of the rule. Based on comments received and as discussed elsewhere in this preamble, independent power producers were removed from adopted §117.1200(a)(2) to avoid a potential expansion in the applicability. The commission adopts a new §117.1200(b) that incorporates the rule language in existing §117.101(b).

Section 117.1203, Exemptions

The commission adopts a new §117.1203 that incorporates the exemptions in the existing §117.103, relating to exemptions for utility electric generation sources in ozone nonattainment areas, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1203(a) - (c) incorporate the exemptions in the existing §117.103(a) - (c). In addition, for new §117.1203(c)(1), the commission revises the existing language in §117.103(c)(1) to expand the provisions relating to emergency fuel oil firing exemptions to emergency operating conditions declared by the Southeastern Electric Reliability Council and to remove reference to the Southwest Power Pool. This change is necessary because the Southeastern Electric Reliability Council area does overlap the Houston-Galveston-Brazoria ozone nonattainment area. The Southwest Power Pool area does not apply to the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.1205, Emission Specifications for Reasonably Available Control Technology (RACT)

The commission adopts a new §117.1205 that incorporates the specifications in the existing §117.105, relating to emission specifications for RACT, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. The commission adopts a new §117.1205(a) - (l) that incorporates the rule language in the existing §117.105(a) - (l).

The commission adopts a new equation in §117.1205(d) that incorporates the existing equation for calculating the rolling 24-hour heat input weighted average emission specification in the existing §117.105(d). The new equation in §117.1205(d) presents the equation in a format consistent with other figures in Chapter 117 and provides a written description of all the terms used in the equation. In addition, for new §117.1205(e), the commission uses the term auxiliary steam boilers as opposed to auxiliary boilers used in the existing language to be consistent with the definition in §117.10. For new §117.1205(i), the commission changes the word "ten" to the numeral "10" regarding the MW rating for stationary gas turbines subject to the CO emission specification in new §117.1205(i). Finally, new §117.1205(l) incorporates the rule language from existing §117.105(l) and (l)(3).

Section 117.1210, Emission Specifications for Attainment Demonstration

The commission adopts a new §117.1210 that incorporates the rule language in the existing §117.106, relating to emission specifications for attainment demonstrations, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. A new §117.1210(a) incorporates the specifications in the existing §117.106(c). The catchline is also changed to "Emission specifications for the Mass Emission Cap and Trade Program" to more accurately reflect the purpose of the emission specifications in combination with the MECT Program in Chapter 101, Subchapter H, Division 3. New §117.1210(b) incorporates the rule language concerning related emissions in the existing §117.106(d). In addition, for new §117.1210(b)(2), the commission changes the emissions specification for ammonia from the word "ten" to the numeral "10." Consistent with EPA guidance, the commission normally enforces emission test and monitoring results to the same significant figures as the emission specifications. Using the numeral "10" for the ammonia emission specification will ensure consistent enforcement of the emission specification.

Finally, the commission adopts a new §117.1210(c) and (c)(1) - (4), relating to compliance flexibility, that incorporates the rule language in the existing §117.106(e) and (e)(2) - (4).

Section 117.1215, Alternative System-Wide Emission Specifications

The commission adopts a new §117.1215 that incorporates the rule language in the existing §117.107, relating to alternative system-wide emission specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

The commission adopts new §117.1215(a) - (e) that incorporate the rule language in the existing §117.107(a) - (e). In addition, for new §117.1215, the commission revises language in existing §117.107 referencing system-wide emission limit or system-wide emission limitation to specify system-wide emission specification. These changes are to provide consistency and clarity in new §117.1215 and to be consistent with the section title and the change to the definition of system-wide emission limit in §117.10 discussed previously in this preamble.

New §117.1215(d) incorporates the rule language from existing §117.107(d). In addition, existing §117.107(d)(1) and (2) include required calculations written in paragraph form rather than in equation form. The commission is reformatting the calculations in a mathematical formula rather than the paragraph form to present the equations in a format consistent with other equations in Chapter 117 and provide a written description of all the terms used in the equation. The new equations are identical in content to the existing required calculations in paragraph form. The new equation in §117.1215(d)(1) incorporates the calculation for allowable system-wide NO _X emission specification for each affected utility boiler in the existing §117.107(d)(1). The new equations in §117.1215(d)(2) incorporate the calculation for the allowable NO _X emission rate for each affected stationary gas turbine in the existing §117.107(d)(2) as well as the existing equation for the in-stack NO _X concentration term in the existing §117.107(d)(2).

The commission adopts a new §117.1215(e) that incorporates the rule language in the existing §117.107(e). In addition, for new §117.1215(e), the commission uses the term system-wide as opposed to plant-wide that is used in the existing language to be consistent with the section.

Section 117.1220, System Cap

The commission adopts a new §117.1220 that incorporates the rule language in the existing §117.108, relating to system cap, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

The commission adopts a new §117.1220(a) - (k) that incorporates the rule language in the existing §117.108(a) - (k). For new §117.1220(b), the commission revises the language in existing §117.108(b) that specifies "that would otherwise be subject to the NO _X emission rates of §117.106 . . .." New §117.1220(b) specifies "that is subject to §117.1210(a) . . .." As previously discussed in this preamble, this change is necessary to clarify the commission's intent regarding units subject to the MECT Program. In addition, the commission adopts new equations in §117.1220(c) that incorporate the equations in existing §117.108(c) and present the equations in a format consistent with other equations in Chapter 117. The new equations in §117.1220(c) include only the information applicable to the Houston-Galveston-Brazoria ozone nonattainment area. The new equation in §117.1220(c)(1) incorporates the equation for the rolling 30-day average emission cap in the existing §117.108(c)(1). The new equation in §117.1220(c)(2) incorporates the equation for the maximum daily emission cap in the existing §117.108(c)(2). The commission adopts a new §117.1220(k) that incorporates the requirements of the existing §117.108(k). The new §117.1220(k) changes source cap to system cap to be consistent with the section. Also, for new §117.1220(k), the commission replaces the term upset period with the language "emissions event, as defined in §101.1 of this title (relating to Definitions) . . .." This change is necessary to update the rule to current terminology used by the commission.

The commission adopts a new §117.1220(l), relating to the use of emissions credits, that incorporates the rule language from existing §117.109, System Cap Flexibility. New §117.1220(m), relating to the sale and transfer of an electric generating system, incorporates the rule language from existing §117.110, Change of Ownership-System Cap.

Section 117.1225, Alternative Case Specific Specifications

The commission adopts a new §117.1225 that incorporates the rule language in the existing §117.121, relating to alternative case specific specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1225(a) and (b) incorporate the rule language in the existing §117.121(a) and (b). In addition, the new §117.1225(a) omits the provision in the existing §117.121(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.1235, Initial Demonstration of Compliance

The commission adopts a new §117.1235 that incorporates the rule language in the existing §117.111, relating to initial demonstration of compliance, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.1240, Continuous Demonstration of Compliance

The commission adopts a new §117.1240 that incorporates the rule language and requirements applicable to the Houston-Galveston-Brazoria ozone nonattainment area from existing §117.113, relating to initial demonstration of compliance, as well as the rule language and requirements from existing §117.114.

New §117.1240(a) incorporates the rule language in the existing §117.113(a), relating to NO _X monitoring. New §117.1240(b) incorporates the CO monitoring requirements from existing §117.113(b). The specific requirements and methods in the existing §117.113(b) appear in the new §117.8120, relating to CO monitoring, and subsequently have been omitted from new §117.1240(b) and replaced with a reference to the new §117.8120.

New §117.1240(c) incorporates the rule language and ammonia monitoring requirements in existing §117.114(a)(4). The new §117.1240(c) specifies that the owner or operator of units subject to the ammonia emission limits in the new §117.1210(b)(2) shall comply with the ammonia monitoring requirements of the new §117.8130. The specific ammonia monitoring procedures in existing §117.114(a)(4) are incorporated in new §117.8130.

The requirements for CEMS in the existing §117.113(c)(1) and (2) appear in the new §117.8110(a), relating to emission monitoring system requirements for utility electric generation sources. Therefore, the new §117.1240(d) omits the specific requirements of existing §117.113(c)(1) and (2). New §117.1240(d)(1) refers to the new §117.8110(a) for CEMS requirements applicable to units subject to the RACT emission specifications of new §117.1205. New §117.1240(d)(2) incorporates the CEMS requirements for units subject to the emission specifications for attainment demonstration in new §117.1210. New §117.1240(d)(2)(A) references the new §117.8110(a) and new §117.1240(d)(2)(B) - (D) incorporate the existing rule language and CEMS requirements in existing §117.113(c)(3) that are specific to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1240(e) incorporates the rule language from existing §117.113(d), concerning acid rain peaking units. New §117.1240(f) incorporates the rule language from existing §117.113(e), concerning auxiliary boilers. In addition, for new §117.1240(f), the commission revises the term auxiliary boiler to auxiliary steam boiler to be consistent with the definition in §117.10.

New §117.1240(g) that incorporates the requirements for PEMS from existing §117.113(f). New §117.1240(g)(1) incorporates the rule language from existing §117.113(f)(1). The requirements in the existing §117.113(f)(2) - (4) appear in the new §117.8110(b), relating to emission monitoring system requirements for utility electric generation sources, and subsequently have been omitted from the new §117.1240(g) and replaced with a reference to §117.8110(b) in new §117.1240(g)(2).

New §117.1240(h) - (m) incorporate the rule language applicable to the Houston-Galveston-Brazoria ozone nonattainment area from existing §117.113(g) - (l), respectively. New §117.1240(n) incorporates the rule language from existing §117.114(b), and new §117.1240(o) incorporates the rule language from existing §117.114(c). In addition, for new §117.1240(o), the commission adds language to specify "The owner or operator of units subject to §117.1210(a) of this title shall comply with the following." This change is necessary because the provisions of §117.114(c) only apply to sources subject to existing §117.106(c) and new §117.1210(a).

The provisions in existing §117.114(a)(1) - (3), concerning monitoring requirements for NO _X , CO, and totalizing fuel flow meters, are redundant with existing requirements in §117.113 and new §117.1240. Therefore, existing §117.114(a)(1) - (3) are not incorporated in the new §117.1240. Rule language from existing §117.114(a)(4)(E), concerning recordkeeping for ammonia monitoring, is to be incorporated in new §117.1245, Notification, Recordkeeping, and Reporting Requirements, to consolidate the recordkeeping requirements in the appropriate section.

Section 117.1245, Notification, Recordkeeping, and Reporting Requirements

The commission adopts a new §117.1245 that incorporates the rule language in the existing §117.119, relating to notification, recordkeeping, and reporting requirements, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1245(a) - (e) incorporate the requirements in the existing §117.119(a) - (e). In addition, for new §117.1245(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.1245(a). Finally, new §117.1245(e)(8) incorporates the recordkeeping requirement of the existing §117.114(a)(5)(E) associated with ammonia monitoring requirements.

Section 117.1252, Final Control Plan Procedures for Reasonably Available Control Technology

The commission adopts a new §117.1252 that incorporates the requirements in the existing §117.115, relating to final control plan procedures for RACT, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1252(a), (b), and (c) incorporate the rule language from existing §117.115(a), (b) and (d), respectively. In addition, the commission omits the existing §117.115(c), relating to electronic submission and formatting requirements for the control plan, from the new §117.1252. Existing §117.115 and new §117.1252 specify the content requirements for the control plan. Therefore, a mandatory format for the control plan information is not necessary.

Section 117.1254, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

The commission adopts a new §117.1254 that incorporates the rule language in the existing §117.116, relating to final control plan procedures for attainment demonstration emission specifications, applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.1254(a) incorporates the rule language from existing §117.116(a). New §117.1254(a)(1)(A) incorporates the existing §117.116(a)(1)(D), and replaces the existing §117.116(a)(1)(A). New §117.1254(a)(1)(B) and (C) incorporate the existing §117.116(a)(1)(B) and (D). New §117.1254(a)(2) - (5) incorporate rule language from the existing §117.116(a)(2) - (5), respectively. Finally, the commission adopts new §117.1254(b) and (c) that incorporate the rule language from existing §117.116(b) and (c), respectively.

Section 117.1256, Revision of Final Control Plan

The commission adopts a new §117.1256 that incorporates the requirements in the existing §117.117, relating to revision of final control plan, applicable to the Houston-Galveston-Brazoria ozone nonattainment area.

DIVISION 4, DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

The commission adopts a new Chapter 117, Subchapter C, Division 4, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, that includes new rules applicable to utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. These new rules are one part of the commission's Dallas-Fort Worth eight-hour ozone attainment demonstration and are necessary for the area to demonstrate attainment.

Section 117.1300, Applicability

New §117.1300, concerning applicability, identifies the facilities and unit types in the Dallas-Fort Worth eight-hour ozone nonattainment area that are subject to this rule. Subsection (a) specifies that the division applies to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts used in an electric power generating system that is owned or operated by a municipality or a PUC-regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC, or is owned or operated by an electric cooperative, municipality, river authority, or public utility operating in the Dallas-Fort Worth eight-hour ozone nonattainment area. Based on comments received and as discussed elsewhere in this preamble, independent power producers were removed from adopted §117.1300(a)(2) to avoid a potential expansion in the applicability.

Subsection (b) specifies that the provisions of the rule are applicable for the life of each affected unit within an electric power generating system or until the rule, or sections of the rule that are applicable to an affected unit, are rescinded.

Section 117.1303, Exemptions

New §117.1303 specifies the unit types and conditions that qualify for exemption from the specifications of the rule. New §117.1303(a), concerning exemptions from emission specifications for attainment demonstration, specifies the units exempt from the provisions of §117.1310 and §117.1340, except as may be specified in §117.1340(i) or (j). Units exempted include any new auxiliary steam boiler or stationary gas turbines placed into service after November 15, 1992, any auxiliary steam boiler with an annual heat input less than or equal to 2.2(10 ¹¹ ) British thermal units per year, or stationary gas turbines and engines used solely to power other engines or gas turbines during startups or that are demonstrated to operate less than 850 hours per year, based on a rolling 12-month average.

New §117.1303(b) specifies the exemptions for emergency fuel oil firing conditions. New §117.1303(b)(1) specifies that the emissions specifications of §117.1310 of this title do not apply during an emergency operating condition declared by the Electric Reliability Council of Texas, or any other emergency operating condition that necessitates oil firing. All findings that emergency operating conditions exist are subject to the approval of the executive director.

New §117.1303(b)(2) requires the owner or operator of an affected unit to provide the executive director, and any local air pollution control agency having jurisdiction, verbal notification as soon as possible but no later than 48 hours after declaration of the emergency. Verbal notification must identify the anticipated date and time oil firing will begin, duration of the emergency period, affected oil-fired equipment, and quantity of oil to be fired in each unit, and must be followed by written notification containing this information no later than five days after declaration of the emergency.

New §117.1303(b)(3) specifies that the owner or operator shall provide final written notification, as soon as possible but no later than two weeks after the termination of emergency fuel oil firing, to the executive director and any local air pollution control agency having jurisdiction. Final written notification must identify the actual dates and times that oil firing began and ended, duration of the emergency period, affected oil-fired equipment, and quantity of oil fired in each unit.

Section 117.1310, Emission Specifications for Eight-Hour Attainment Demonstration

The commission adopts a new section §117.1310 that specifies the emission specifications for eight-hour attainment demonstration. The new §117.1310(a) establishes NO _X emissions specifications for units in the Dallas-Fort Worth eight-hour ozone nonattainment area that are subject to this rulemaking. In addition, emission specifications for RACT from existing §117.105 are adopted to satisfy RACT requirements for auxiliary steam boilers and stationary gas turbines in the Dallas-Fort Worth eight-hour ozone nonattainment area.

New §117.1310(a)(1)(A) establishes an emission specification of 0.06 lb/MMBtu heat input from utility boilers that are part of a small utility system, as defined in §117.10. New subparagraph (B) establishes a NO_X emission specification of 0.033 lb/MMBtu heat input for utility boilers that are part of a large utility system, as defined in §117.10. The averaging times for both of these emission specifications are on a rolling 24-hour average basis during the months of March through October of each calendar year, and on a rolling 30-day average basis during the months of November, December, January, and February of each calendar year. In addition, in subparagraph (C) the commission is adopting a new output or efficiency-based emission specification of 0.50 pounds per megawatt-hour output on an annual average basis. Based on comments received and discussed in detail elsewhere in this preamble, the commission has created an additional subparagraph §117.1310(a)(1)(D) to provide the option of a system-wide heat input weighted average for utility boilers that are part of a large utility system for compliance with the 0.033 lb/MMBtu emission specification. New clause (i) specifies that the system-wide heat input weighted average is based on a rolling 168-hour (seven day) average calculated for each hour during which fuel was combusted in any unit in the system. New §117.1310(a)(1)(D)(ii) provides an equation for determining the system-wide heat input weighted average. The equation calculates the heat input weighted average based on the hourly average NO _X lb/MMBtu for each utility boiler multiplied by that boiler's hourly average heat input in MMBtu/hr, then summing these products for all boilers in the system to calculate total NO _X emissions in pounds per hour. The total NO _X emissions in pounds per hour is divided by the total system-wide heat input in MMBtu/hr to determine the system-wide heat input weighted average NO _X in lb/MMBtu on an hourly basis.

New §117.1310(a)(2) specifies emission specifications for auxiliary steam boilers. Subparagraph (A) establishes an emission specification of 0.26 lb/MMBtu heat input on a rolling 24-hour average and 0.20 lb/MMBtu heat input on a 30-day rolling average while firing natural gas or a combination of natural gas and waste oil. Subparagraph (B) establishes an emission specification of 0.30 lb/MMBtu heat input on a rolling 24-hour averaging period while firing fuel oil only. The heat input weighted average of the applicable emission specifications specified in subparagraphs (A) and (B) on a rolling 24-hour averaging period while firing a mixture of natural gas and fuel oil is specified in subparagraph (C). New subparagraph (C) also specifies the equation for calculating the emission specification while firing both natural gas and fuel oil. Also, for each auxiliary steam boiler that is an affected facility as defined by New Source Performance Standards (NSPS) 40 CFR Part 60, Subparts D, Db, or Dc, the applicable NSPS NO _X emission limit applies, unless the boiler is also subject to a more stringent permit emission limit, in which case the more stringent emission limit applies. Each auxiliary steam boiler subject to an emission specification under this subparagraph is not subject to the emission specifications of the subparagraphs of this paragraph. These emission specifications are identical to the current emission specifications for auxiliary steam boilers regulated under existing §117.105, concerning emission specifications for RACT, and the equation in subparagraph (C) is identical to the equation provided in existing §117.105 for calculating the emission specification while firing both natural gas and fuel oil.

New §117.1310(a)(3) specifies emission specifications for stationary gas turbines. New subparagraph (A) establishes two emission specifications for stationary gas turbines with a MW rating greater than or equal to 30 MW and an annual electric output in megawatt-hr (MW-hr) of greater than or equal to the product of 2,500 hours and the MW rating of the unit. A NO _X emission specification of 42 ppmv at 15% O ₂ , dry basis, on a block one-hour average, is for stationary gas turbines while firing natural gas, and an emission specification of 65 ppmv at 15% O ₂ , dry basis, is for stationary gas turbines while firing fuel oil. Subparagraph (B) establishes emission specifications for stationary gas turbines used for peaking service with an annual electric output in MW-hr of less than the product of 2,500 hours and the MW rating of the unit. The NO _X emission specifications under subparagraph (B) are 0.20 lb/MMBtu heat input, on a block one-hour average, while firing natural gas, and 0.30 lb/MMBtu heat input while firing fuel oil. These emission specifications are identical to the current RACT emission specifications for stationary gas turbines regulated under existing §117.105.

New §117.1310(b) establishes emission specifications of related emissions. For utility boilers or auxiliary steam boilers, a CO limit of 400 ppmv at 3.0% O ₂ , dry (or alternatively, 0.30 lb/MMBtu heat input for gas-fired units and 0.31 lb/MMBtu heat input for oil-fired units), based on a one-hour average for units not equipped with a CEMS or PEMS for CO or a rolling 24-hour averaging period for units equipped with CEMS or PEMS for CO. For any stationary gas turbine with a MW rating greater than or equal to 10 MW, §117.1310(b) establishes a CO emission specification of 132 ppmv at 15% O ₂ , dry basis. Section 117.1310(b)(2) specifies ammonia emission specifications for units that inject urea or ammonia into the exhaust stream for NO _X control, of 10 ppmv, at 3.0% O ₂ , dry, for boilers and 15% O₂ , dry, for stationary gas turbines (including duct burners used in turbine exhaust ducts), based on a block one-hour averaging period for units not equipped with a CEMS or PEMS for ammonia. Units not subject to the ammonia emission specification in §117.1310(b)(2)(A) are limited to a 20 ppmv ammonia emission specification under subparagraph (B), based on a block one-hour averaging period. This 20 ppmv ammonia emission specification is consistent with the current ammonia emission specification from existing §117.105 for RACT.

New §117.1310(c), concerning compliance flexibility, specifies that an owner or operator may use §117.9800 to comply with the NO _X emission specifications of this section. The subsection also specifies that §117.1325 is not an applicable method of compliance with the NO_X emission specifications for this section. An owner or operator may petition the executive director for an alternative to the CO or ammonia specifications of §117.1310 in accordance with §117.1325.

Section 117.1325, Alternative Case Specific Specifications

New §117.1325 specifies that where a person can demonstrate that an affected unit cannot attain the applicable CO or ammonia emission specifications of §117.1310(b), the executive director may approve emission specifications different from the CO or ammonia specifications in §117.1310(b) for that unit. Section 117.1325(a) specifies that the executive director shall consider on a case-by-case basis the technological and economic circumstances of the individual unit, shall determine that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of controls to meet the NO _X emission specifications of §117.1310, as applicable, and in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant where the unit is located to meet emission specifications through system-wide averaging at maximum capacity.

New §117.1325(b) specifies that any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision. New subsection (b) also specifies that the requirements of §50.139 apply and that executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for EPA approval in some cases.

Section 117.1335, Initial Demonstration of Compliance

New §117.1335 specifies the procedures for the initial demonstration of compliance for owners or operators of units subject to the rule. Section 117.1335(a) specifies that the owner or operator shall test for NO _X , CO, and O ₂ emissions. Also, for units that inject urea or ammonia into the exhaust stream for NO _X control, the owner or operator must test for ammonia emissions. Testing must be performed in accordance with the schedules specified in new §117.9130.

Section 117.1335(b) specifies that the tests required by subsection (a) must be used for determination of initial compliance with the emission specifications. Test results must be reported in the units of the applicable emission specifications and averaging periods. If compliance testing is based on 40 CFR Part 60, Appendix A reference methods, the report must contain the information specified in new §117.8010.

New §117.1335(c) specifies that CEMS or PEMS required by new §117.1340 must be installed and operational before testing under subsection (a). Verification of operational status must, at a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

New §117.1335(d) specifies initial compliance with the emission specifications for units operating with CEMS or PEMS in accordance with §117.1340 must be demonstrated after monitor certification testing using the NO _X CEMS or PEMS. Paragraphs (1) - (5) specify the proper monitoring procedures to be followed for the different averaging times and units specified in the emission specifications of §117.1310.

Section 117.1340, Continuous Demonstration of Compliance

New §117.1340 details the operating, monitoring, and testing required by owners and operators of units subject to the emissions specifications of §117.1310 in order to demonstrate continuous compliance.

New §117.1340(a) requires the owner or operator of each unit subject to the emission specifications of this division to install, calibrate, maintain, and operate a CEMS, PEMS, or other system specified in §117.1340, to measure NO _X on an individual basis. Each NO_X monitor (CEMS or PEMS) is subject to the RATA relative accuracy requirements of 40 CFR Part 75, Appendix B, Figure 2, except the concentration options (ppmv and lb/MMBtu) do not apply. Under subsection (a), each NO _X monitor must meet either the relative accuracy percent requirement of 40 CFR Part 75, Appendix B, Figure 2, or an alternative relative accuracy requirement of ± 2.0 ppmv from the reference method mean value.

New §117.1340(b), concerning CO monitoring, specifies the owner or operator shall monitor CO exhaust emissions from each unit subject to the emission specifications of §117.1310, using one or more of the methods specified in §117.8120. New §117.1340(c) requires the owner or operator of units that are subject to the ammonia emission specification of new §117.1310(b)(2)(A) to comply with the ammonia monitoring requirements of new §117.8130.

New §117.1340(d), concerning CEMS requirements, specifies that the owner or operator of any CEMS used to meet a pollutant monitoring requirement of §117.1340 shall comply with the requirements of §117.8110(a).

New §117.1340(e) provides alternatives for NO _X monitoring for acid rain peaking units, as defined in 40 CFR §72.2, which are consistent with the alternatives of existing §117.113(d). New §117.1340(f) provides alternative NO _X monitoring provisions for auxiliary steam boilers. The owner or operator of each auxiliary steam boiler must either install, calibrate, maintain, and operate a CEMS in accordance with new §117.1340, or comply with the appropriate (considering boiler maximum rated capacity and annual heat input) industrial boiler monitoring requirements of new §117.440.

New §117.1340(g) details the requirements for any PEMS used to meet a pollutant monitoring requirement of this section. The required PEMS and fuel flow meters must be used to demonstrate continuous compliance with the emission specifications. The PEMS must predict the pollutant emissions in the units of the applicable emission specification, and must meet the requirements of new §117.8110(b).

New §117.1340(h), regarding stationary gas turbine monitoring, specifies the owner or operator of each stationary gas turbine subject to the emission specifications of §117.1310 of this title, instead of monitoring emissions in accordance with the monitoring requirements of 40 CFR Part 75, may comply with the following monitoring requirements. For stationary gas turbines rated less than 30 MW or peaking gas turbines that use steam or water injection to comply with the emission specifications of new §117.1310(a)(3), the owner or operator may either install, calibrate, maintain and operate a CEMS or PEMS in compliance with §117.1340, or install, calibrate, maintain, and operate a continuous monitoring system, accurate to within 5%, to monitor and record the average hourly fuel and steam or water consumption. The steam-to-fuel or water-to-fuel ratio monitoring data must be used for demonstrating continuous compliance with the applicable emission specification of §117.1310. For stationary gas turbines subject to the emission specifications of §117.1310 of this title, the owner or operator may install, calibrate, maintain and operate a CEMS or PEMS in compliance with §117.1340.

New §117.1340(i), concerning totalizing fuel flow meters, specifies the owner or operator of units listed in subsection (i) shall install, calibrate, maintain, and operate totalizing fuel flow meters to individually and continuously measure the gas and liquid fuel usage. A computer that collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. In lieu of installing a totalizing fuel flow meter on a unit, an owner or operator may opt to assume fuel consumption at maximum design fuel flow rates during hours of the unit's operation. The units that the totalizing fuel flow meter requirements of subsection (i) apply to include any unit subject to the emission specifications of §117.1310, any stationary gas turbine with a MW rating greater than or equal to 1.0 MW operated more than 850 hours per year and any unit claimed exempt from the emission specifications of using the low annual capacity factor exemption of §117.1303(a)(2).

New §117.1340(j) specifies the owner or operator of any stationary gas turbine using the exemption of §117.1303(a)(3) shall record the operating time with an elapsed run time meter.

New §117.1340(k), concerning monitoring for output-based NO _X emission specification, is a new eight-hour monitoring requirement detailing the monitoring required for the owner or operator of any unit that complies with the optional output-based NO _X emission specification in new §117.1310(a)(1)(C). The subsection requires the owner or operator to install, calibrate, maintain, and operate a system to continuously monitor, at least once every 15 minutes, and record the gross energy production of the unit in megawatt-hours (MW-hr). In addition, for each hour of operation, the owner or operator shall determine the total mass emission of NO _X , in pounds, from the unit using the NO _X monitoring requirements of §117.1340(a) and the fuel monitoring requirements of §117.1340(i). The owner or operator shall also, for each hour of operation, calculate and record the NO _X emissions in pounds per megawatt-hour.

New §117.1340(l), concerning loss of exemption, specifies the requirements for owners or operators of units claimed exempt under new §117.1303(a)(2) or (3) that have lost exemption status because the applicable limit is exceeded.

New §117.1340(m), concerning data used for compliance, specifies that, after the initial demonstration of compliance required by new §117.1335, the methods required in new §117.1340 must be used for demonstrating continuous compliance with the emission specifications in new §117.1310.

Section 117.1345, Notification, Recordkeeping, and Reporting Requirements

New §117.1345 specifies the notification, recordkeeping, and reporting requirements for owners or operators of units subject to the emission specifications of §117.1310.

New §117.1345(a), concerning startup and shutdown records, specifies that for units subject to the startup and/or shutdown provisions of §101.222 of this title (relating to Demonstrations), hourly records must be made of startup and/or shutdown events and maintained for a period of at least two years. Records must be available for inspection upon request by the executive director, EPA, and any local air pollution control agency having jurisdiction. These records include, but are not limited to: type of fuel burned; quantity of each type of fuel burned; gross and net energy production in MW-hr; and the date, time, and duration of the event.

New §117.1345(b), concerning notification, specifies the owner or operator of a unit subject to the emission specifications in §117.1310 shall submit written notification to the appropriate regional office and any local air pollution control agency having jurisdiction of the date of any testing or any CEMS or PEMS performance evaluation conducted under §117.1335 or §117.1340 at least 15 days prior to such date.

New §117.1345(c) specifies the owner or operator of an affected unit shall furnish the Office of Compliance and Enforcement, the appropriate regional office, and any local air pollution control agency having jurisdiction a copy of any testing conducted under §117.1335 or any CEMS or PEMS performance evaluation conducted under §117.1340. Reports must be submitted within 60 days after completion of such testing or evaluation, and not later than the appropriate compliance schedules specified in new §117.9130.

New §117.1345(d), concerning semiannual reports, specifies the owner or operator of a unit required to install a CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring system under §117.1340 shall report in writing to the executive director on a semiannual basis any exceedance of the applicable emission limitations and the monitoring system performance. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. The content requirements for the written reports are specified in new paragraphs (1) - (5).

New §117.1345(e) specifies the recordkeeping requirement for the owner or operator of a unit subject to the new Subchapter C, Division 4. Records must be kept for a period of at least five years and made available for inspection upon request by the executive director, EPA, or local air pollution control agencies having jurisdiction. Operating records for each unit must be recorded and maintained at a frequency equal to the applicable emission specification averaging period, or for units claimed exempt from the emission specifications based on low annual capacity factor, monthly. New paragraph (1) requires records of emission rates in units of the applicable standards. New paragraph (2) requires records of gross energy production in MW-hr, except for auxiliary steam boilers and as specified in new paragraph (8). Records of the quantity and type of fuel burned are required by new paragraph (3), and the injection rate of reactant chemicals (if applicable) are required by new paragraph (4). New paragraph (5) requires records of emission monitoring data, in accordance with §117.1340, including: specified information regarding any monitoring system malfunctions; results of certification testing, evaluations, calibrations, checks, adjustments, and maintenance of monitoring systems; and actual emissions or operating parameter measurements, as applicable. New paragraphs (6) and (7) require records of performance testing results and hours of operation, respectively. New paragraph (8) requires additional records for any unit that the owner or operator elects to comply with the output-based emission specification in §117.1310(a)(1)(C). The additional records include hourly records of the gross energy production in MW-hr, as well as records of hourly and annual average NO _X emissions in lb/MW-hr. In addition, new paragraph (8) specifies that the averaging period for the annual average NO _X emissions in lb/MW-hr, for demonstrating continuous compliance is from January 1 through December 31 of each calendar year, beginning on January 1, 2010. This averaging period creates a temporary overlap with the initial demonstration of compliance period in new §117.1335, but is necessary to reset the averaging period to a calendar-year basis.

As discussed elsewhere in this preamble, the commission has provided an alternative system-wide heat input weighted average emission specification in §117.1310(a)(1)(D). A new §117.1345(e)(9) is adopted to specify the recordkeeping requirements for owners or operators of large utility systems that elect to use the alternative system-wide heat input weighted average emission specification. New subparagraphs (A) and (B) require hourly records of the average NO _X emissions in lb/MMBtu and average heat input in MMBtu/hr for each utility boiler in the system. New subparagraph (C) requires hourly records of the system-wide heat input weighted average NO _X emissions in lb/MMBtu. New subparagraph (D) requires hourly records of the rolling 168-hour average of the system-wide heat input weighted average NO _X emission in lb/MMBtu.

Section 117.1350, Initial Control Plan Procedures

New §117.1350 requires the owner or operator of any unit in the Dallas-Fort Worth eight-hour ozone nonattainment area that is subject to new §117.1310 to submit an initial control plan. New subsection (a) requires the control plan to include a list of all combustion units at the account that are listed in §117.1310. For each unit, the list must include the maximum rated capacity, anticipated annual capacity factor, estimated or measured NO_X emission data in the units associated with the category of equipment from §117.1310, the method of determination for the NO_X emission data, the facility identification number and emission point number as submitted to the Industrial Emissions Assessment Section of the commission, and the emission point number as listed on the Maximum Allowable Emissions Rate Table of any applicable commission permit. The list must also include identification of all units with a claimed exemption from the emission specifications in §117.1310 and the rule basis for the claimed exemption, a list of units to be controlled and the type of control to be applied for each unit, including an anticipated construction schedule. For units required to install totalizing fuel flow meters in accordance with §117.1340, the plan must indicate whether the devices are currently in operation, and if so, whether they have been installed as a result of the requirements of this rule. For units required to install CEMS or PEMS, the plan must indicate whether the systems are currently in operation, and if so, whether they have been installed as a result of the requirements of this rule.

New subsection (b) specifies that the initial control plan must be submitted to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office by the applicable date specified for initial control plans in new §117.9130. Control plans submitted to the Chief Engineer's Office should be submitted to the attention of the Air Quality Planning Section.

Finally, new subsection (c) specifies that for units located in Dallas, Denton, Collin, and Tarrant Counties subject to new §117.1110, the owner or operator may elect to submit the most recent revision of the final control plan required by new §117.1154 in lieu of the initial control plan required by §117.1350(a).

Section 117.1354, Final Control Plan Procedures for Attainment Demonstration Emission Specifications

New §117.1354 requires the owner or operator of utility boilers listed in new §117.1300 at a major source of NO _X to submit a final control plan to show compliance with the requirements of new §117.1310. The final control plans must be submitted to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office. Control plans submitted to the Chief Engineer's Office should be submitted to the attention of the Air Quality Planning Section. As specified in new §117.1354(a), the report must include: the methods of NO _X control for each utility boiler; the emissions measured by testing required in §117.1335; the submittal date, and whether sent to the Austin or the regional office (or both), of any compliance stack test or RATA report required by §117.1335 not being submitted concurrently with the final compliance report; and the specific rule citation for any utility boiler with a claimed exemption. New §117.1354(b) specifies that the report must be submitted by the applicable date specified for final control plans in new §117.9130.

Section 117.1356, Revision of Final Control Plan

New §117.1356 specifies the conditions under which a revised final control plan may be submitted by the owner or operator. The revised final control plan may be submitted along with any required permit applications. The section specifies that such a plan must adhere to the requirements and the final compliance dates, and that replacement new units may be included in the control plan. The revision of the final control plan is subject to the review and approval of the executive director.

SUBCHAPTER D, COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

The commission adopts a new Chapter 117, Subchapter D, entitled Combustion Control at Minor Sources in Ozone Nonattainment Areas, that incorporates the rule language from the existing Chapter 117, Subchapter D, Small Combustion Sources, Division 2, Boilers, Process Heaters, and Stationary Engines and Gas Turbines at Minor Sources.

In addition, the commission adopts a new Subchapter D, Division 2, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources, that includes new rule language and requirements associated with minor sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. The new Subchapter D, Division 2 is a part of the commission's eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area and is necessary for the area to demonstrate attainment.

DIVISION 1, HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA MINOR SOURCES

The commission adopts a new Subchapter D, Division 1, entitled Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources, that incorporates the rule language from existing Subchapter D, Division 2. The existing Subchapter D, Division 2, is only applicable in the Houston-Galveston-Brazoria ozone nonattainment area.

Section 117.2000, Applicability

New §117.2000 incorporates the applicability rule language from existing §117.471.

Section 117.2003, Exemptions

New §117.2003 incorporates the exemption rule language from existing §117.473.

Section 117.2010, Emission Specifications

New §117.2010 incorporates the rule language from existing §117.475, concerning emission specifications. New §117.2010(a) - (i) incorporate the rule language from existing §117.475(a) - (i), respectively. In addition, for new §117.2010(i)(2), the commission changes the emissions specification for ammonia from the word "ten" to the numeral "10." Consistent with EPA guidance, the commission normally enforces emission testing and monitoring results to the same significant figures as the emission specifications. Using the numeral "10" for the ammonia emission specification will ensure consistent enforcement of the emission specification.

Section 117.2025, Alternative Case Specific Specifications

New §117.2025 incorporates the rule language in the existing §117.481, relating to alternative case specific specifications. New §117.2025(a) and (b) incorporate the rule language in the existing §117.481(a) and (b), respectively. In addition, new §117.2025(a) omits the existing §117.481(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.2030, Operating Requirements

New §117.2030 incorporates the rule language in the existing §117.478, relating to operating requirements. New §117.2030(a) - (c) incorporate the rule language in the existing §117.478(a) - (c), respectively. For new §117.2030(a) and (b), the commission revises the language in existing §117.478(a) and (b) that specifies unit or units "subject to the emission limitations of §117.475." New §117.2030(a) and (b) specify "subject to §117.2010 . . .." While compliance with the emission specifications in existing §117.475(c) is achieved through the MECT Program for sources that are required to participate in the program, and an individual unit may not necessarily be required to meet the applicable emission specification in §117.475(c), units subject to existing §117.475(c) are still required to comply with existing §117.478. This change for new §117.2030 will clarify the commission's intent and avoid misinterpretation of the rule requirements for units subject to the MECT Program. In addition, for new §117.2030(b)(1), the commission omits the phrase "except for wood-fired boilers" because wood-fired boilers are not subject to either the existing rule or the new rule. The commission is concurrently adopting a new §117.8140(b) that incorporates the engine testing requirements in the existing §117.478(b)(5). Therefore, the engine testing requirements in existing §117.478(b)(5) have been omitted from the new §117.2030(b)(5) and replaced with a reference to the new §117.8140(b).

Section 117.2035, Monitoring and Testing Requirements

New §117.2035 incorporates the rule language regarding monitoring and testing from the existing §117.479, relating to monitoring, recordkeeping, and reporting requirements. New §117.2035(a) - (f) incorporate the rule language from existing §117.479(a) - (f), respectively. New §117.2035(g) incorporates the rule language from existing §117.479(i), concerning run time meters. The recordkeeping and reporting requirements in existing §117.479(g), (h), and (j) are incorporated in a new §117.2045, as discussed elsewhere in this preamble. In addition, for new §117.2035, the commission revises the language in existing §117.479(a) and (e) that specifies "subject to the emission limitations of §117.475." New §117.2035(a) and (e) specify "subject to §117.2010 . . .." As previously indicated in this preamble, this change will clarify the commission's intent and avoid misinterpretation of the rule requirements for units subject to the MECT Program.

For new §117.2035(b) and (c), the references to existing §117.213(e) and (f) are updated to §117.8100(a) and (b), as applicable, because the applicable requirements for CEMS and PEMS from existing §117.213 are incorporated in a new §117.8100. For new §117.2035(c), concerning NO _X monitors, the commission adds a provision that specifies that if a PEMS is used, the PEMS must predict the pollutant emissions in units of the applicable emission specifications of the division. This change is necessary because this requirement from existing §117.213(f) is not included in the new §117.8100(b).

The commission is concurrently adopting a new §117.8000 that incorporates some of the testing requirements in the existing §117.479(e)(3). Therefore, the commission adopts a new §117.2035(e)(3) that replaces specific requirements from existing §117.479(e)(3)(A) - (F) with a reference to the new §117.8000. Existing §117.479(e)(3)(G), regarding the provision allowing the use of American Society for Testing and Materials (ASTM) D6522-00 for performance testing on natural gas-fired engines, turbines, boilers, and process heaters, is incorporated into the new §117.2035(e)(3). Also, the commission is concurrently adopting a new §117.8010 that incorporates the report content requirements in the existing §117.211(g). Therefore, for new §117.2035(e)(3), the reference to §117.211(g) in existing §117.479(e)(3)(G), for report content requirements, is revised to reference the new §117.8010.

As indicated previously in this preamble, the commission is concurrently adopting a new §117.8010 that incorporates the report content requirements in the existing §117.211(g). Therefore, new §117.2035(e)(4) changes the reference to §117.211(g) to the new §117.8010. Also, for new §117.2035(e)(6), the commission revises the language "Initial compliance with the emission specifications of §117.475" to specify that "Initial compliance with §117.2010 . . .." As indicated previously in this preamble, this change will clarify the commission's intent and avoid misinterpretation of the rule requirements for units subject to the MECT Program.

Section 117.2045, Recordkeeping and Reporting Requirements

New §117.2045 incorporates the rule language regarding recordkeeping and reporting from the existing §117.479, relating to monitoring, recordkeeping, and reporting requirements. New §117.2045(a) - (c) incorporate the rule language from existing §117.479(g), (h), and (j), respectively. For new §117.2045, the commission is revising the language in existing §117.479(g) that specifies "subject to the emission limitations of §117.475 . . .." New §117.2045(a) specifies "subject to §117.2010 . . .." As previously indicated in this preamble, this change will clarify the commission's intent and avoid misinterpretation of the rule requirements for units subject to the MECT Program.

DIVISION 2, DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

The commission adopts a new Subchapter D, Division 2, entitled Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources, that includes new rule language and requirements associated with minor sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area.

Section 117.2100, Applicability

New §117.2100 specifies that the new Division 2, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources, applies to stationary reciprocating internal combustion engines located in the Dallas-Fort Worth eight-hour ozone nonattainment area at a stationary source of NO _X that is not a major source of NO _X . After further evaluation, the commission has determined that process heaters and stationary gas turbines at minor sources of NO _X do not represent a significant source of emissions in the Dallas-Fort Worth eight-hour ozone nonattainment area. Emission reductions from these two source categories under the proposed rule would be minimal. Therefore, the commission has decided to exempt process heaters and stationary gas turbines from the adopted rule. In addition, although no comments were received specifically regarding boilers at minor sources, the commission has decided to also exempt boilers from the adopted rule. The commission estimated that over 1,000 boilers would require retrofitting or replacement to meet the proposed emission specification. While considering comments received regarding the compliance schedule for minor sources, the commission determined that controls on boilers located at minor sources could not be implemented in time to help advance attainment of the area by the attainment date. The issue is further complicated by the fact that many of the owners or operators of boilers at minor sources are small businesses, schools, hospitals, and other institutions that would likely require more time to comply with the rule for economic reasons.

Section 117.2103, Exemptions

New §117.2103 specifies stationary, reciprocating internal combustion engines that will be exempt from the requirements of Chapter 117, Subchapter D, Division 2. As discussed elsewhere in this preamble, boilers, process heaters, and stationary gas turbines are not subject to the adopted rule. Exemptions related to boilers, process heaters, and stationary gas turbines have been removed to reflect this change, and the exemptions section renumbered accordingly. Section 117.2103 specifies those engines exempt from the rule, except for requirements that are specified in §§117.2130(c), 117.2135(e), and 117.2145(b) and (c).

New §117.2103(1) - (7) exempts stationary reciprocating internal combustion engines: with a hp rating of 50 hp or less; used for research and testing; used for performance verification and testing; used solely to power other engines and gas-turbines during startups; used exclusively for emergency situations, except for 100 hours of operation for testing and maintenance purposes; used in response to and during any officially declared disaster or state of emergency; or used directly and exclusively by the owner or operator for agricultural operations necessary for growing crops or raising of fowl or animals. Based on comments received and as discussed elsewhere in this preamble, the commission has revised the limit on hours to qualify for the exemption under §117.2103(5) to 100 hours instead of the 52 hours in the proposed rule. The exemption in new §117.2103(5), for engines used exclusively for emergency situations, is not applicable to any new, modified, reconstructed, or relocated engines placed into service on or after June 1, 2007. New §117.2103(5) also provides the definitions for modified, reconstruction, or relocated.

New §117.2103(8), specifies that any stationary diesel engine placed into service before January 1, 2007, in the Dallas-Fort Worth eight-hour ozone nonattainment area is eligible for the exemption in §117.2103(8) provided the engine meets the conditions of subparagraphs (A) and (B). New §117.2103(8)(A) and (B) specify that engines claimed exempt under §117.2103(8) must operate less than 100 hours per year, based on a rolling 12-month average and not have been modified, reconstructed, or relocated on or after January 1, 2007, in the Dallas-Fort Worth eight-hour ozone nonattainment area.

New §117.2103(9) specifies that any stationary diesel engine placed into service on or after January 1, 2007, in the Dallas-Fort Worth eight-hour ozone nonattainment area is eligible for the exemption in §117.2103(9) provided the engine meets the conditions of subparagraphs (A) and (B). New §117.2103(9)(A) and (B) specify that new, modified, reconstructed, or relocated stationary diesel engines claimed exempt under §117.2103(9) must operate less than 100 hours per year, based on a rolling 12-month average, and must meet the corresponding emissions standards in 40 CFR §89.112(a), Table 1 (October 23, 1998) and in effect at the time of installation, modification, reconstruction, or relocation.

Section 117.2110, Emission Specifications for Eight-Hour Attainment Demonstration

New §117.2110 establishes the emission specifications for units in the Dallas-Fort Worth eight-hour ozone nonattainment area that are subject to this rulemaking. As discussed elsewhere in this preamble, boilers, process heaters, and stationary gas turbines are not subject to the adopted rule. Provisions in the adopted §117.2110 related to boilers, process heaters, and stationary gas turbines have been modified or removed to reflect this change, and the provisions in adopted §117.2110 renumbered accordingly.

New §117.2110(a)(1) establishes NO _X emission specifications for stationary, gas-fired, reciprocating internal combustion engines. New subparagraph (A) establishes the emission specifications for rich-burn gas-fired engines. Rich-burn engines fired on landfill gas are limited to 0.60 g/hp-hr and all other gas-fired rich-burn engines are limited to 0.50 g/hp-hr. New subparagraph (B) establishes the emission specifications for lean-burn gas-fired engines. Lean-burn engines placed into services before June 1, 2007, that have not been modified, reconstructed, or relocated on or after June 1, 2007, are limited to 0.70 g/hp-hr. Lean-burn gas-fired engines installed, modified, reconstructed, or relocated on or after June 1, 2007, are limited to 0.60 g/hp-hr if fired on landfill gas and 0.50 g/hp-hr for all other lean-burn engines. As discussed elsewhere in this preamble, the change to the emission specification for existing lean-burn engines is based on comments received.

NSCR technology is anticipated to be the primary control technology for rich-burn engines to comply with this rule. In some cases, the owner or operator may have to install an additional catalyst module with the NSCR control package in order to comply with the 0.50 g/hp-hr emission specification. One possible control technology available for lean-burn engines is the application of an EGR kit (in order to reduce the excess O ₂ ) combined with NSCR control. While NSCR is not normally applied to lean-burn engines, the use of the EGR kit reduces exhaust gas O ₂ and allows NSCR to be installed. Owners or operators of some lean-burn engines may not be able to apply the exhaust gas recirculation kit coupled with NSCR. In these instances, SCR may be required to achieve the emission specifications. No landfill gas-fired engines were identified in the inventory in the counties impacted by this rule; however, the 0.60 g/hp-hr for gas-fired engines fired on landfill gas is consistent with the emission specification for this category of engines in the Houston-Galveston-Brazoria ozone nonattainment area and is expected to be achievable through combustion modifications or by purchasing a new engine meeting the emission specification.

Stationary, dual-fuel, reciprocating internal combustion engines are limited to 5.83 g/hp-hr by new §117.2110(a)(2). For stationary, dual-fuel reciprocating internal combustion engines, combustion modifications are expected to be necessary to meet the 5.83 g/hp-hr emission specification requirements.

New §117.2110(a)(3) establishes emission specifications for stationary, diesel, reciprocating internal combustion engines based on engine hp rating and the date that the engine was installed, modified, reconstructed, or relocated. These emission specifications are similar to the emission specifications for stationary diesel engines subject to existing Subchapter D, Division 2 in the Houston-Galveston-Brazoria ozone nonattainment area; however, the commission is not requiring engines to meet previous specifications for which the dates have passed. While the date associated with the emission specifications in §117.2110(a)(3) was not specifically commented on, the commission has determined that March 1, 2009, the compliance date specified for diesel engines in §117.9210, is more appropriate to use as a basis for the tiered emission specification under §117.2110(a)(3). Aligning the date with the compliance date in §117.9210 will simplify the emission specification schedule and make compliance with the rule easier for owners or operators of engines that were ordered prior to the rule proposal but would not be installed by June 1, 2007. This revision also provides relief for emergency diesel engines installed after June 1, 2007, that might not qualify for exemption under §117.2103(8) or (9).

New §117.2110(a)(3)(A) specifies that stationary diesel engines placed into service before March 1, 2009, that have not been modified, reconstructed, or relocated after March 1, 2009, are limited to the lower of 11.0 g/hp-hr or the emission rate established by testing, monitoring, manufacturer's guarantee, or manufacturer's other data. New §117.2110(a)(3)(B) establishes the NO _X emission limits for stationary diesel engines installed, modified, reconstructed, or relocated on or after March 1, 2009. The emission specifications in §117.2110(a)(3)(B) are tiered based on engine horsepower and are consistent with the final standards for stationary diesel engines in the Houston-Galveston-Brazoria nonattainment area.

The commission expects that, initially, the majority of stationary diesel engines at minor sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area qualify for exemption under §117.2103(8) or (9). When owners or operators modify, reconstruct, or relocate existing stationary diesel engines on or after June 1, 2007, if used exclusively in emergency situations, these engines would continue to be exempt from the new emission specifications, but will be required to meet the EPA Tier 1, Tier 2, or Tier 3 emission standards for non-road diesel engines in effect at the time of installation, modification, reconstruction, or relocation. These requirements ensure that as turnover of older, higher-emitting stationary diesel engines occurs, the replacements will be cleaner engines. For engines that do not qualify for exemption, the commission does not anticipate that engines placed into service prior to March 1, 2009, would require combustion modifications to meet the 11.0 g/hp-hr emission specification. The cost of combustion modifications to stationary diesel engines to meet the emission standards in §117.2110(a)(3)(B) is expected to be near the cost of a new engine; therefore, the commission anticipates that for engines placed into service on or after March 1, 2009, the owner or operator will likely purchase new equipment rather than retrofit or modify existing equipment.

New §117.2110(a)(4), proposed as subsection (a)(6), provides an alternative emission specification of 0.060 lb/MMBtu in lieu of the emissions specifications in §117.2110(a)(1) - (3) for a unit with an annual capacity factor of 0.0383 or less. The capacity factor as of December 31, 2000, must be used to determine eligibility for this alternative emission specification. For units placed into service after December 31, 2000, a 12-month rolling average must be used to determine the annual capacity factor.

New §117.2110(a)(5) defines modification, reconstruction, and relocated consistent with §117.2010(c)(4). The commission has moved these definitions from subsection (a)(3)(A) so the definitions also apply to the terms used in subsection (a)(1) and to clarify the rule. The paragraphs under subsection (a) are also revised to be complete sentences for clarity.

New §117.2110(b) specifies the averaging time for determining compliance with the NO _X emission specifications. New §117.2110(b)(1) specifies the averaging time for units equipped with CEMS or PEMS must be either a rolling 30-day average in the units of the applicable standard, a block one-hour average in the units of the applicable standard, or a block one-hour average in pounds per hour for boilers. New §117.2110(b)(2) specifies that averaging time for units not operated with CEMS or PEMS must be a block one-hour average in the units of the applicable standard.

New §117.2110(c) specifies that the maximum rated capacity used to determine the applicability of the emissions specifications must be the greater of the maximum rated capacity as of December 31, 2000, or the maximum rated capacity after December 31, 2000.

New §117.2110(d) specifies that a unit's classification is determined by the most specific classification applicable to the unit as of December 31, 2000. For example, a unit that is classified as a stationary gas-fired engine as of December 31, 2000, but subsequently is authorized to operate as a dual-fuel engine, will remain classified as a stationary gas-fired engine for the purposes of this rule.

New §117.2110(e) specifies that changes after December 31, 2000, to a unit subject to an emission specification in subsection (a) that result in increased NO _X emissions from a unit not subject to the emission specifications is only allowed if the conditions of §117.2110(e)(1) and (2) are met. Section 117.2110(e)(1) requires the increase in NO _X emissions at the unit not subject to an emission specification be determined using CEMS or PEMS monitoring or through stack testing that meets the requirements of §117.2135. In addition, §117.2110(e)(2) requires that emission credits equal to the increase in NO _X emissions must be obtained and used in accordance with new §117.9800, concerning use of emissions credits for compliance. An example of this is redirecting one or more fuel or waste streams containing chemical-bound nitrogen to an incinerator or a flare.

New §117.2110(f) specifies that a source that met the definition of major source on December 31, 2000, must always be classified as a major source for purposes of this rule. In addition, a source that was a minor source on December 31, 2000, but becomes a major source after December 31, 2000, will from that time forward always be classified as a major source for purposes of Chapter 117.

New §117.2110 also adds a new §117.2110(g) that specifies that the low annual capacity factor available under §117.2110(a)(4) for units with an annual capacity factor of 0.0383 or less is based on the unit's status on December 31, 2000. In addition, §117.2110(g) specifies that reduced operation after December 31, 2000, cannot be used to qualify for a more lenient emission specification under subsection (a)(4).

New §117.2110(h) establishes ammonia and CO emission specifications. The CO emission specification in §117.2110(h)(1) is 400 ppmv at 3.0 O₂ , dry basis, or alternatively, 3.0 g/hp-hr for stationary internal combustion engines. New §117.2110(h)(1)(A) and (B) specify the averaging time for the CO emission specification. The CO specification is necessary to prevent large increases in CO emissions concurrent with the installation of NO _X controls and represents good engineering practice. For units that inject urea or ammonia into the exhaust stream to control NO _X emissions, §117.2110(h)(2) includes a 10 ppmv ammonia emission specification (15% O ₂ for gas-fired lean-burn engines, and 3.0% O ₂ for all other units). New §117.2110(h)(2)(A) and (B) specify the averaging time for the ammonia emission specification. This ammonia emission specification is necessary to ensure that excessive ammonia slip emissions do not occur should an owner or operator use a control technology such as SCR.

Finally, new §117.2110(i) specifies that an owner or operator may use emission reduction credits as specified in new §117.9800 to comply with the NO _X emission specifications.

Section 117.2125, Alternative Case Specific Specifications

New §117.2125, concerning alternative case specific specifications, establishes provisions that allows owners or operators to petition the executive director for alternative case specific emission specifications for CO and ammonia. Section 117.2125(a) specifies that the executive director may approve emission specifications different from the CO or ammonia specifications for a unit where a person can demonstrate that the affected unit cannot attain the CO or ammonia specifications of §117.2110(h). Subsection (a)(1) specifies that the executive director shall consider on a case-by-case basis the technological and economic circumstances of the individual unit. Subsection (a)(2) requires that the executive director must determine that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of controls to meet the NO _X emission specifications of §117.2110. Subsection (a)(3) specifies that the executive director, in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant at which the unit is located to meet emission specifications through system-wide averaging at maximum capacity. Finally, §117.2125(b) specifies that any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision, and that the requirements of §50.139 (relating to Motion to Overturn Executive Director's Decision) apply to §117.2125.

Section 117.2130, Operating Requirements

New §117.2130 establishes operating requirements for units subject to the emission specifications of this division. New §117.2130(a) specifies that the owner or operator must operate any unit subject to the emission specifications in compliance with those specifications. New §117.2130(b) specifies that all units subject to the emission specifications must be operated so as to minimize NO _X emissions consistent with the emission control techniques selected, over the unit's operating or load range during normal operations. As discussed elsewhere in this preamble, boilers, process heaters, and stationary gas turbines are not subject to the adopted rule. Provisions in the adopted §117.2130 related to boilers, process heaters, and stationary gas turbines have been modified or removed to reflect this change, and the provisions renumbered as necessary.

New §117.2130(b)(1) requires that each unit controlled with post-combustion control techniques must be operated such that the reducing agent injection rate is maintained to limit NO _X concentrations to less than or equal to the NO _X concentrations achieved at maximum rated capacity. New §117.2130(b)(2) requires each stationary internal combustion engine controlled with NSCR to be equipped with an AFR controller that operates on exhaust O ₂ or CO control and maintains AFR in the range required to meet the engine's applicable emission limits. New §117.2130(b)(3) requires that each stationary internal combustion engine must be checked for proper operation according to §117.8140(b). New §117.2130(c) specifies that no person shall start or operate any stationary diesel or dual-fuel engine for testing or maintenance between the hours of 6:00 a.m. and noon, except as provided in subsection (c)(1) - (3). New subsection (c)(1) allows for specific manufacturer's recommended testing requiring a run of over 18 consecutive hours. Subsection (c)(2) allows for operation to verify reliability of emergency equipment (e.g., emergency generators or pumps) immediately after unforeseen repairs. Routine maintenance such as an oil change is not considered to be an unforeseen repair. New subsection (c)(3) allows for operation of firewater pumps for emergency response training conducted during April through October. This provision is identical to a requirement implemented for the Houston-Galveston-Brazoria ozone nonattainment area. The requirement will delay emissions of NO _X from testing of these engines until after noon in order to help limit ozone formation.

Section 117.2135, Monitoring, Notification, and Testing Requirements

New §117.2135 specifies the monitoring, notification, and testing requirements that apply to minor sources in the Dallas-Fort Worth eight-hour ozone nonattainment area subject to this rule. As discussed elsewhere in this preamble, boilers, process heaters, and stationary gas turbines are not subject to the adopted rule. Provisions in the adopted §117.2135 related to boilers, process heaters and stationary gas turbines have been modified or removed to reflect this change and the provisions renumbered as necessary.

Proposed §117.2135(a) is not adopted because the totalizing fuel flow meter requirements were only applicable to boilers and process heaters. New §117.2135(a) specifies that if an owner or operator installs an O ₂ monitor, then the criteria in §117.8100(a) is the appropriate guidance for the location and calibration of the monitor. New §117.2135(b) specifies that if an owner or operator installs a NO _X monitor, then it must meet the CEMS or PEMS requirements of §117.8100(a) or (b). New §117.2135(c) specifies that monitors must be installed on the schedule specified in §117.9210.

New §117.2135(d) lists the testing requirements for units subject to the emission specifications of §117.2110. Section 117.2135(d)(1) requires that each unit must be tested for NO _X , CO, and O ₂ emissions and subsection (d)(2) requires that each unit that injects urea or ammonia for NO _X control be tested for ammonia emissions. New §117.2135(d)(3) specifies all testing must be conducted according to §117.8000 for units not equipped with CEMS or PEMS. In lieu of the test methods specified in §117.8000 of this title, the owner or operator may use ASTM D6522-00 to perform the NO_X , CO, and O ₂ testing required by this subsection on natural gas-fired reciprocating engines. Also, if the owner or operator elects to use ASTM D6522-00 for the testing requirements, the report must contain the information specified in §117.8010. New §117.2135(d)(4) specifies that the results must be reported in the units of the applicable standard and averaging periods, and that if compliance testing is based on 40 CFR 60 Appendix A test methods then the report must contain the information specified in §117.8010.

New §117.2135(d)(5) specifies that for units equipped with CEMS or PEMS, the CEMS or PEMS must be installed and operational before testing under this subsection. Verification of operational status must, at a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device. New §117.2135(d)(6) specifies that on units operating with CEMS or PEMS, initial compliance with the emission specifications of §117.2110 of this title must be demonstrated using the CEMS or PEMS after monitor certification. New §117.2135(d)(7) specifies retesting requirements for units not operating with CEMS or PEMS. New §117.2135(d)(7)(A) requires retesting within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate. New §117.2135(d)(7)(B) allows retesting at the discretion of the owner or operator after any modification that could reasonably be expected to decrease the NO _X emission rate, including, but not limited to, installation of post-combustion controls, low-NO _X burners, low excess air operation, staged combustion (for example, overfire air), FGR, and fuel-lean and conventional (fuel-rich) reburn. New §117.2135(d)(8) specifies that testing be performed in accordance with the schedule specified in §117.9210. New §117.2135(d)(9) requires that all test reports be submitted to the executive director for review and approval within 60 days after completion of the testing. Notification requirements are specified in new §117.2135(d)(10). Written notification is required at least 15 days in advance of any testing or RATA required under §117.2135. Finally, new §117.2135(e) specifies the owner or operator of any stationary diesel engine claimed exempt using the exemption of §117.2103(5), (8), or (9) of this title shall record the operating time with a non-resettable elapsed run time meter.

Section 117.2145, Recordkeeping and Reporting Requirements

New §117.2145 specifies recordkeeping and reporting requirements for sources subject to the rule. As discussed elsewhere in this preamble, boilers, process heaters, and stationary gas turbines are not subject to the adopted rule. Provisions in the adopted §117.2145 related to boilers, process heaters and stationary gas turbines have been modified or removed to reflect this change, and the provisions renumbered accordingly.

New §117.2145(a) requires that the owner or operator of a unit subject to the emission specifications of §117.2110 must maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the EPA, or local air pollution control agencies having jurisdiction. New adopted §117.2145(a)(1) requires that records of hourly emissions be maintained for each unit using a CEMS or PEMS. New §117.2145(a)(1)(A) requires hourly emissions for units complying with an emission specification enforced on a block one-hour average. New §117.2145(a)(1)(B) requires daily emissions for units complying with an emission specification enforced on a rolling 30-day average. New §117.2145(a)(1)(B)(i) and (ii) specify that emissions must be recorded in units of lb/MMBtu heat input and pounds or tons per day. New §117.2145(a)(2) specifies records for each stationary internal combustion engine subject to the emission specifications of §117.2110. Records required under new §117.2145(a)(2) include emissions measurements required by §117.2130(b)(3) as well as any catalytic converter, AFR controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken. New subsection (a)(3) requires records of the CO measurements specified in subsection §117.2130(b)(3). New subsection (a)(4) requires records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring systems. New subsection (a)(5) requires the owner or operator to maintain records of the results of performance testing.

New §117.2145(b) specifies that written records of the number of hours of operation for each day's operation must be made for each engine claimed exempt under §117.2103(5), (8), or (9) of this title or §117.2130(b)(3). In addition, for each engine claimed exempt under §117.2103(5), written records must be maintained that reflect the purpose of engine operation and, if operation was for an emergency situation, identification of the type of emergency situation and the start and end times and dates of the emergency situation. The records must be maintained for at least five years and must be made available upon request to representatives of the executive director, the EPA, or any local air pollution control agency having jurisdiction. New §117.2145(c) specifies the requirements for records of operation for testing and maintenance. The owner or operator of each stationary diesel or dual-fuel engine shall maintain the following records for at least five years and make them available upon request by authorized representatives of the executive director, the EPA, or local air pollution control agencies having jurisdiction. New §117.2145(c)(1) specifies the owner or operator of each stationary diesel or dual-fuel engine shall maintain records of dates of operation. New subsection (c)(2) requires records of start and end times of operation. New subsection (c)(3) requires records with engine identification information and new subsection (c)(4) requires records of the total hours of operation for each month and for the most recent 12 consecutive months.

SUBCHAPTER E, MULTI-REGION COMBUSTION CONTROL

The commission adopts a new Chapter 117, Subchapter E, entitled Multi-Region Combustion Control, that incorporates the portions of the existing Chapter 117 that are applicable to multiple regions of the state. New Subchapter E incorporates rules from existing Subchapter B, Divisions 2 and 4, and existing Subchapter D, Division 1. In addition, the commission adopts a new Subchapter E, Division 4, entitled East Texas Combustion, that adopts new rule language and requirements associated with stationary, gas-fired, reciprocating internal combustion engines in certain counties in the Northeast Texas area. The new Subchapter E, Division 4 is a part of the commission's eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area.

DIVISION 1, UTILITY ELECTRIC GENERATION IN EAST AND CENTRAL TEXAS

The commission adopts a new Chapter 117, Subchapter E, Division 1 to incorporate the rule language from existing Chapter 117, Subchapter B, Division 2, regarding utility electric generation in East and Central Texas.

Section 117.3000, Applicability

New §117.3000 incorporates the applicability language from existing §117.131.

Section 117.3003, Exemptions

New §117.3003 incorporates the exemption language from existing §117.133.

Section 117.3005, Gas-Fired Steam Generation

New §117.3005 incorporates the requirements and specifications from existing §117.134.

Section 117.3010, Emission Specifications

New §117.3010 incorporates the requirements and emission specifications from existing §117.135. The commission also corrects a typographical error in existing §117.135(1) that incorrectly specified "nitrogen oxide (NO _X ) . . .." The correct terminology for the regulated pollutant is "nitrogen oxides (NO _X )." Because all other sections in the division correctly specify "nitrogen oxides," the commission does not anticipate that any regulated entities have misinterpreted the commission's intent with regard to the emission specifications in §117.135. Therefore, the commission does not consider the correction in new §117.3010(1) to have any impact to the regulated community.

In addition, the commission revises the ammonia emission specification in new §117.3010(2), incorporated from existing §117.135(2), to be the numeral "10" instead of the word "ten." Consistent with EPA guidance, the commission normally enforces emission test and monitoring results to the same significant figures as the emission specifications. Using the numeral "10" for the ammonia emission specification will ensure consistent enforcement of the emission specification. Finally, the commission moves the existing requirement for ammonia monitoring procedures in existing §117.135(2)(B), that references the ammonia monitoring procedures in existing §117.114(a)(4) to the appropriate monitoring section in new §117.3040, concerning continuous demonstration of compliance.

Section 117.3020, System Cap

New §117.3020 incorporates the language from existing §117.138, concerning System Cap requirements, and §117.139, concerning System Cap Flexibility. Existing §117.138(a) - (k) are incorporated in new §117.3020(a) - (k). Existing §117.139 is incorporated in new §117.3020(l). In addition, the commission adopts a revised equation in §117.3020(c) that incorporates the equation in existing §117.138(c) and presents the equation in a format consistent with other equations in Chapter 117. Finally, based on comments received, the commission has corrected the cross-reference error in §117.3020(l) to reference the appropriate citation, §117.3000(a)(4).

Section 117.3025, Alternative Case Specific Specifications

New §117.3025 incorporates the provisions in the existing §117.151, relating to alternative case specific specifications. New §117.3025(a) and (b) incorporates the rule language in the existing §117.151(a) and (b); however, the new §117.3025(a) omits the existing §117.151(a)(4) because the Engineering Services Team no longer exists within the TCEQ.

Section 117.3035, Initial Demonstration of Compliance

New §117.3035 incorporates the requirements for initial demonstration of compliance from existing §117.141. New §117.3035(a) - (d) incorporate the rule language from existing §117.141(a) - (d). Additionally, in new §117.3035(a), the commission revises the language from existing §117.141(a) to clarify that the units subject to the emission specifications should be tested and not the owner or operator of the units.

Section 117.3040, Continuous Demonstration of Compliance

New §117.3040 incorporates the requirements for continuous demonstration of compliance from existing §117.143. New §117.3040(a) incorporates the rule language from existing §117.143(a). The CO monitoring provisions in existing §117.143(b) are incorporated in new §117.3040(b); however, the actual monitoring methods in existing §117.143(b)(1) and (2) are incorporated in new §117.8120. Therefore, new §117.3040(b) specifies that if the owner or operator chooses to monitor CO exhaust emissions, the methods specified in §117.8120 should be considered appropriate guidance for determining CO emissions.

New §117.3040(c) incorporates the ammonia monitoring provisions from existing §117.135(2)(B) because the continuous demonstration of compliance section is the most appropriate section for the ammonia monitor requirements. The ammonia monitoring procedures in existing §117.114(a)(4), referenced by existing §117.135(2)(B), are incorporated in a new §117.8130. New §117.3040(c) specifies that for units that inject urea or ammonia into the exhaust stream for NO _X control, one of the ammonia monitoring procedures in new §117.8130 must be used to demonstrate compliance with the ammonia emission specification.

New §117.3040(d) incorporates the CEMS requirements from existing §117.135(c). The requirements for CEMS in existing §117.135(c) are sufficiently different from the requirements in §117.113(e) that referencing the general CEMS requirements for utility electric generation sources in new §117.8110(a) would result in substantive changes to the requirements for affected CEMS. Therefore, the commission is not merging the CEMS requirements in existing §117.135(c) with new §117.8110(a).

New §117.3040(e) incorporates the rule language from existing §117.135(d), concerning monitoring for acid rain peaking units. The commission adopts a new §117.3040(f) that incorporates the rule language from existing §117.135(e), concerning PEMS requirements.

New §117.3040(f)(1) incorporates the provision in existing §117.135(f)(1), that specifies that the PEMS must predict the pollutant emissions in the units of the applicable emission specifications of the division. The commission adopts a new §117.3040(f)(2) that references the new §117.8110(b) as a replacement for the rule language in existing §117.135(f)(2) - (4). The general requirements for PEMS in new §117.8110(b) are identical to the requirements in existing §117.135(f)(2) - (4).

Finally, the commission adopts new §117.3040(g) - (l) that incorporate the rule language from existing §117.135(f) - (k), respectively.

Section 117.3045, Notification, Recordkeeping, and Reporting Requirements

New §117.3045, concerning notification, recordkeeping, and reporting requirements, incorporates the rule language from existing §117.149. New §117.3045(a) - (e) incorporate the rule language from existing §117.149(a) - (e). In addition, for new §117.3045(a), the commission replaces the language "the startup and/or shutdown exemptions allowed under §101.222" with "the startup and/or shutdown provisions of §101.222 . . .." The reference to exemptions is not applicable to §101.222 and the change is necessary to clarify new §117.3045(a).

Section 117.3054, Final Control Plan Procedures

New §117.3054, concerning final control plan procedures, incorporates the rule language from existing §117.145.

Section 117.3056, Revision of Final Control Plan

New §117.3056, concerning revision of final control plan, incorporates the rule language from existing §117.147.

DIVISION 2, CEMENT KILNS

The commission adopts a new Chapter 117, Subchapter E, Division 2 to incorporate the rule language from existing Chapter 117, Subchapter B, Division 4, regarding cement kilns. In addition, the commission adopts new control, monitoring, testing, and recordkeeping requirements for cement kilns in Ellis County as a part of the commission's Dallas-Fort Worth eight-hour ozone attainment demonstration.

Section 117.3100, Applicability

New §117.3100 incorporates the applicability rule language from existing §117.261. In addition, the language in existing §117.261, regarding applicability of the rule to units placed into service before December 31 1999, is moved to the new §117.3103, Exemptions.

Section 117.3101, Cement Kiln Definitions

New §117.3101 incorporates the definition rule language from existing §117.260.

Section 117.3103, Exemptions

The commission is adopting a new §117.3103, concerning exemptions, that incorporates the exemption in applicability language of existing §117.261 that exempted certain units placed into service on or after December 31, 1999, and adopts a new exemption regarding units subject to new §117.3123. The new §117.3103(a) specifies that units exempted from the division include any portland cement kiln placed into service on or after December 31, 1999, except as specified in new §§117.3110, 117.3120, and 117.3123. New §117.3110 and §117.3120 are corresponding new sections that incorporate existing rule language from existing §117.265 and §117.283, respectively, which are already referenced in the existing language in §117.261. The reference to new §117.3123 is necessary to ensure that cement kilns located at existing accounts in Ellis County, regardless of date placed into service, are subject to the emission control requirements for the Dallas-Fort Worth eight-hour attainment demonstration described in §117.3123 and other associated requirements discussed later in this preamble.

New §117.3103(b) specifies that any account in Ellis County that had no portland cement kilns in operation prior to January 1, 2001, is exempt from new §117.3123. All existing accounts are regulated under the source cap control measure in new §117.3123, including any new kilns placed into service at those accounts. Any newly permitted accounts will be addressed under New Source Review permitting. Adopted §117.3103(c) specifies that, after the compliance date specified in new §117.9320(c), §117.3110 and §117.3120 do not apply to cement kilns subject to §117.3123 between March 1 and October 31 of each calendar year. This change is necessary because the source cap in §117.3123 only applies during ozone season and the current one-hour ozone rule requirements will remain in effect during non-ozone season. As discussed elsewhere in this preamble, these changes were made based on comments received.

Section 117.3110, Emission Specifications

New §117.3110 incorporates the rule language regarding emission specifications from existing §117.265. New §117.3110(a) - (e) incorporate the rule language from existing §117.265(a) - (e).

Section 117.3120, Source Cap

New §117.3120 incorporates the rule language from existing §117.283. New §117.3120(a) - (f) incorporate the rule language from existing §117.283(a) - (f), respectively. In addition, the commission adopts a new equation in §117.3120(a) that incorporates the equation in existing §117.283(a). The new equation in §117.3120(a) presents the equation in a format consistent with other equations in Chapter 117 and provides a definition for each term used in the equation.

Section 117.3123, Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements

The commission is adopting a new §117.3123, entitled Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements, that includes a new mandatory source cap requirement for all units located in Ellis County. New §117.3123(a) specifies that the owner or operator of any portland cement kiln in Ellis County shall not allow the total NO _X emissions from all cement kilns located at the account to exceed the source cap limitation in new §117.3123(b). New §117.3123(a) also specifies that compliance with the source cap must be in accordance with the compliance schedule in new §117.9320(c). Based on comments received, the adopted subsection (a) also specifies that the source cap only applies from March 1 through October 31 of each calendar year. Owners or operators must demonstrate compliance with the 30-day rolling average cap beginning on March 31 of each calendar year. The change will provide time for owners or operators to transition from non-ozone season controls to controls associated with the source cap under §117.3123. This change will not significantly impact the Dallas-Fort Worth eight-hour ozone attainment demonstration because ozone exceedances rarely occur during March.

New §117.3123(b) specifies that the NO _X source cap for an account subject to new §117.3123 must be calculated according to the equation in new §117.3123(b). Based on comments received and further evaluation, the commission has revised the source cap calculation methodology. For the adopted rule, the source cap for an account is determined according to the three-year average production rate of the kilns located at the account plus one standard deviation of total production at an account, by kiln type (wet or dry), over the same three years, and a pound per ton of clinker NO_X emission factor based on kiln type. The source cap, identified as resultant Cap _8hour in the equation, is the total allowable NO _X emissions from all cement kilns located at an account in tons per day and on a 30-day rolling average basis. The NO _X emission factor to determine the cap contribution from each dry preheater-precalciner or precalciner kiln, variable K _D , is 1.7 pounds per ton of clinker. The NO _X emission factor to determine the cap contribution from each long wet kiln, variable K _W , is 3.4 pounds per ton of clinker. Variables N _D and N _W are the average annual production in tons of clinker of dry preheater-precalciner or precalciner kilns and long wet kilns, respectively, located at the account for the calendar years 2003, 2004, and 2005, as reported to the Industrial Emissions Assessment Section of the commission, plus one standard deviation of total production at an account, by kiln type (wet or dry), over the same three years. The total source cap for an account subject to new §117.3123 is the product of variables K_D and N _D , plus the product of variables K _W and N _W , then converted to tons per day. Cement kilns that began operation after calendar year 2005 are excluded from the calculation of the source cap; however, as described later in this preamble, NO _X emissions from cement kilns that began operation after calendar year 2005 are included in the total emissions calculation when determining compliance with the source cap.

The emission factors used for the source cap calculation, K _D and K _W , were determined based on actual emission data from the sources located in Ellis County. The wet kiln NO_X emission factor, 3.4 pounds per ton of clinker, is based on an approximate 35% reduction from Ash Grove's actual average pound per ton of clinker emission rate from 2003 to 2005. The NO _X emission factor for dry preheater-precalciner or precalciner kilns, 1.7 pounds per ton of clinker, is based on TXI's dry preheater-precalciner or precalciner kiln actual overall average pound per ton of clinker emission rate since 2001. The 1.7 pounds per ton of clinker emission factor represents an approximate 45 - 50% reduction from Holcim's pound per ton of clinker emission rate for 2001. The commission's rationale for the different approaches is to recognize the best performing kilns for each category while establishing a cap approach that requires feasible and equitable reductions from all three sites. The different approaches for the two types of kilns is also due to significant differences in the pound per ton of clinker NO _X emissions from kilns of the same category located at different sites. While TXI's dry preheater-precalciner or precalciner kiln is currently meeting or doing better than 1.7 pounds NO _X per ton of clinker, the NO _X emissions from TXI's wet kilns are substantially higher than Ash Grove's wet kilns. Therefore, under the source cap approach and because the TXI facility in Ellis County has both types of cement kilns, the emission factor used for the dry kilns must be balanced against the more stringent emission factor for wet kilns.

The revised source cap calculation is more equitable than the proposed source cap because it includes all kilns in operation at the three accounts impacted by this rulemaking. The new approach also recognizes those kilns that are performing better, on a pound per ton of clinker basis, than other kilns in the same category. In addition, based on evaluation of recent emission inventory trend data, the proposed source cap approach may have inadvertently penalized certain sources that have made substantial reductions since 2001 by requiring those sources to potentially make greater reductions than certain other sources that have shown an upward trend in NO _X emissions during the same time. Under the adopted source cap approach, the total NO _X source cap for all three accounts will be approximately 16.4 tpd, only 0.6 tpd higher than the emissions modeled for the low-end controls based on the cement kiln study.

New §117.3123(c) specifies the NO _X emission monitoring requirements of new §117.3142 must be used to demonstrate continuous compliance with the source cap. The adopted §117.3123(d) is revised to specify the requirements that apply to kilns that were not operational prior to calendar year 2006, to reflect the revised source cap approach. New §117.3123(d)(1) specifies that a cement kiln not in operation prior to calendar year 2006 is subject to the source cap but must not be included in the source cap calculation in new §117.3123(b). New subsection (d)(2) specifies that the requirements of new §117.3142 and §117.3145 apply, and new subsection (d)(3) specifies that the NO _X emissions from the kiln must be included in the calculation of the 30-day rolling average for compliance with the source cap. The intent of the source cap in new §117.3123 is to establish a maximum cap on the total NO _X emissions from cement kilns at each account, based on the kilns in operation in calendar years 2003 through 2005. The provisions of new §117.3123(d) prohibit expanding the source cap based on new units installed after calendar year 2005. Also for subsections (c) and (d), rolling 30-day average is revised as 30-day rolling average to be consistent with the terminology used in the cap equation.

The commission adopts a new §117.3123(e) that requires the owner or operator to submit a control plan for compliance with the source cap. Control plans are required to be submitted to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office. Control plans submitted to the Chief Engineer's Office should be submitted to the attention of the Air Quality Planning Section. New §117.3123(e)(1) specifies the minimum content of the control plan, including: the emission point number for each kiln at the account; the facility identification number for each kiln at the account; the source cap for the account calculated according to the equation in new §117.3123(b); and a description of the control measures that have been or will be implemented for each cement kiln for compliance with the source cap. New §117.3123(e)(2) provides for revisions to the control plan and specifies that the revised control plan must be submitted with any required permit application. The revised control plan must adhere to the requirements of the rule.

New §117.3123(f) specifies an ammonia emission specification of 10 ppmv at 7% O ₂ for units that inject ammonia or urea to control NO _X emissions. Because SNCR and SCR are among the potential control technologies available for compliance with the source cap, an ammonia emission specification is necessary to prevent excessive ammonia slip. In addition, rolling 24-hour average is revised as 24-hour rolling average to be consistent with other terminology in the section.

Finally, new §117.3123(g) provides compliance flexibility by allowing owners or operators to comply with the source cap limitation, in whole or in part, using emission reduction credits as provided in new §117.9800.

Section 117.3125, Alternative Case Specific Specifications

New §117.3125 sets forth provisions for alternative case specific emission specifications for ammonia. Section 117.3125(a) specifies that the executive director may approve emission specifications different from the ammonia specification for a unit where a person can demonstrate that the affected unit cannot attain the ammonia specification of §117.3123(f). Subsection (a)(1) specifies that the executive director shall consider, on a case-by-case basis, the technological and economic circumstances of the individual unit. Subsection (a)(2) requires that the executive director must determine that such specifications are the result of the lowest emission specification the unit is capable of meeting after the application of controls to meet the NO_X emission specifications of §117.3123. Subsection (a)(3) specifies that the executive director, in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant at which the unit is located to meet emission specifications through system-wide averaging at maximum capacity. Finally, §117.3125(b) specifies that any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision and that the requirements of §50.139 apply to §117.3125.

Section 117.3140, Continuous Demonstration of Compliance

New §117.3140 incorporates the rule language from existing §117.243, concerning continuous demonstration of compliance. New §117.3140(a) - (c) incorporate the rule language from existing §117.273(a) - (c), respectively. In addition, for new §117.3140(c)(2), the cross-reference to existing §117.213(f)(2) - (7) is changed to new §117.8100(b) because the applicable requirements for PEMS in existing §117.213(f)(2) - (7) are incorporated in new §117.8100(b).

Section 117.3142, Emission Testing and Monitoring for Eight-Hour Attainment Demonstration

New §117.3142 specifies emission testing and monitoring requirements for units subject to the source cap in new §117.3123. New §117.3142(a) specifies that the owner or operator of any portland cement kiln subject to new §117.3123 must comply with the monitoring requirements in new §117.3142(a)(1) - (4). New §117.3142(a)(1) specifies that the NO _X monitoring requirements of §117.3140 apply. The affected facilities are already required to monitor NO _X emissions under either existing §117.473, which is incorporated in the new §117.3140, or due to TCEQ air permit requirements. In addition, new §117.3142(a)(1)(A) - (C) specify additional requirements for NO _X CEMS. New subparagraph (A) requires that each individual stack must be analyzed for NO _X separately for single units with multiple exhaust stacks. New subparagraph (B) allows sharing of CEMS among units or among multiple exhaust stacks on a single unit provided the conditions of subparagraph (B)(i) and (ii) are met. New §117.3142(a)(1)(B)(i) requires that exhaust of each stack is analyzed and reported separately, and new §117.3142(a)(1)(B)(ii) requires that the CEMS meet the certification requirements in §117.3140(b) for each exhaust stream while the CEMS is operating in time-shared mode. New §117.3142(a)(1)(C) requires that all bypass stacks be monitored to quantify emissions directed through the bypass stack. If the CEMS is located upstream of the bypass stack to satisfy this requirement, the new clauses (i) and (ii) specify additional requirements for monitoring of bypass stacks. New clause (i) specifies that no stream from other potential sources of NO _X may be introduced between the CEMS and the bypass stack. New clause (ii) requires the owner or operator to install, operate, and maintain a continuous monitoring system to record automatically the date, time, and duration of each event when the bypass stack is open. These additional requirements for CEMS are necessary to ensure that NO _X emissions are accurately quantified for compliance with the source cap in new §117.3123.

The commission also adopts a new §117.3142(a)(2) to require monitoring of stack exhaust flow rate using the monitoring specifications of 40 CFR Part 60, Appendix B, Performance Specification 6, or 40 CFR Part 75, Appendix A. This new flow monitoring requirement is necessary to ensure that total NO_X emissions are accurately quantified for compliance with the new source cap in new §117.3123. The affected facilities in Ellis County are already required to perform similar flow monitoring due to the TCEQ air permit requirements. Therefore, this new flow monitoring requirement should not require the installation of any new monitoring equipment. In addition, the certification requirements in new §117.3142(a)(2) are similar to the flow monitor certification requirements already required for the monitoring systems by permit.

For units that inject ammonia or urea to control NO _X emissions, new §117.3142(a)(3) requires that ammonia emissions must be monitored according to either new §117.8130(1), (2), or (4). These ammonia monitoring procedures include the mass balance approach, the oxidation of ammonia to nitric oxide approach, or other methods approved by the executive director. The method of stain tubes method in §117.8130(3) is not appropriate for cement kilns in determining compliance with the ammonia emission specification in §117.3123(f) due to the infrequency of sample collection using this method and the potential high variability of ammonia emissions from kilns using urea or ammonia injection for NO _X control. Based on comments received, the commission has revised the adopted §117.3142(a)(3) to clarify that ammonia monitoring is required for kilns that inject ammonia or urea for NO _X control regardless of fuel type. In addition, for the adopted §117.3142(a)(3), the commission adds language that specifies the ammonia monitoring requirements only apply from March 1 to October 31, or any other time the owner or operator injects ammonia or urea for NO _X control. This change is necessary because the source cap under §117.3123 only applies during ozone season, when the sources are mostly likely to be using NO_X control technologies that use ammonia or urea injection. New §117.3142(a)(4) specifies that the installation of monitors must be performed in accordance with the schedule specified in §117.9320(c).

The commission also adopts a new §117.3142(b) that specifies the calculations and equations used to demonstrate compliance with the source cap. As discussed elsewhere in this preamble, the source cap under §117.3123 only applies from March 1 to October 31. Therefore, the commission has revised the adopted §117.3142(b) to specify that the calculation requirements of subsection (b) only apply during that time frame so owners or operators are not required to perform the calculations specifically associated with the source cap when the cap does not apply. New §117.3142(b)(1) specifies the equation used to calculate hourly NO _X emissions from each kiln, in pounds per hour, identified as resultant "EH" in the equation. Variable "C" is the block hour average NO _X concentration in ppmv, dry basis. Variable "F" is the block hour average exhaust flow rate in dry standard cubic feet per minute. Based on comments received, the commission has removed the requirement that variables "C" and "F" must be on a 7% oxygen corrected basis. Variable "K" is a conversion factor from 40 CFR 60, Appendix A, Method 19 for calculating NO _X mass emission rates from ppmv concentrations. New §117.3142(b)(2) specifies the equation for calculating the total daily NO _X emissions, expressed as resultant "ED" in the equations, in tons per day from the hourly emissions determined according to new subsection (b)(1) and the number of hours of operation per day for each kiln, expressed as variable "N" in the equation. New §117.3142(b)(3) specifies the equation for determining the 30-day rolling average NO _X emissions, expressed as resultant "E _30day " in the equation, in tons per day for the account, computed for the preceding 30 days. The 30-day rolling average is calculated based on the total daily NO _X emissions from each kiln determined according to new subsection (b)(2), the number of kilns located at the account, expressed as variable "K," and the preceding 30 days, expressed as variable "N" in the equation. The term rolling 30-day average in the proposed subsection (b)(3) was revised as 30-day rolling average for the adopted rule to be consistent with the cap equation in §117.3123.

Section §117.3145, Notification, Recordkeeping, and Reporting Requirements

New §117.3145 incorporates the rule language from existing §117.279, concerning notification, recordkeeping, and reporting requirements. New §117.3145(a) - (c) incorporates the notification, recordkeeping, and reporting rule language from existing §117.279(a) - (c). In addition, modifications to the existing rule language and additional requirements are for the sources subject to the new source cap in §117.3123. For new §117.3145(a), concerning notification, the commission adds a reference to new §117.3142 to the existing language from §117.279. This change is necessary to require notification of any CEMS or PEMS performance evaluation for monitoring systems required under §117.3142. Similarly, the commission adds a reference to new §117.3142 in new §117.3145(b) to require reporting of test results for any CEMS or PEMS relative accuracy test audit. New §117.3145(c)(1) is revised to specify that for each kiln subject to §117.3110 or §117.3120, the records in subparagraphs (A) - (C) are required. This change is necessary to clarify that sources subject to the source cap in §117.3123 are not required to maintain the records under §117.3145(c)(1)(A) - (C). In addition, for new §117.3145(c)(1)(B), the commission is revising the language from existing §117.279(c)(1)(B) to specify that records of the production of clinker should be in United States short tons. Metric tons are typically used by the cement manufacturing industry to express production and this change is necessary to clarify the appropriate units for the records and for the emissions calculated in pounds per ton of clinker.

New §117.3145(c)(4) specifies new recordkeeping requirements for each kiln subject to the source cap in new §117.3123 and the monitoring requirements of new §117.3142. New §117.3145(c)(4)(A) requires records of the control plan required by new §117.3123. New §117.3145(c)(4)(B) and (C) require hourly records of the average NO _X concentration in ppmv, and hourly records of the NO _X emission in pounds per hour. The requirement to correct NO _X concentrations to 7% oxygen has been removed based on comments received. New §117.3145(c)(4)(D) and (E) require daily records of the NO _X emissions from each kiln in tons per day and daily records of the NO _X emissions in tons per day expressed as 30-day rolling average. As discussed elsewhere in this preamble, rolling 30-day average was revised to be consistent with §117.3123. New §117.3145(c)(4)(F) requires hourly records of the average exhaust gas flow rate in dry standard cubic feet per minute. The requirement to correct flow rate to 7% oxygen has been removed based on comments received. New §117.3145(c)(4)(G) requires records of the ammonia monitoring required under new §117.3142(a)(3).

DIVISION 3, WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

The commission adopts a new Chapter 117, Subchapter E, Division 3 to incorporate the rule language from existing Chapter 117, Subchapter D, Division 1, regarding water heaters, small boilers, and process heaters.

Section §117.3200, Applicability

New §117.3200 incorporates the applicability rule language from existing §117.461.

Section 117.3201, Definitions

New §117.3201, concerning definitions, incorporates the rule language from existing §117.460. In addition, the commission deletes the definitions of direct-vent unit and power-vent unit. These definitions were added in the previous rulemaking because direct-vent and power-vent units were not required to meet the 10 ng/J NO _X emission standard. Because new §117.3205, concerning emission specifications, specifies the same standard for all Type 0 water heaters manufactured on or after July 1, 2002, the separate emission specifications and definitions for direct-vent and power-vent units are superfluous. Subsequent definitions are renumbered accordingly.

Section 117.3203, Exemptions

New §117.3203 incorporates the rule language regarding exemptions from existing §117.463. In addition, for new §117.3203(3), the commission changes the exemption in existing §117.463(3), concerning Type 0 units used exclusively to heat swimming pools and hot tubs. New §117.3203(3) adds language to allow Type 1 and 2 units at single-family residences to qualify for this exemption. It was the commission's intent that the exemption in existing §117.463(3) apply to water heaters used exclusively to heat swimming pools and hot tubs at single-family residences. Only Type 0 units were anticipated to be used for this purpose. The commission has become aware that some single-family residences have installed Type 1 or 2 units to heat swimming pools and hot tubs. Therefore, the commission is adopting this change to clarify the intent of the exemption. Type 1 and 2 units installed after the appropriate compliance dates at multi-family residences or commercial properties are still required to comply with emission limits set forth in new §117.3205.

Section 117.3205, Emission Specifications

New §117.3205, concerning emission specifications, incorporates the rule language from existing §117.465. Also, the commission adopts changes to existing §117.465(b) to implement the requirements of HB 965. For new §117.3205(b)(1), the language "but no later than December 31, 2006," in existing §117.465(b)(1) is removed to clarify that Type 0 units manufactured after July 1, 2002, must comply with the requirements in subsection (b)(1)(A) and (B) of this section. As previously discussed in this preamble, the existing NO _X emission specifications, 10 ng/J of heat output or 15 ppmv at 3.0% O ₂ , in existing §117.465(b)(2)(A) for Type 0 units (except power-vent and direct-vent units) are repealed. Therefore, new §117.3205(b) excludes these emission specifications for Type 0 units.

In addition, the emission specifications for power-vent and direct-vent units in existing §117.465(b)(2)(B) are identical to the emission specifications in existing §117.465(b)(1) and new §117.3205(b)(1). Therefore, new §117.3205(b) excludes the emission specifications for power-vent and direct-vent units from existing §117.465(b)(3). All Type 0 gas-fired water heaters, including power-vent and direct vent units, manufactured on or after July 1, 2002, are subject to the NO _X emissions specifications in new §117.3205(b)(1). Finally, new §117.3205(b)(2) and (3) incorporate the rule language from existing §117.465(b)(4) and (5), respectively, concerning the emission specifications for Type 1 and 2 units.

Section 117.3210, Certification Requirements

New §117.3210 incorporates the rule language from existing §117.467, concerning certification requirements. New §117.3210(a) and (b) incorporate the requirements from existing §117.467(a) and (b), respectively. In addition, for new §117.3210(a), the commission removes the date reference for Test Method 7. This change will allow the most recent versions of EPA Test Methods 7 through 7E to be used for the certification testing.

Section 117.3215, Notification and Labeling Requirements

New §117.3215 incorporates the rule language from existing §117.469, concerning notification and label requirements.

DIVISION 4, EAST TEXAS COMBUSTION

The commission adopts a new Chapter 117, Subchapter E, Division 4, regarding new requirements for stationary, gas-fired reciprocating internal combustion engines in specified counties in the Northeast Texas area. The new Subchapter E, Division 4 is a part of the commission's eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area. Any engines located in the Dallas-Fort Worth eight-hour ozone nonattainment area are not subject to this rule. Such engines are either currently regulated by equivalent or more stringent requirements under other divisions of Chapter 117 or are regulated in separate rulemakings concurrent with this rule. Therefore, applying this rule to the Dallas-Fort Worth eight-hour ozone nonattainment counties would be superfluous.

Section 117.3300, Applicability

New §117.3300 specifies that the new division applies to stationary, gas-fired reciprocating internal combustion engines in certain counties in the Northeast Texas area. The specific counties included in the applicability for this rulemaking include the following counties: Anderson, Brazos, Burleson, Camp, Cass, Cherokee, Franklin, Freestone, Gregg, Grimes, Harrison, Henderson, Hill, Hopkins, Hunt, Lee, Leon, Limestone, Madison, Marion, Morris, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, Shelby, Smith, Titus, Upshur, Van Zandt, and Wood Counties. Based on comments received, Bosque, Cooke, Grayson, Hood, Somervell, and Wise Counties have been removed from the applicability of the adopted rule.

Section 117.3303, Exemptions

New §117.3303 specifies those stationary, reciprocating internal combustion engines that are exempt from the requirements of Chapter 117, Subchapter E, Division 4. Based on comments received, engines with a hp rating less than 240 hp and all gas-fired lean-burn engines are exempt from the rule. Diesel engines and dual-fuel engines are also exempt from the rule. Section 117.3303 also exempts engines used: for research and testing; for performance verification and testing; solely to power other engines and gas-turbines during startups; exclusively for emergency situations, except for 100 hours of operation for testing and maintenance purposes; in response to and during any officially declared disaster or state of emergency; or directly and exclusively by the owner or operator for agricultural operations necessary for growing crops or raising of fowl or animals. While the exemption in §117.3303(5) was not specifically commented on, the commission has revised similar exemptions in §117.403 and §117.2103 based on comments received to allow for up to 100 hours per year for testing and maintenance purposes. The commission has revised §117.3303(5) to be consistent with the adopted changes to the similar exemptions in §117.403 and §117.2103.

Section 117.3310, Emission Specifications for Eight-Hour Attainment Demonstration

The emission specifications for attainment demonstration, and additional requirements related to the emission specifications, are included in new §117.3310. As discussed elsewhere, gas-fired lean-burn engines are exempt from the adopted rule based on comments received. Provisions in the adopted §117.3310 related to gas-fired lean-burn engines have been modified or removed to reflect this change. Section 117.3310(a) specifies the NO _X emission specifications for stationary gas-fired reciprocating internal combustion engines. New §117.3310(a)(1) establishes a 1.00 g/hp-hr NO _X emission specification for gas-fired rich-burn engines with a maximum rated capacity less than 500 hp. The NO _X emission specifications for gas-fired rich-burn engines with a maximum rated capacity equal to or greater than 500 hp are in new §117.3310(a)(2) and include 0.60 g/hp-hr for engines fired on landfill gas and 0.50 g/hp-hr on all other gas-fired rich-burn engines.

NSCR technology is anticipated to be the primary control technology that will be used for rich-burn engines to meet the emission specifications. Some engines with maximum rated capacities equal to or greater than 500 hp may have to install an additional catalyst module with the NSCR control package in order to comply with the more stringent 0.50 g/hp-hr emission specification. No landfill gas-fired rich-burn engines were identified in the counties impacted by this rule. Should a landfill gas-fired rich-burn engine become subject to this rule, the 0.60 g/hp-hr emission specification is consistent with the emission specifications for this category of engines in the Houston-Galveston-Brazoria ozone nonattainment area and is achievable through combustion modifications rather than installation of NSCR.

A block one-hour averaging time for determining compliance with the NO_X emission specifications is specified in new §117.3310(b). The block one-hour average must be calculated in the units of the applicable standard. New §117.3310(c) specifies that the maximum rated capacity used to determine the applicability of the emission specifications of §117.3310(a) or the exemption status of a unit under §117.3303(1) must be the greater of the maximum rated capacity as of December 31, 2000, or the maximum rated capacity after December 31, 2000.

New §117.3310(d) specifies that a unit's classification is determined by the most specific classification applicable to the unit as of December 31, 2000. For example, a unit that is classified as a stationary gas-fired engine as of December 31, 2000, but subsequently is authorized to operate as a dual-fuel engine, must be classified as a stationary gas-fired engine for the purposes of this rule. As discussed elsewhere in this preamble, the commission has removed the CO emission specification from §117.3310(e) based on comments received. The adopted §117.3310(e) establishes the emission specification for ammonia and specifies that the owner or operator of any unit subject to the NO _X emission specifications of subsection (a) shall not allow the discharge into the atmosphere ammonia emissions in excess of 10 ppmv at 3.0% O ₂ , dry basis. The averaging times for the ammonia specification are specified in new §117.3310(e)(1) and (2). Paragraph (1) specifies a block one-hour averaging period for units not equipped with a CEMS or PEMS for ammonia. Paragraph (2) specifies a rolling 24-hour averaging period for units equipped with CEMS or PEMS for ammonia. Finally, new §117.3310(f) specifies that an owner or operator may use emission reductions credits as specified in §117.9800 of this title to comply with the NO _X emission specifications of this section.

Section 117.3325, Alternative Case Specific Specifications

New §117.3325, Alternative Case Specific Specifications, sets forth provisions for alternative case specific emission specifications for ammonia. As discussed elsewhere in this preamble, the commission is not adopting the CO emission specification that was proposed in §117.3310(e). Therefore, all references to CO in the adopted §117.3325 have been removed. Section 117.3325(a) specifies that the executive director may approve emission specifications different from the ammonia specifications for a unit where a person can demonstrate that the affected unit cannot attain the ammonia specification of §117.3310(e). Subsection (a)(1) specifies that the executive director shall consider on a case-by-case basis the technological and economic circumstances of the individual unit. Subsection (a)(2) requires that the executive director must determine that such specifications are the result of the lowest emission specification the unit is capable of meeting after the application of controls to meet the NO _X emission specifications of §117.3310. Subsection (a)(3) specifies that the executive director, in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant at which the unit is located to meet emission specifications through system-wide averaging at maximum capacity. Finally, §117.3325(b) specifies that any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision, and that the requirements of §50.139 (relating to Motion to Overturn Executive Director's Decision) apply to §117.3325.

Section 117.3330, Operating Requirements

Operating requirements for units subject to the emission specifications of the division are listed in new §117.3330. New §117.3330(a) specifies that the owner or operator shall operate any unit subject to the emission specifications in compliance with those specifications. New §117.3330(b) specifies that all units subject to the emission specifications must be operated so as to minimize NO _X emissions consistent with the emission control techniques selected, over the unit's operating or load range during normal operations. New §117.3330(b)(1) requires that each unit controlled with post-combustion control techniques must be operated such that the reducing agent injection rate is maintained to limit NO _X concentrations to less than or equal to the NO _X concentrations achieved at maximum rated capacity. New §117.3330(b)(2) requires that each stationary internal combustion engine controlled with NSCR must be equipped with an automatic AFR controller that operates on exhaust O ₂ or CO control and maintains the AFR in the range required to meet the engine's applicable emission specifications. New §117.3330(b)(3) requires that each stationary internal combustion engine must be checked for proper operation according to new §117.8140(b). As discussed elsewhere in this preamble, the commission is not adopting the CO emission specification that was proposed in §117.3310(e). Therefore, the adopted §117.3330(b)(3) is revised to specify that the engine must be checked for proper operation by recorded NO _X measurements according to §117.8140(b). This testing includes recorded measurements of NO _X emissions at least quarterly and as soon as practicable within two weeks after each occurrence of engine maintenance that may reasonably be expected to increase emissions, O ₂ sensor replacement, catalyst cleaning, or catalyst replacement. New §117.8140(b) also specifies that stain tubes and portable NO _X analyzers are acceptable for this documentation. The quarterly emission testing is not required for those engines whose monthly run time does not exceed ten hours; however, this exemption does not apply to the requirement to test emissions after installation of controls, major repair work, or any time the owner or operator has reason to believe the emissions may have changed. In addition, while not specifically commented on, the commission has become aware that under the proposed rule an engine equipped with NO _X CEMS or PEMS would still be required to perform this quarterly emission testing. Therefore, §117.3330(b)(3) is also revised to specify that engines equipped with a CEMS or PEMS to monitor NO _X are exempt from the requirements of subsection (b)(3).

Section 117.3335, Monitoring, Notification, and Testing Requirements

New §117.3335 specifies the monitoring, notification, and testing requirements. As discussed elsewhere in this preamble, the commission is not adopting the CO emission specification that was proposed in §117.3310(e). Because the adopted rule excludes a CO emission specification, the requirements for performing CO testing have also been removed from §117.3335. New §117.3335(a) and (b) require that if the owner or operator installs a CEMS or PEMS to monitor O ₂ or NO _X , the CEMS or PEMS must meet the requirements of new §117.8100(a) or (b), as applicable. New §117.3335(c) specifies that if the owner or operator elects to install CEMS or PEMS, the installation and certification of the monitoring systems must be in accordance with the compliance schedule in §117.9340.

New §117.3335(d) lists the testing requirements of units subject to the emission specifications of §117.3310. Section 117.3335(d)(1) requires that each unit must be tested for NO _X and O₂ emissions and subsection (d)(2) requires that each unit that injects urea or ammonia for NO _X control be tested for ammonia emissions. Subsection (d)(3) requires that all testing be conducted according to new §117.8000, which includes the general stack testing procedures and methods for Chapter 117. The specific requirements of new §117.8000 are discussed later in this preamble. New §117.3335(d)(3) also specifies the owner or operator of a natural gas-fired engine may use ASTM D6522-00 to perform the NO _X and O ₂ testing required in lieu of the methods specified in §117.8000. If ASTM D6522-00 is used, the test report must contain the information specified in new §117.8010.

New subsection (d)(4) requires that test results must be reported in the units of the applicable emission limits and averaging periods. New §117.3335(d)(5) specifies that, for units equipped with CEMS or PEMS, the CEMS or PEMS must be installed and operational before testing under this subsection. Verification of operational status must, at a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device. New §117.3335(d)(6) specifies that on units operating with CEMS or PEMS, initial compliance with the emission specifications of §117.3310 of this title may be demonstrated using the CEMS or PEMS, after monitor certification testing, in lieu of the methods specified in §117.3335(d)(3).

New §117.3335(d)(7) specifies retesting requirements for units not operating with CEMS or PEMS. Engines must be periodically tested according to new §117.8140(a). The specific procedures and requirements in new §117.8140(a) are discussed later in this preamble. In addition, new §117.3335(d)(7)(A) requires retesting within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate. New §117.3335(d)(7)(B) allows retesting at the discretion of the owner or operator after any modification that could reasonably be expected to decrease the NO _X emission rate, including, but not limited to, installation of post-combustion controls, low-NO _X burners, low excess air operation, staged combustion (for example, overfire air), FGR, and fuel-lean and conventional (fuel-rich) reburn. New §117.3335(d)(8) specifies that testing be performed in accordance with the schedule specified in §117.9340.

New §117.3335(e) requires that each unit that injects urea or ammonia into the exhaust stream for NO _X control must be monitored according to one of the ammonia monitoring procedures specified in new §117.8130. These ammonia monitoring procedures include the use of the mass balance equation in §117.8130(1), the molybdenum oxidizer and NO _X analyzer approach in §117.8130(2), the use of stain tubes in §117.8130(3), or other methods approved by the executive director as allowed in §117.8130(4). New §117.3335(f) requires the owner or operator of an affected source to submit written notification of any CEMS or PEMS RATA or testing required under this section, except for any testing related to the ammonia monitoring specified in §117.3335(e), to the appropriate regional office and any local air pollution control agency having jurisdiction at least 15 days in advance of the date of RATA or testing.

Section 117.3345, Recordkeeping and Reporting Requirements

New §117.3345(a) requires that the owner or operator of a unit subject to the emission specifications of §117.3310 maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the EPA, or local air pollution control agencies having jurisdiction. New §117.3345(a)(1) requires that records of hourly emissions be maintained for each unit using a CEMS or PEMS. New §117.3345(a)(2) specifies records for each stationary internal combustion engine subject to the emission specifications of §117.3310, including: emissions measurements required by §117.3330(b)(3); and catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken. As discussed elsewhere in this preamble, the commission is not adopting the CO emission specification that was proposed in §117.3310(e) and the requirement for CO testing have also been excluded from §117.3330(b)(3). Therefore, the recordkeeping requirement proposed in subsection (a)(3) for records of the CO measurements specified in §117.3330(b)(3) is not included in the adopted §117.3345(b). New subsection (a)(3) requires records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring systems. New subsection (a)(4) requires the owner or operator to maintain records of the results of performance testing and new subsection (a)(5) requires records of the ammonia monitoring required by §117.3335(e).

New §117.3345(b) specifies that written records of the number of hours of operation for each day's operation must be made for each engine claimed exempt under §117.3303(5) of this title or §117.3330(b)(3) of this title. New §117.3330(b)(3) references the engine testing provisions in new §117.8140(b), which also includes an exemption for which new §117.3345(b) will require written records. In addition, for each engine claimed exempt under §117.3303(5) of this title, written records must be maintained that reflect the purpose of engine operation and, if operation was for an emergency situation, identification of the type of emergency situation and the start and end times and dates of the emergency situation. The records must be maintained for at least five years and must be made available upon request to representatives of the executive director, the EPA, or any local air pollution control agency having jurisdiction.

New §117.3345(c) specifies that, except for the ammonia monitoring requirements of §117.3335(e), the owner or operator of an affected unit must furnish the appropriate regional office and the Office of Compliance and Enforcement reports of all testing and monitor certification required under new §117.3335. Reports must be submitted for review and approval within 60 days after completion of the testing and must contain the information specified in new §117.8010. In addition, in response to comments received, the commission has revised §117.3345(c) to clarify that the quarterly testing under §117.3330(b)(3) is not subject to the reporting requirements of §117.3345(c).

SUBCHAPTER F, ACID MANUFACTURING

The commission adopts a new Chapter 117, Subchapter F, entitled Acid Manufacturing, that incorporates the divisions and associated rule language of the existing Chapter 117, Subchapter C, Acid Manufacturing.

DIVISION 1, ADIPIC ACID MANUFACTURING

The commission adopts a new Chapter 117, Subchapter F, Division 1, entitled Adipic Acid Manufacturing, that incorporates rule language from the existing Chapter 117, Subchapter C, Division 1, Adipic Acid Manufacturing.

Section 117.4000, Applicability

New §117.4000 incorporates the rule language from existing §117.301, concerning the applicability for adipic acid manufacturing.

Section 117.4005, Emission Specifications

New §117.4005 incorporates the rule language from existing §117.305 concerning the emission specifications for units subject to the Adipic Acid Manufacturing Division.

Section 117.4025, Alternative Case Specific Specifications

New §117.4025 incorporates the rule language from existing §117.321, concerning provisions for alternative case specific specifications for units that cannot attain the emission specifications in new §117.4005.

Section 117.4035, Initial Demonstration of Compliance

New §117.4035 incorporates the rule language from existing §117.311, concerning initial demonstration of compliance for units subject to the emission specifications in new §117.4005.

Section 117.4040, Continuous Demonstration of Compliance

New §117.4040 incorporates the rule language from existing §117.313, concerning continuous demonstration of compliance for units subject to the emission specifications in new §117.4005. New §117.4040(a) - (e) incorporate the rule language from existing §117.313(a) - (e). In addition, for new §117.4040(c), the reference to existing §117.213(f) is changed to reference new §117.8100(b). The requirements for PEMS in existing §117.213(f) are incorporated in new §117.8100(b).

Section 117.4045, Notification, Recordkeeping, and Reporting Requirements

New §117.4045 incorporates the rule language from existing §117.319, concerning notification, recordkeeping, and reporting requirements for affected facilities subject to the emission specifications in new §117.4005.

Section 117.4050, Control Plan Procedures

New §117.4050 incorporates the rule language from existing §117.309, concerning the control plan procedures for persons affected by the division.

DIVISION 2, NITRIC ACID MANUFACTURING - OZONE NONATTAINMENT AREAS

The commission adopts a new Chapter 117, Subchapter F, Division 2, entitled Nitric Acid Manufacturing - Ozone Nonattainment Areas, that incorporates rule language from the existing Chapter 117, Subchapter C, Division 2, Nitric Acid Manufacturing - Ozone Nonattainment Areas.

Section 117.4100, Applicability

New §117.4100 incorporates the rule language from existing §117.401, concerning the applicability for nitric acid manufacturing in ozone nonattainment areas.

Section 117.4105, Emission Specifications

New §117.4105 incorporates the rule language from existing §117.405, concerning the emission specifications for affected nitric acid manufacturing units in ozone nonattainment areas.

Section 117.4125, Alternative Case Specific Specifications

New §117.4125 incorporates the rule language from existing §117.421, concerning provisions for alternative case specific specifications for units that cannot attain the emission specifications in new §117.4105.

Section 117.4135, Initial Demonstration of Compliance

New §117.4135 incorporates the rule language from existing §117.411, concerning initial demonstration of compliance for units subject to the emission specifications in new §117.4105.

Section 117.4140, Continuous Demonstration of Compliance

New §117.4140 incorporates the rule language from existing §117.413, concerning continuous demonstration of compliance for units subject to the emission specifications in new §117.4105. New §117.4140(a) - (e) incorporate the rule language from existing §117.413(a) - (e). In addition, for new §117.4140(c), the reference to existing §117.213(f) is changed to reference new §117.8100(b). The requirements for PEMS in existing §117.213(f) are incorporated in new §117.8100(b).

Section 117.4145, Notification, Recordkeeping, and Reporting Requirements

New §117.4145 incorporates the rule language from existing §117.419, concerning notification, recordkeeping, and reporting requirements for affected facilities subject to the emission specifications in new §117.4105.

Section 117.4150, Control Plan Procedures

New §117.4150 incorporates the rule language from existing §117.409, concerning the control plan procedures for persons affected by the division.

DIVISION 3, NITRIC ACID MANUFACTURING - GENERAL

The commission adopts a new Chapter 117, Subchapter F, Division 3, entitled Nitric Acid Manufacturing - General, that incorporates rule language from the existing Chapter 117, Subchapter C, Division 3, Nitric Acid Manufacturing - General.

Section 117.4200, Applicability

New §117.4200 incorporates the rule language from existing §117.451, concerning the general applicability for nitric acid production units, except for units in applicable ozone nonattainment areas.

Section 117.4205, Emission Specifications

New §117.4205 incorporates the rule language from existing §117.455 concerning the emission specification for affected nitric acid production units.

Section 117.4210, Applicability of Federal New Source Performance Standards

New §117.4210 incorporates the rule language from existing §117.458, concerning the applicability of 40 CFR Part 60, Subpart G (Standards of Performance for Nitric Acid Plants).

SUBCHAPTER G, GENERAL MONITORING AND TESTING REQUIREMENTS

The commission adopts a new Chapter 117, Subchapter G that incorporates general monitoring and testing requirements from various divisions of Chapter 117 that are commonly cross-referenced from other divisions.

DIVISION 1, COMPLIANCE STACK TESTING AND REPORT REQUIREMENTS Section 117.8000, Stack Testing Requirements

New §117.8000, Stack Testing Requirements, incorporates the common stack testing requirements from existing §117.211(e) and §117.479(e), concerning testing requirements for initial demonstration of compliance. New §117.8000(a) specifies that the requirements of new §117.8000 are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8000, the relevant section of Chapter 117 references new §117.8000. New §117.8000(b) incorporates language from §117.479(e)(3) specifying that shorter test times may be used, if approved by the executive director. This provision is not included in existing §117.211(e). Incorporating the language in new §117.8000(b) will ensure that the executive director has sufficient flexibility to consider allowing shorter test times, if warranted, whether the testing is conducted at sites that are minor or major sources of NO _X .

New §117.8000(c)(1) - (3), (5), and (6) incorporate the test method requirements from existing §117.211(e)(1) - (5). Also, new §117.8000(c)(5) updates the section references to Test Method 1 and Performance Specification 2, because the EPA has reformatted the test methods and performance specifications from 40 CFR Part 60, Appendices A and B. The reference to §2.1 of Test Method 1 is changed to §11.1, and the reference to §3.2 of Performance Specification 2 is changed to §8.1.3. In addition, the commission adopts a new §117.8000(c)(4) to specify that, for units that inject ammonia or urea to control NO _X emissions, the methods required to determine ammonia are the Phenol-Nitroprusside Method, the Indophenol Method, or EPA Conditional Test Method 27. The initial demonstration of compliance requirements from existing §117.211 require ammonia testing on units that inject urea or ammonia for NO _X control; however, existing §117.211 does not specify methods for conducting the ammonia testing. The methods in new §117.8000(c)(4) are the same methods required to determine the correction factor "d" from the mass balance equation approach of monitoring for ammonia slip in existing §117.114 and §117.214.

Finally, new §117.8000(d) incorporates the language from existing §117.211(e)(6), concerning the provisions for EPA-approved alternative test methods and minor modifications to test methods.

Section 117.8010, Compliance Stack Test Reports

New §117.8010, Compliance Stack Test Reports, incorporates the compliance stack test report content requirements from existing §117.211(g) that was commonly referenced from other divisions. New §117.8010 specifies that the requirements of new §117.8010 are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8010, the relevant section of Chapter 117 references new §117.8010. The report content requirements from existing §117.211(g)(1) - (8) are incorporated in new §117.8010(1) - (8). Also, new §117.8010(8)(B) updates the section reference to Performance Specification 2, because the EPA has reformatted the test methods and performance specifications from 40 CFR Part 60, Appendices A and B. The reference to §9 of Performance Specification 2 is changed to §8.5.

DIVISION 2, EMISSION MONITORING

The commission adopts a new Chapter 117, Subchapter G, Division 2, Emission Monitoring, that incorporates general monitoring requirements from various divisions of Chapter 117 that are commonly cross-referenced from other divisions.

Section 117.8100, Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources

New §117.8100 incorporates the general requirements from existing §117.213(e) and (f) for CEMS and PEMS used at industrial, commercial, and institutional sources to comply with a monitoring requirement of Chapter 117. New §117.8100(a) specifies that the requirements for CEMS in new §117.8100(a) are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8100(a), the relevant section of Chapter 117 references new §117.8100. The requirements for CEMS in existing §117.213(e)(1) - (3), (5), and (6) are incorporated in new §117.8100(a)(1) - (6). Existing §117.213(e)(4) includes CEMS requirements specific to the Houston-Galveston-Brazoria ozone nonattainment area and is not included in new §117.8100(a).

New §117.8100(b) specifies that the requirements for PEMS in new §117.8100(b) are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8100(b), the relevant section of Chapter 117 references new §117.8100. The requirements for PEMS in existing §117.213(f)(2) - (7) are incorporated in new §117.8100(b)(1) - (6). Existing §117.213(f)(1) specifies that the PEMS must predict the pollutant emissions in the units of the applicable emission specifications of the division, and is not incorporated in new §117.8100(b) because division-specific requirements might apply.

The commission adopts a new §117.8100(c) that specifies that reports of any RATA performed in accordance with §117.8100 must comply with the new §117.8010, concerning compliance stack test report contents. New §117.8100(c) is necessary to clarify that the report for any RATA performed in accordance with §117.8100(a) or (b) must still meet the report content requirements.

Section 117.8110, Emission Monitoring System Requirements for Utility Electric Generation Sources

New §117.8110 incorporates the general requirements from existing §117.113(c) and (f) for CEMS and PEMS used at utility electric generation sources to comply with a monitoring requirement of Chapter 117. The requirements for CEMS and PEMS at utility electric generation sources in existing §117.113(c) and (f) are sufficiently different from the requirements for industrial, commercial, and institutional sources in existing §117.213 that combining the requirements for both source categories would result in significant substantive changes impacting owners and operators. Therefore, the commission has maintained the monitoring system requirements for CEMS and PEMS at a utility electric generation source separate from other source categories. New §117.8110(a) specifies that the requirements for CEMS in new §117.8110(a) are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8110(a), the relevant section of Chapter 117 references new §117.8110. The requirements for CEMS in existing §117.113(c)(1) and (2) are incorporated in new §117.8110(a)(1) and (2). Existing §117.113(c)(3) is a Houston-Galveston-Brazoria ozone nonattainment area specific requirement for CEMS and is not incorporated into §117.8110(a).

New §117.8110(b) specifies that the requirements for PEMS in new §117.8110(b) are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8110(b), the relevant section of Chapter 117 references new §117.8110. The requirements for PEMS in existing §117.113(f)(2) - (4) are incorporated in new §117.8110(b)(1) - (3). Existing §117.113(f)(1) specifies that the PEMS must predict the pollutant emissions in the units of the applicable emission specifications of the division, and is not incorporated in new §117.8110(b) because division-specific requirements might apply. In addition, the reference in existing §117.113(f)(4)(B) to existing §117.213(f) is changed to §117.8100(b), because the applicable requirements from §117.213(f) are incorporated in new §117.8100(b).

Section 117.8120, Carbon Monoxide (CO) Monitoring

New §117.8120 incorporates the CO monitoring requirements from existing §117.113(b) and §117.213(d), and the optional CO monitoring requirements from existing §117.143(b). New §117.8120 specifies that the requirements for CO monitoring in new §117.8120 are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8120, the relevant section of Chapter 117 references new §117.8120. The references to applicable subsections for CEMS or PEMS used to monitor CO in existing §§117.113(b)(1), 117.143(b)(1), and 117.213(b)(1) are changed to new §117.8100(a) or §117.8110(a) and §117.8100(b) or §117.8110(b), as applicable.

Section 117.8130, Ammonia Monitoring

New §117.8130 incorporates the ammonia monitoring requirements from existing §117.114(a)(4) and §117.214(a)(1)(D) that are commonly referenced from various divisions of Chapter 117. New §117.8130 specifies that the requirements for ammonia monitoring in new §117.8130 are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8130, the relevant section of Chapter 117 references new §117.8130. Existing §117.114(a)(4)(A) - (D) and §117.214(a)(1)(D)(i) - (iv) are incorporated in new §117.8030(1) - (4). The O ₂ correction for ammonia concentrations to 3.0% for boilers and 15% for gas turbines in the equation in existing §117.114(a)(4)(A) is identical to the O ₂ corrections for boilers and gas turbines in existing §117.214(a)(1)(D)(i); therefore, new §117.8030(1) incorporates the O ₂ correction criteria for the ammonia concentrations from §117.214(a)(1)(D)(i). The methods specified for variable "d" of the equations in §117.114(a)(4)(A) and §117.214(a)(1)(D)(i) are identical and are incorporated in new §117.8000(c)(4). Variable "d" of the equation in new §117.8130(1) specifies that the correction factor is the ratio of measured slip to calculated ammonia slip, where the measured slip is obtained from the stack sampling for ammonia during an initial demonstration of compliance required by Chapter 117 and using the methods specified in new §117.8000.

Section 117.8140, Emission Monitoring for Engines

New §117.8140 incorporates certain testing requirements for stationary internal combustion engines from existing §§117.208(d)(7), 117.213(g)(1), 117.214(b)(2), and 117.478(b)(5). New §117.8140(a), concerning periodic testing for engines, specifies that the requirements in new §117.8140(a) are applicable when required by a provision of Chapter 117. When owners or operators are required to comply with §117.8140(a), the relevant section of Chapter 117 references new §117.8140(a). New §117.8140(a)(1) - (3) incorporate the engine testing provisions for NO _X and CO from §117.213(g)(1)(A) - (C). New §117.8140(a)(1) specifies that the methods in new §117.8000 must be used. The provisions for testing on a biennial calendar basis or with 15,000 hours of operation in existing §117.213(g)(1)(B) are incorporated in new §117.8140(a)(2). The exemption from periodic testing in existing §117.213(g)(1)(C) for engines used exclusively in emergency situations is incorporated in new §117.8140(a)(3).

New §117.8140(b), concerning checks for proper operation of engines, specifies that the requirements in new §117.8140(a) are applicable when required by a provision of Chapter 117. New §117.8140(b) incorporates the engine-testing provisions for proper operation from §§117.208(d)(7), 117.214(b)(2)(A), and 117.478(b)(5). The exemption from quarterly testing for engines with a monthly run time of 10 hours or less in existing §117.214(b)(2)(A) and §117.478(b)(5) is only applicable in the Houston-Galveston-Brazoria ozone nonattainment area. This exemption is not in §117.208(d)(7). The commission is incorporating the exemption for engines with a monthly run time of 10 hours or less in new §117.8140(b), expanding the applicability of the exemption to affected engines in the Beaumont-Port Arthur and Dallas-Fort Worth ozone nonattainment areas. The provision in existing §117.214(b)(2)(A) and §117.478(b)(5) that specifies the exemption does not diminish the requirement to test emissions after installation of controls, major repair work, or any time the owner or operator believes emissions may have changed is also incorporated in new §117.8140(b).

SUBCHAPTER H, ADMINISTRATIVE PROVISIONS

The commission adopts a new Chapter 117, Subchapter H, entitled Administrative Provisions, that incorporates the administrative provisions from existing Chapter 117, Subchapter E, concerning compliance schedules and certain compliance flexibility provisions, and includes new compliance schedules and changes to reflect new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration.

DIVISION 1, COMPLIANCE SCHEDULES

The commission adopts a new Chapter 117, Subchapter H, Division 1, entitled Compliance Schedules, that incorporates the compliance schedules from existing Chapter 117, Subchapter E, §§117.510, 117.512, 117.520, 117.524, 117.530, and 117.534, and includes new compliance schedules and changes to reflect new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration.

Section 117.9000, Compliance Schedule for Beaumont-Port Arthur Ozone Nonattainment Area Major Sources

New §117.9000 incorporates the compliance schedule rule language from existing §117.520(a), applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.9000(1) incorporates the rule language from existing §117.520(a)(1), concerning the compliance schedule for RACT requirements. New §117.9000(2) incorporates the rule language from existing §117.520(a)(2), concerning the compliance schedule for lean-burn engine requirements, and new §117.9000(3) incorporates the rule language from existing §117.520(a)(3), concerning the compliance schedule for requirements associated with the emission specifications for attainment demonstration. In addition, as previously indicated in this preamble, the commission is incorporating general requirements from existing §117.213 for CEMS and PEMS at industrial, commercial, and institutional sources in a new §117.8100. Therefore, for new §117.9000(1)(B)(i) and (3)(B)(iii), the commission changes the reference for the CEMS or PEMS performance evaluation and quality assurance procedures from existing §117.213(e)(1)(A) and (B) and (f)(3) - (5)(A) to the new §117.8100(a)(1)(A) and (B) and (b)(2) - (4)(A). Also, existing §117.520(a)(3)(C)(ii) incorrectly references to semiannual reports required by existing §117.213(c)(1)(C). Existing §117.213(c)(1)(C) does not include a requirement for semiannual reports. Therefore, the commission excludes this cross-reference from the new §117.9000(3)(C)(ii).

Section 117.9010, Compliance Schedule for Dallas-Fort Worth Ozone Nonattainment Area Major Sources

New §117.9010 incorporates the compliance schedule rule language from existing §117.520(b), applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.9010(1) incorporates the rule language from existing §117.520(b)(1)(A). New §117.9010(2) incorporates the rule language from existing §117.520(b)(1)(B). As previously indicated in this preamble, the commission is incorporating general requirements from existing §117.213 for CEMS and PEMS at industrial, commercial, and institutional sources in a new §117.8100. Therefore, for new §117.9010, the commission changes the reference for the CEMS or PEMS performance evaluation and quality assurance procedures from existing §117.213(e)(1)(A) and (B) and (f)(3) - (5)(A) to the new §117.8100(a)(1)(A) and (B) and (b)(2) - (4)(A).

In addition, the compliance schedule in existing §117.520(b)(2), for engines subject to existing §117.206(b)(3), is incorporated in new §117.9030, concerning the compliance schedule for the Dallas-Fort Worth eight-hour ozone nonattainment area. The applicability for existing §117.520(b)(2) is the nine-county area of the Dallas-Fort Worth eight-hour ozone nonattainment area and new §117.9030 is the most appropriate location to incorporate these requirements.

Section 117.9020, Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Major Sources

New §117.9020 incorporates the compliance schedule rule language from existing §117.520(c), applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.9020(1) incorporates the rule language from existing §117.520(c)(1), concerning the compliance schedule for RACT requirements. New §117.9020(2) incorporates the rule language from existing §117.520(c)(2), concerning the compliance schedule for requirements associated with the emission specifications for attainment demonstration. In addition, as previously indicated in this preamble, the commission is incorporating general requirements from existing §117.213 for CEMS and PEMS at industrial, commercial, and institutional sources in a new §117.8100. Therefore, for new §117.9020, the commission changes the reference for the CEMS or PEMS performance evaluation and quality assurance procedures from existing §117.213(e)(1)(A) and (B) and (f)(3) - (5)(A) to the new §117.8100(a)(1)(A) and (B) and (b)(2) - (4)(A).

Finally, for new §117.9020(2)(B)(ii), the commission revises the compliance schedule language in existing §117.520(c)(2)(B)(ii) regarding submitting the certification of activity level for electric generating facilities subject to the system cap in existing §117.210. The current language in existing §117.520(c)(2)(B)(ii) might be incorrectly interpreted that an owner or operator is required to use the first two consecutive third quarters of actual activity level data out of the first five years of operation. The commission's intent in existing §117.210 and §117.520(c)(2)(B)(ii) is that the owner or operator may select any two consecutive third quarters of actual level of activity data out of the first five years of operation, and that the selection must be made no later than 60 days after the end of the first five years of operation. Therefore, the language in new §117.9020(2)(B)(ii) is revised to specify this requirement more accurately.

Section 117.9030, Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources

New §117.9030, Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources, specifies the compliance schedules for units subject to the emissions specifications of §117.410 and §117.423.

New §117.9030(a) specifies the compliance schedule for any stationary, reciprocating, internal combustion engines subject to the emission specifications of §117.410(a), and incorporates the existing compliance schedule rule language from existing §117.520(b)(2). New §117.9030(a)(1) incorporates the rule language from existing §117.520(b)(2)(A). New §117.9030(a)(2) and (a)(2)(A) - (D) incorporate the rule language from existing §117.520(b)(2)(B) and (B)(i) - (iv).

In addition, for new §117.9030(a)(1)(C), the commission is revising the requirement in existing §117.520(b)(2)(B)(iii) to submit final control plans required by existing §117.215. As previously indicated in this preamble, the commission is incorporating the requirements for engines subject to existing §117.206(b)(3) and §117.520(b)(2) in the new division for the Dallas-Fort Worth eight-hour ozone nonattainment area. Existing §117.520(b)(2)(B)(iii) incorrectly references the final control plan procedures for RACT. The correct cross-reference for final control plans for engines subject to existing §117.206(b)(3) should be existing §117.216, Final Control Plan Procedures for Attainment Demonstration Emission Specifications. Therefore, the applicable final control plan procedures for attainment demonstration emission specifications for the engines under new Subchapter B, Division 3 are in new §117.454. Because this change could result in a change in the information required, the commission is changing the compliance date in new §117.9030(a)(1)(C) for submitting the final control plans to January 1, 2008. The commission is not changing any other existing compliance schedule requirements from existing §117.520(b)(2).

New §117.9030(b) specifies the compliance schedule requirements for units subject to the emissions specifications of §117.410(b). Based on comments received, the commission has revised the compliance schedule in §117.9030(b) to provide additional time for certain sources to comply with the requirements of the rule. New §117.9030(b)(1) establishes the compliance schedule for existing sources subject to the rule. Subparagraph (A) requires the owner or operator of any stationary source of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area that is a major source of NO _X and is subject to §117.410(b) to submit the initial control plan required by §117.450 of this title no later than June 1, 2008. Subparagraph (B) requires owners or operators of units subject to the emission specifications of §117.410(b) to comply with all other requirements of Subchapter B, Division 4 as soon as practicable, but no later than March 1, 2009, or March 1, 2010, depending on the source category of the unit. Section 117.9030(b)(1)(B)(i) establishes a compliance date of March 1, 2009, for units subject to §117.410(b)(1), (2), (4), (5), (6), (7)(A), (8), (10), and (14). Section 117.9030(b)(1)(B)(ii) establishes a compliance date of March 1, 2010, for units subject to §117.410(b)(3), (7)(B), (9), (11), (12), and (13). The selection of the source categories for the two compliance schedules was based on the number of sources in each category, the type of controls likely to be implemented to meet the adopted emission specifications, the time required to implement those controls, and the amount of reductions expected from each source category. Some source categories may require more time to comply with the rule due to the procurement and installation times of the control technologies necessary or because the large number of units in a particular source category requiring retrofit controls might limit vendors' ability to meet demand. The adopted compliance schedule focuses the maximum reductions possible by March 1, 2009. New subparagraph (C) requires owners or operators of diesel and dual-fuel engines to comply with the restriction on hours of operation for maintenance and testing in §117.410(g), and the associated recordkeeping in §117.445(f)(9), as soon as practicable, but no later than March 1, 2009. New subparagraph (D) requires owners or operators of any stationary gas turbine or stationary internal combustion engine claimed exempt under §117.403(a)(7)(D), (8), or (9) to comply with the run time meter requirements of §117.440(i), and associated recordkeeping in §117.445(f)(4), as soon as practicable, but no later than March 1, 2009.

New §117.9030(b)(2) specifies the owner or operator of any stationary source of NO _X that becomes subject to the requirements of Subchapter B, Division 4 of this chapter on or after the applicable compliance date specified in §117.9030(b)(1), shall comply with the requirements of Subchapter B, Division 4 as soon as practicable, but no later than 60 days after becoming subject. For example, new boilers placed into service after March 1, 2009, will be required to comply within 60 days after startup of the unit. Existing units previously exempt from the rule, but no longer qualifying for that exemption after the applicable compliance date, will be required to comply with the rule no later that 60 days after the date that the exemption status was lost.

Section 117.9100, Compliance Schedule for Beaumont-Port Arthur Ozone Nonattainment Area Utility Electric Generation Sources

New §117.9100 incorporates the compliance schedule rule language from existing §117.510(a), applicable to the Beaumont-Port Arthur ozone nonattainment area. New §117.9100(1) incorporates the rule language from existing §117.510(a)(1), concerning the compliance schedule for RACT requirements. New §117.9100(2) incorporates the rule language from existing §117.510(a)(2), concerning the compliance schedule for requirements associated with the emission specifications for attainment demonstration.

Section 117.9110, Compliance Schedule for Dallas-Fort Worth Ozone Nonattainment Area Utility Electric Generation Sources

New §117.9110 incorporates the compliance schedule rule language from existing §117.510(b), applicable to the Dallas-Fort Worth ozone nonattainment area. New §117.9110(1) incorporates the rule language from existing §117.510(b)(1), concerning the compliance schedule for RACT requirements. New §117.9110(2) incorporates the rule language from existing §117.510(b)(2), concerning the compliance schedule for requirements associated with the emission specifications for attainment demonstration.

Section 117.9120, Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Utility Electric Generation Sources

New §117.9120 incorporates the compliance schedule rule language from existing §117.510(c), applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.9120(1) incorporates the rule language from existing §117.510(c)(1), concerning the compliance schedule for RACT requirements. New §117.9120(2) incorporates the rule language from existing §117.510(c)(2), concerning the compliance schedule for requirements associated with the emission specifications for attainment demonstration.

Section 117.9130, Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources

New §117.9130, Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources, specifies the compliance schedule for owners or operators subject to the new Subchapter C, Division 4. New §117.9130(a) specifies the compliance schedule for existing units subject to the rule. New §117.9130(a)(1) requires the owner or operator to submit the initial control plan required by new §117.1350 by no later than June 1, 2008. New §117.9130(a)(2) specifies that the owner or operator must comply with all other requirements of new Subchapter C, Division 4 as soon as practicable, but no later that March 1, 2009. Finally, the commission adopts a new §117.9130(b) that specifies, for units in the Dallas-Fort Worth eight-hour ozone nonattainment area that become subject to new Subchapter C, Division 4 on or after March 1, 2009, the owner or operator must comply as soon as practicable, but no later than 60 days after becoming subject.

Section 117.9200, Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources

New §117.9200 incorporates the compliance schedule rule language from existing §117.534, concerning the compliance schedule for boilers, process heaters, stationary engines and stationary gas turbines at minor sources applicable to the Houston-Galveston-Brazoria ozone nonattainment area. New §117.9200(1) incorporates the rule language from existing §117.534(1), concerning the compliance schedule for sources subject to the MECT Program. New §117.9200(2) incorporates the rule language from existing §117.534(2), concerning the compliance schedule for sources not subject to the MECT Program. In addition, as previously indicated in this preamble, the commission is incorporating general requirements from existing §117.213 for CEMS and PEMS at industrial, commercial, and institutional sources in a new §117.8100. Therefore, for new §117.9200, the commission changes the reference for the CEMS or PEMS performance evaluation and quality assurance procedures from existing §117.213(e)(1)(A) and (B) and (f)(3) - (5)(A) to the new §117.8100(a)(1)(A) and (B) and (b)(2) - (4)(A).

Section 117.9210, Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources

New §117.9210 specifies the compliance schedule for sources subject to the new Subchapter D, Division 2, Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources. Based on comments received, the commission has revised the compliance schedule to provide additional time for certain source categories to comply with the rule. Also, as discussed elsewhere in this preamble, boiler, process heaters, and stationary gas turbines at minor sources are not subject to the adopted rule. Provisions in the adopted §117.9210 related to boilers, process heaters, and stationary gas turbines have been modified or removed to reflect this change, and the provisions renumbered as necessary.

The adopted §117.9210(a) specifies the owner or operator of each stationary source of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area that is not a major source of NO _X shall comply with the requirements of Subchapter D, Division 2 as soon as practicable, but no later than the dates specified in paragraphs (1) through (3). Rich-burn gas-fired, diesel, and dual-fuel stationary engines are required to comply with the requirements of the division by no later than March 1, 2009. Lean-burn stationary gas-fired engines must meet the requirements of the rule by no later than March 1, 2010.

New §117.9210(b) specifies the owner or operator of any stationary source of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area that becomes subject to the requirements of Subchapter D, Division 2 on or after the applicable compliance date in subsection (a), must comply with the requirements of Subchapter D, Division 2 as soon as practicable, but no later than 60 days after becoming subject.

Section 117.9300, Compliance Schedule for Utility Electric Generation in East and Central Texas

New §117.9300 incorporates the compliance schedule rule language from existing §117.512, concerning the compliance schedule for utility electric generation in East and Central Texas. New §117.9300(1) incorporates the rule language from existing §117.512(1), and new §117.9300(2) incorporates the rule language from existing §117.512(2).

Section §117.9320, Compliance Schedule for Cement Kilns

New §117.9320 incorporates the rule language regarding the compliance schedule for cement kilns from existing §117.524. New §117.9320(a) and (b) incorporate the rule language from existing §117.524(a) and (b), respectively. In addition, for new §117.9320(a), the commission adds the language "Except as specified in subsection (c) of this section . . .." This change is necessary to clarify that the compliance schedule in subsection (a) is not applicable to the new requirements in §§117.3123, 117.3142, and 117.3145.

A new §117.9320(c) specifies that the owner or operator of each portland cement kiln in Ellis County must be in compliance with the requirements of §117.3123 and §117.3142, and the applicable requirements of §117.3145 as soon as practicable, but no later than March 1, 2009. In addition, new §117.9320(c)(1) specifies that the provisions in new §117.9320(b), regarding extension of compliance schedules, do not apply to subsection (c) or the requirements of §117.3123, §117.3142, or the applicable requirements of §117.3145. New §117.9320(c) is necessary to ensure that the required reductions under the source cap of §117.3123 occur by the date necessary to demonstrate attainment. However, based on comments received, the commission has revised §117.9320(c) to include a provision in new paragraph (2) that would extend the compliance date to no later than March 1, 2010, if a contested case hearing is granted as a direct result of a permit application necessary to comply with §117.3123. New §117.9320(c)(2) also specifies that the compliance date remains March 1, 2009, if a contested case hearing is granted under the conditions specified in subparagraphs (A) or (B). The condition in new subparagraph (A) is if the contested case hearing is granted as a result of a permit application that includes modifications necessary to comply with §117.3123, but the contested case hearing is the result of modifications included in the permit that are unrelated to compliance with §117.3123. The condition in new subparagraph (B) is if the contested case hearing is granted at the request of the owner or operator of the affected portland cement kiln or a third party affiliated with the owner or operators. The provisions of subparagraph (A) or (B) are necessary to ensure that the compliance date is only extended to March 1, 2010, if a contested case hearing is granted due to circumstances beyond the control of the affected site.

Section 117.9340, Compliance Schedule for East Texas Combustion

New §117.9340 specifies the compliance schedule for owner or operators to comply with the requirements of Chapter 117, Subchapter E, Division 4, East Texas Combustion. Based on comments received, the commission has determined that additional time is needed for affected owners or operators to comply with the requirements of the East Texas Combustion rule. Therefore, the commission has revised the compliance date from March 1, 2009, to March 1, 2010. The adopted §117.9340(a) specifies that the owner or operator of each stationary, reciprocating internal combustion engine subject to Subchapter E, Division 4 must comply with the requirements of Subchapter E, Division 4 as soon as practicable, but no later than March 1, 2010. Section 117.9340(b) specifies that the owner or operator of a stationary, reciprocating internal combustion engine that becomes subject to the requirements of Subchapter E, Division 4 on or after March 1, 2010, must comply with the requirements of that division as soon as practicable, but no later than 60 days after becoming subject.

Section 117.9500, Compliance Schedule for Nitric Acid and Adipic Acid Manufacturing Sources

New §117.9500 incorporates the compliance schedule rule language from existing §117.530, concerning the compliance schedule for nitric acid and adipic acid manufacturing sources. New §117.9500(1) - (3) incorporate the rule language from existing §117.530(1) - (3), respectively.

DIVISION 2, COMPLIANCE FLEXIBILITY

The commission adopts a new Chapter 117, Subchapter H, Division 2, entitled Compliance Flexibility, that incorporates the rule language from existing Chapter 117, §117.570 and §117.571, and includes changes to reflect new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration.

Section 117.9800, Use of Emission Credits for Compliance

New §117.9800 incorporates the rule language from existing §117.570, concerning the use of emission credits for compliance. New §117.9800(a) - (d) incorporate the rule language from existing §117.570(a) - (d), respectively. In addition, new §117.9800(a) is restructured for clarity. The list of applicable sections in existing §117.570(a) is listed as separate paragraphs in new §117.9800(a)(1) - (8). Applicable section number references for the new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration are included in new §117.9800(a)(5), (7), and (8). Also, for new §117.9800(d), the list of applicable sections in existing §117.570(d), concerning final control plans, is also revised to include new §117.456 and §117.1356.

Section 117.9810, Use of Emission Reductions Generated from the Texas Emissions Reduction Plan (TERP)

New §117.9810 incorporates the rule language from existing §117.571, concerning the use of emission reductions generated from the Texas Emissions Reduction Plan. New §117.9810(a) and (b) incorporate and restructure for clarity the rule language from existing §117.571(a). New §117.9810(a) revises the applicability of §117.571 to include the Dallas-Fort Worth eight-hour ozone nonattainment area. The list of applicable sections in existing §117.571(a) is listed as separate paragraphs in new §117.9810(a)(1) - (6). Applicable section number references for the new rules for the Dallas-Fort Worth eight-hour ozone attainment demonstration are included in new §117.9810(a)(6). The rule language concerning provisions for obtaining emission reductions generated from TERP in existing §117.571(a)(1) - (6) is incorporated in new §117.9810(b) and (b)(1) - (6). Also, for new §117.9810(b)(6), the commission removes the language "of this division" regarding applicable emission reduction requirements, because this reference has no meaning under the new format for the division that incorporates this rule language. The new §117.9810(b)(6) specifies "applicable emission reduction requirements of this chapter." Finally, new §117.9810(c) incorporates the rule language from existing §117.571(b).

FINAL REGULATORY IMPACT ANALYSIS DETERMINATION

The commission reviewed the rulemaking for a new 30 TAC Chapter 117 in light of the regulatory impact analysis requirements of Texas Government Code, §2001.0225, and determined that, except for the repeal and reformatting of Chapter 117 and as specifically discussed later regarding rules in Subchapter E, Division 3, the rulemaking meets the definition of a major environmental rule as defined in that statute. A major environmental rule means a rule, the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure, and that may adversely affect in a material way the economy, a sector of the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state.

The rulemaking does not, however, meet any of the four applicability criteria for requiring a regulatory impact analysis for a major environmental rule, which are listed in Texas Government Code, §2001.0225(a). Texas Government Code, §2001.0225, applies only to a major environmental rule, the result of which is to: 1) exceed a standard set by federal law, unless the rule is specifically required by state law; 2) exceed an express requirement of state law, unless the rule is specifically required by federal law; 3) exceed a requirement of a delegation agreement or contract between the state and an agency or representative of the federal government to implement a state and federal program; or 4) adopt a rule solely under the general powers of the agency instead of under a specific state law.

The repeal and reformatting of Chapter 117 is necessary to accommodate new rules for the eight-hour ozone attainment demonstration and to provide for future potential rulemaking. The reformatting includes minor technical changes and corrections to existing language for rule language associated with the one-hour ozone NAAQS. The repeal and reformatting of Chapter 117 will not negatively impact the status of the state's attainment with the ozone NAAQS because all existing rules remain in effect until the effective date of the reformatted chapter. All requirements in the existing rules for the one-hour ozone NAAQS, applicable to a particular region or area that the rules apply to, have been incorporated into the new formatted rules. This is necessary so there will be no backsliding or temporary lapse in the enforcement or effectiveness of the current requirements in 30 TAC Chapter 117, which are necessary for attainment and maintenance of the NAAQS in Texas.

Specifically, the remainder of this rulemaking can be summarized as indicated in the following categories.

SUBCHAPTER B: COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

These rules adopt new emission control requirements for major ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. Specifically, the new Subchapter B, Division 4 requires owners or operators of major ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area to reduce NO_X emissions from a wide variety of stationary sources. The rules also include monitoring, testing, recordkeeping, reporting, and other requirements associated with the emission specifications necessary to ensure compliance with the emission specifications and that the necessary NO _X emission reductions will be achieved.

Further, the emission specifications for attainment demonstration in new §117.410 specify stricter emission limits for NO _X for all unit and industry types in the Dallas-Fort Worth eight-hour nonattainment area than are specified in the EPA's ACT. The FCAA RACT requirement is fulfilled by the emission specifications for attainment demonstration in §117.410 for the Dallas-Fort Worth eight-hour ozone nonattainment area.

The emission reductions from these adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area and help the area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter B, Division 4 are one step toward meeting the state's obligations under the FCAA.

SUBCHAPTER C: COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

These rules adopt new requirements for utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. Specifically, the new Subchapter C, Division 4 applies to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts used in an electric power generating system owned or operated by a municipality or a PUC-regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or an electric cooperative, municipality, river authority, or public utility located within the Dallas-Fort Worth eight-hour ozone nonattainment area. The rules establish a unit-by-unit basis for compliance with the existing emission specifications for units subject to the rule; however, based on comments received discussed elsewhere in this preamble, the rule is revised to also provide an alternative system-wide heat-input weighted average approach. Further, as discussed elsewhere in this preamble, the rules satisfy RACT requirements for the five new counties in the nine-county Dallas-Fort Worth eight-hour ozone nonattainment area.

The emission reductions from these adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area and help the area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter C, Division 4 are one step toward meeting the state's obligations under the FCAA.

SUBCHAPTER D: COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 2: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

These rules adopt requirements for minor stationary sources of NO_X in the Dallas-Fort Worth eight-hour ozone nonattainment area to meet new emission specifications and other reductions of NO _X emissions from affected stationary internal combustion engines. Specifically, this rulemaking regulates units at sites including small businesses and industries, hospitals, hotels, public and private office and administrative buildings, and school districts that were previously unregulated.

The emission reductions from these adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area and help the area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter D, Division 2 are one step toward meeting the state's obligations under the FCAA.

SUBCHAPTER E: MULTI-REGION COMBUSTION CONTROL

DIVISION 2: CEMENT KILNS

These rules implement a control strategy for cement kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area. Specifically, the commission is adopting a source-cap approach to establish a maximum NO _X emission cap for each account. As discussed elsewhere in this preamble, these rules are based on the commission's evaluation of the "Assessment of NO _X Emissions Reduction Strategies for Cement Kilns--Ellis County: Final Report," together with modeling sensitivity studies, and all other available information, including information submitted as public comment on the proposed rules. A source cap allows an owner or operator to choose the most applicable and cost-effective control technology available to a particular kiln while still achieving the overall reductions modeled for the Dallas-Fort Worth eight-hour attainment demonstration. Owners or operators may use any of the control technologies identified in the final report of the control technology study or other appropriate technologies to achieve reductions for compliance with the source cap. Before an increase in NO_X emissions from a change in operation from one unit or the installation of a new kiln could occur, a corresponding and equivalent decrease in NO _X emission will be required from another existing unit.

The emission reductions from these adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area, and help the area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter E, Division 2 are one step toward meeting the state's obligations under the FCAA.

DIVISION 3: WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

The commission reviewed the rulemaking action in Subchapter E, Division 3 of Chapter 117 in light of the regulatory analysis requirements of Texas Government Code, §2001.0225, and determined that the rulemaking action does not meet the definition of a major environmental rule as defined in that statute. A major environmental rule is a rule the specific intent of which is to protect the environment or reduce risks to human health from environmental exposure and that may adversely affect in a material way the economy, productivity, competition, jobs, the environment, or the public health and safety of the state or a sector of the state.

The primary purpose of this rulemaking action in this division is to repeal the current 10 ng/J NO _X emission standard for certain gas-fired residential water heaters, as set forth in §117.465(b)(2). This emission standard has never become effective. The effective date has been extended through a prior adopted rulemaking, and it has subsequently been determined that compliance with the 10 ng/J standard for Type 0 units is not currently achievable. The basis for this determination is discussed earlier in this preamble in greater detail. All water heaters must still meet the 40 ng/J emission standard in the existing rules. The original rules, adopted on April 19, 2000, did not constitute a major environmental rulemaking action, and the amendments to the existing rules are minor in nature. Therefore, the rulemaking does not constitute a major environmental rule, and thus not subject to a formal regulatory analysis.

The emission reductions from the remaining emission standards in the adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area, and help bring the area into compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter E, Division 3 are one step toward meeting the state's obligations under the FCAA.

DIVISION 4: EAST TEXAS COMBUSTION

The primary purpose of the new rules is to require affected gas-fired stationary, reciprocating internal combustion engines in certain counties in the Northeast Texas area to meet new NO _X emission specifications and other requirements in order to reduce NO _X emissions and ozone air pollution transport into the Dallas-Fort Worth eight-hour ozone nonattainment area. The specific counties included in the applicability for this rulemaking include the following counties: Anderson, Brazos, Burleson, Camp, Cass, Cherokee, Franklin, Freestone, Gregg, Grimes, Harrison, Henderson, Hill, Hopkins, Hunt, Lee, Leon, Limestone, Madison, Marion, Morris, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, Shelby, Smith, Titus, Upshur, Van Zandt, and Wood Counties.

The emission reductions from these adopted rules will result in reductions in ozone formation in the Dallas-Fort Worth eight-hour ozone nonattainment area and help the area make progress toward compliance with the eight-hour ozone NAAQS. These emission reductions are one component of the Dallas-Fort Worth attainment demonstration SIP revision the state is required to submit to EPA to assure attainment and maintenance of the eight-hour ozone NAAQS, and the new rules in Subchapter E, Division 4 are one step toward meeting the state's obligations under the FCAA.

ANALYSIS

The new Chapter 117 rulemaking implements express requirements of the FCAA. Under 42 USC, §7410, each state is required to adopt and implement a state implementation plan containing adequate provisions to implement, attain, maintain, and enforce the NAAQS within the state. While 42 USC, §7410 generally does not require specific programs, methods, or reductions in order to meet the standard, state SIPs must include "enforceable emission limitations and other control measures, means or techniques (including economic incentives such as fees, marketable permits, and auctions of emissions rights), as well as schedules and timetables for compliance as may be necessary or appropriate to meet the applicable requirements of this chapter," (meaning Chapter 85, Air Pollution Prevention and Control, otherwise known as the FCAA). The provisions of the FCAA recognize that states are in the best position to determine what programs and controls are necessary or appropriate in order to meet the NAAQS. This flexibility allows states, affected industry, and the public, to collaborate on the best methods for attaining the NAAQS for the specific regions in the state. Even though the FCAA allows states to develop their own programs, this flexibility does not relieve a state from developing a program that meets the requirements of 42 USC, §7410. States are not free to ignore the requirements of 42 USC, §7410 and must develop programs and control measures to assure that their state implementation plans provide for implementation, attainment, maintenance, and enforcement of the NAAQS within the state.

The requirement to provide a fiscal analysis of regulations in the Texas Government Code was amended by Senate Bill (SB) 633 during the 75th legislative session. The intent of SB 633 was to require agencies to conduct a regulatory impact analysis of extraordinary rules. These are identified in the statutory language as major environmental rules that will have a material adverse impact and will exceed a requirement of state law, federal law, or a delegated federal program, or are adopted solely under the general powers of the agency. With the understanding that this requirement would seldom apply, the commission provided a cost estimate for SB 633 that concluded "based on an assessment of rules adopted by the agency in the past, it is not anticipated that the bill will have significant fiscal implications for the agency due to its limited application." The commission also noted that the number of rules that would require assessment under the provisions of the bill was not large. This conclusion was based, in part, on the criteria set forth in the bill that exempted rules from the full analysis unless the rule was a major environmental rule that exceeds a federal law.

As discussed earlier in this preamble, the FCAA does not always require specific programs, methods, or reductions in order to meet the NAAQS; thus, states must develop programs for each nonattainment area to help ensure that those areas will meet the attainment deadlines. Because of the ongoing need to address nonattainment issues and to meet the requirements of 42 USC, §7410, the commission routinely proposes and adopts SIP rules. The legislature is presumed to understand this federal scheme. If each rule proposed for inclusion in the SIP was considered to be a major environmental rule that exceeds federal law, then every SIP rule would require the full regulatory impact analysis (RIA) contemplated by SB 633. This conclusion is inconsistent with the conclusions reached by the commission in its cost estimate and by the Legislative Budget Board (LBB) in its fiscal notes. Since the legislature is presumed to understand the fiscal impacts of the bills it passes, and that presumption is based on information provided by state agencies and the LBB, the commission believes that the intent of SB 633 was only to require the full RIA for rules that are extraordinary in nature. While the SIP rules will have a broad impact, that impact is no greater than is necessary or appropriate to meet the requirements of the FCAA. For these reasons, rules adopted for inclusion in the SIP fall under the exception in Texas Government Code, §2001.0225(a), because they are required by federal law.

The commission has consistently applied this construction to its rules since this statute was enacted in 1997. Since that time, the legislature has revised the Texas Government Code, but left this provision substantially unamended. It is presumed that "when an agency interpretation is in effect at the time the legislature amends the laws without making substantial change in the statute, the legislature is deemed to have accepted the agency's interpretation." (Central Power & Light Co. v. Sharp , 919 S.W.2d 485, 489 (Tex. App. Austin 1995), writ denied with per curiam opinion respecting another issue , 960 S.W.2d 617 (Tex. 1997); Bullock v. Marathon Oil Co. , 798 S.W.2d 353, 357 (Tex. App. Austin 1990, no writ ). Cf. Humble Oil & Refining Co. v. Calvert , 414 S.W.2d 172 (Tex. 1967); Dudney v. State Farm Mut. Auto Ins. Co. , 9 S.W.3d 884, 893 (Tex. App. Austin 2000); Southwestern Life Ins. Co. v. Montemayor , 24 S.W.3d 581 (Tex. App. Austin 2000, pet. denied ); and Coastal Indust. Water Auth. v. Trinity Portland Cement Div. , 563 S.W.2d 916 (Tex. 1978).)

The commission's interpretation of the RIA requirements is also supported by a change made to the Texas Administrative Procedure Act (APA) by the legislature in 1999. In an attempt to limit the number of rule challenges based upon APA requirements, the legislature clarified that state agencies are required to meet these sections of the APA against the standard of "substantial compliance." (Texas Government Code, §2001.035.) The legislature specifically identified Texas Government Code, §2001.0225 as falling under this standard. The commission has substantially complied with the requirements of §2001.0225.

The specific intent of the adopted rules is to protect the environment and to reduce risks to human health, particularly in the state's ozone nonattainment areas, by adoption of the new rules in Chapter 117. As discussed elsewhere in this preamble, the commission conducted an extensive analysis, including photochemical modeling, trend data, transport analysis, and supplementary data regarding the nature of eight-hour ozone pollution in the Dallas-Fort Worth eight-hour ozone nonattainment area. Additional information documenting this analysis is available in the adopted Dallas-Fort Worth eight-hour ozone nonattainment area attainment demonstration SIP, which can be found on the commission's Web site at: http://www.tceq.state.tx.us/nav/eq/sip.html. As documented in this preamble and the revised DFW SIP, the emissions reductions resulting from these rules are necessary to make progress toward the attainment, and maintenance of, the eight-hour ozone NAAQS throughout the state. The rules do not exceed a standard set by federal law, since they are designed to meet, not exceed the relevant standard set by federal law - the NAAQS. Rules adopted to meet these federal standards, do not trigger the statutory language in Texas Government Code, §2001.0225(a) requiring a regulatory impact analysis. The Third District Court of Appeals upheld this interpretation in Brazoria County v. Texas Comm'n on Envtl. Quality , 128 S.W. 3d 728 (Tex. App.-Austin 2004, no writ).

In addition, the rules do not exceed an express requirement of state law, which is to protect air quality within the state, and to design and submit a plan to achieve attainment and maintenance of the federally mandated NAAQS. No contract or delegation agreement covers the topic that is the subject of this rulemaking. Finally, this rulemaking was not developed solely under the general powers of the agency, but is authorized by specific sections of Texas Health and Safety Code, Chapter 382 (also known as the Texas Clean Air Act) which are cited in the STATUTORY AUTHORITY section of this preamble, including Texas Health and Safety Code, §§382.011, 382.012, 382.014, 382.016, 382.017, and 382.021. Therefore, this rulemaking is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225(b), because, although the rule meets the definition of a major environmental rule, it does not meet any of the four applicability criteria for a major environmental rule.

Based upon the foregoing, this rulemaking action is not subject to the regulatory analysis provisions of Texas Government Code, §2001.0225.

The commission invited public comment regarding the RIA determination during the public comment period. Comments were received about the RIA determination and are addressed in the RESPONSE TO COMMENTS section of this preamble.

TAKINGS IMPACT ASSESSMENT

Under Texas Government Code, §2007.002(5), taking means 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 §17 or §19, Article I, Texas Constitution; or a governmental action that affects an 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% in the market value of the affected private real property, determined by comparing the market value of the property as if the governmental action is not in effect and the market value of the property determined as if the governmental action is in effect.

The commission completed a takings impact assessment for the rulemaking action under Texas Government Code, §2007.043. The primary purpose of this rulemaking action is summarized in the following paragraphs.

CHAPTER 117 REFORMAT

The repeal and reformatting of Chapter 117 is necessary to accommodate new rules for the eight-hour ozone attainment demonstration and to provide for future potential rulemaking. The reformatted Chapter 117 also provides for easier understanding of what rules are applicable in different geographical areas of the state. The reformatting includes minor technical changes and corrections to existing language for rule language associated with the one-hour ozone NAAQS. The repeal and reformatting of Chapter 117 will not negatively impact the status of the state's attainment with the ozone NAAQS because all existing rules remain in effect until the effective date of the reformatted chapter. All requirements in the existing rules for the one-hour ozone NAAQS, applicable to a particular region or area that the rule applies to, have been incorporated into the new formatted rules. This is necessary so there will be no backsliding or lapse in the enforcement or effectiveness of the current requirements in 30 TAC Chapter 117.

SUBCHAPTER B: COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

These rules adopt new emission control requirements for major ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area. These rules are a part of the area's attainment demonstration and the emission reductions associated with this rulemaking will help the area make progress toward compliance with the eight-hour ozone NAAQS.

Specifically, the new sections of Subchapter B, Division 4 will require owners or operators of major ICI sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area to reduce NO_X emissions from a wide variety of stationary sources. The rules also include monitoring, testing, recordkeeping, reporting, and other requirements associated with the emission specifications necessary to ensure compliance with the emission specifications and that the necessary NO _X emission reductions will be achieved.

Further, the emission specifications for attainment demonstration in new §117.410 specify stricter emission limits for NO _X for all unit and industry types in the Dallas-Fort Worth eight-hour nonattainment area than specified in the EPA's ACT. The FCAA RACT requirement is fulfilled by the emission specifications for attainment demonstration in §117.410 for the Dallas-Fort Worth eight-hour ozone nonattainment area.

SUBCHAPTER C: COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

These rules adopt new requirements for utility electric generation sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. These rules are a part of the area's attainment demonstration and the emission reductions associated with this rulemaking will help the area make progress toward compliance with the eight-hour ozone NAAQS.

Specifically, the new Subchapter C, Division 4 applies to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts used in an electric power generating system owned or operated by a municipality or a PUC-regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or an electric cooperative, municipality, river authority, or public utility located within the Dallas-Fort Worth eight-hour ozone nonattainment area. The rules establish a unit-by-unit basis for compliance with the existing emission specifications for units subject to the rule; however, based on comments received discussed elsewhere in this preamble, the rule is revised to also provide an alternative system-wide heat-input weighted average approach. Further, as discussed elsewhere in this preamble, the rules satisfy RACT requirements for the five new counties in the nine-county Dallas-Fort Worth eight-hour ozone nonattainment area.

SUBCHAPTER D: COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 2: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

These rules adopt requirements for minor stationary sources of NO_X in the Dallas-Fort Worth eight-hour ozone nonattainment area to meet new emission specifications and other reductions of NO _X emissions from affected stationary internal combustion engines. Based on comments received and further analysis discussed elsewhere in this preamble, the adopted rules do not apply to boilers, stationary gas turbines, and process heaters. This rulemaking regulates units at sites including small businesses and industries, hospitals, hotels, public and private office and administrative buildings, and school districts that were previously unregulated.

SUBCHAPTER E: MULTI-REGION COMBUSTION CONTROL

DIVISION 2: CEMENT KILNS

These rules implement a control strategy for cement kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area. Specifically, the commission is adopting a source-cap approach to establish a maximum NO _X emission cap for each account. As discussed elsewhere in this preamble, these rules are based on the commission's evaluation of the "Assessment of NO _X Emissions Reduction Strategies for Cement Kilns--Ellis County: Final Report," together with modeling sensitivity studies, and other available information. A source cap allows an owner or operator to choose the most applicable and cost-effective control technology available to a particular kiln while still achieving the overall reductions modeled for the Dallas-Fort Worth eight-hour attainment demonstration. Owners or operators may use any applicable control technologies to achieve reductions for compliance with the source cap. Before an increase in NO _X emissions from a change in operation from one unit or the installation of a new kiln could occur, a corresponding and equivalent decrease in NO _X emission will be required from another existing unit.

DIVISION 3, WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

The primary purpose of this division is to repeal the current 10 ng/J NO_X emission standard for certain gas-fired residential water heaters, as set forth in §117.465(b)(2). This emission standard has never become effective. The effective date has been extended through prior rulemaking, and it has subsequently been determined that compliance with the 10 ng/J standard for Type 0 units is not currently achievable. The basis for this determination is discussed earlier in this preamble in greater detail. All water heaters must still meet the 40 ng/J emission standard in the existing rules.

DIVISION 4: EAST TEXAS COMBUSTION

The new Chapter 117 will not affect private real property in a manner that will require compensation to private real property owners under the United States Constitution or the Texas Constitution. The rule adoption also will not affect private real 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. Therefore, the rulemaking will not cause a taking under Texas Government Code, Chapter 2007. No comments were received regarding this takings impact analysis.

CONSISTENCY WITH THE COASTAL MANAGEMENT PROGRAM

The commission determined the rulemaking relates to an action or actions subject to the Texas Coastal Management Program (CMP) in accordance with the Coastal Coordination Act of 1991, as amended (Texas Natural Resources Code, §§33.201 et seq. ), and the commission rules in 30 TAC Chapter 281, Subchapter B, concerning Consistency with the Texas Coastal Management Program. As required by 30 TAC §281.45(a)(3) and 31 TAC §505.11(b)(2), relating to actions and rules subject to the CMP, commission rules governing air pollutant emissions must be consistent with the applicable goals and policies of the CMP. The commission reviewed this action for consistency with the CMP goals and policies in accordance with the regulations of the Coastal Coordination Council and determined that the amendments are consistent with the applicable CMP goal expressed in 31 TAC §501.12(1) of protecting and preserving the quality and values of coastal natural resource areas, and the policy in 31 TAC §501.14(q), which requires that the commission protect air quality in coastal areas. The rulemaking and SIP revision will ensure that the amendments comply with 40 CFR Part 50, National Primary and Secondary Air Quality Standards, and 40 CFR Part 51, Requirements for Preparation, Adoption, and Submittal of Implementation Plans. This rulemaking action is consistent with CMP goals and policies, in compliance with 31 TAC §505.22(e). No comments were received regarding the consistency with the CMP.

EFFECT ON SITES SUBJECT TO THE FEDERAL OPERATING PERMITS PROGRAM

Chapter 117 is an applicable requirement under 30 TAC Chapter 122, Federal Operating Permits Program. Owners or operators subject to the federal operating permit program must, consistent with the revision process in Chapter 122, upon the effective date of the rulemaking, revise their operating permit to include the new Chapter 117 requirements.

PUBLIC COMMENT

Public hearings on the proposal were held on January 29, 2007, at 2:00 p.m. and 6:00 p.m. at the Houston-Galveston Area Council, Conference Room A, Suite 120, 3555 Timmons Lane, Houston; January 31, 2007, 7:00 p.m., J. Erik Jonsson Central Library Auditorium, 1515 Young Street, Dallas; February 1, 2007, at 2:00 p.m., Arlington City Hall Council Chambers, 101 W. Abrams Street, Arlington; February 1, 2007, at 6:00 p.m., Midlothian Conference Center, 1 Community Circle, Midlothian; February 6, 2007, at 2:00 p.m., Longview Public Library, 222 W. Cotton Street, Longview; and February 8, 2007, at 2:00 p.m., Texas Commission on Environmental Quality, 12100 Park 35 Circle, Building E, Room 201S, Austin. Oral comments regarding Chapter 117 were presented by Blue Skies Alliance (BSA), City of Dallas, Downwinders at Risk (Downwinders), Engine Manufacturers' Association (EMA), FPL Energy (FPL), HSC, Interfaith Environmental Alliance (IEA), J-W Power Company (J-W Power), Ellis County Judge Chad Adams (Judge Adams), Portland Cement Association (PCA), Public Citizen Texas Office (Public Citizen), Saint Gobain Containers (Saint Gobain), Tarrant County Judge Glen Whitley (Judge Whitley), Tarrant County Commissioner Roy Brooks (Commissioner Brooks), Texas State Representative Lon Burnam (Representative Burnam), TXU Power (TXU), XTO Energy Incorporated (XTO), and 65 individuals.

Written comments regarding Chapter 117 were provided by AeA Texas Council (AeA), Acme Brick Company (Acme), American Marazzi Tile (AMT), Anadarko Petroleum Corporation (APC), Ash Grove Texas L.P. (Ash Grove), BSA, Calpine Corporation (Calpine), CenterPoint Energy (CenterPoint), Chaparral Steel Midlothian (Chaparral), City of Dallas, City of Fort Worth, City of Garland, Compressor System Inc. (CSI), Devon Gas Services L.P. (Devon), Downwinders, East Texas Environmental Concerns Organization (ETECO), Eastman Chemical Company (Eastman), Energy Transfer Technologies (ETT), EMA, Environmental Defense (ED), EOG Resources (EOG), Exelon Generation (Exelon), ExxonMobil Production Company (ExxonMobil), FPL, Greater Fort Worth Sierra Club (GFWSC), Gulf Coast Lignite Coalition (GCLC), J-W Gathering Company (J-W Gathering), J-W Power, North American Insulation Manufacturers' Association (NAIMA), North Central Texas Council of Governments (NCTCOG), Northeast Texas Air Care (NETAC), NRG Texas LP (NRG Texas), Owens Corning Insulating Systems (Owens Corning), Penn Virginia Oil and Gas (PVOG), PCA, Public Citizen, Holcim (Texas) Limited Partnership (Holcim), Saint Gobain, Sustainable Energy and Economic Development Coalition (SEED Coalition), Texas Gas Service (TGS), Texas Independent Producers and Royalty Owners Association (TIPRO), Texas Instruments (TI), Texas Lime Company (Texas Lime), Texas Municipal Power Agency (TMPA), Texas Oil and Gas Association (TXOGA), Texas Pipeline Association (TPA), TXI Operations L.P. (TXI), TXU, United States Environmental Protection Agency (EPA), Vernon E Faulconer Incorporated (Faulconer), Westlake Chemical Corporation (Westlake), XTO, and 17 individuals.

RESPONSE TO COMMENTS

GENERAL COMMENTS

EPA requested the commission certify that, to the best of its knowledge, the emission specifications and associated control technologies proposed in Rule Project Number 2006-034-117-EN represent RACT or above for ozone pollution control purposes.

The commission appreciates the comment. In the Phase II Implementation Rule published in the Federal Register on November 29, 2005, EPA noted in the preamble on page 71655 that current NO_X and VOC RACT guidance could continue to be used by states in making RACT determinations for the eight-hour ozone standard. Additionally, EPA stated that for areas where major sources or source categories were previously reviewed states should review, and if appropriate, accept the initial RACT analysis as meeting RACT for the eight-hour standard. Absent data indicating that the previous RACT determination was no longer appropriate, states would not need to submit a new RACT determination for those sources. In such cases, EPA indicated states should submit a certification as part of its SIP revision, with appropriate information, that these sources are already subject to SIP-approved requirements that still meet the RACT obligation. The commission has completed a new analysis for RACT as part of the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP that documents that the emission specifications and associated control technologies proposed in this rulemaking represent RACT or above, in conjunction with information presented elsewhere in this preamble. The source categories in the Dallas-Fort Worth eight-hour ozone nonattainment area have been reviewed and evaluated to determine appropriate emission specifications, control requirements, and associated control technologies for those source categories. The commission determined that the controls adopted with this rulemaking are available, reasonable, and necessary to help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward attaining the eight-hour ozone NAAQS.

Devon commented that the agency needs to allow the use of infrared imaging in any developed inspection and maintenance requirements.

The commission is aware of and following the development of infrared imaging cameras and other technologies as alternative leak detection procedures; however, Devon's comment is beyond the scope of this rulemaking because such technologies are VOC detection methods.

GCLC commended the commission's efforts to receive stakeholder input and develop emission reduction strategies based on sound science. GCLC expressed support for the Chapter 117 reformat, especially efforts to include reasonable, local-level control strategies. GCLC congratulated the commission for successfully developing the Dallas-Fort Worth eight-hour ozone attainment demonstration that shows decreasing NO _X and VOC emission trends as a result of years of commission initiatives. GCLC supported the adoption of the rules as proposed with any technical corrections staff deems appropriate.

The commission appreciates the comment.

TMPA commented that changes should not be made to the proposed SIP that might require TMPA's Gibbons Creek Steam Electric Station in Grimes County to install SCR or that would place undue reliance on the application of new NO _X standards on electric generation facilities or be at variance with plans being promoted by the PUC and ERCOT for improvement of electrical power reliability in Texas. TMPA further commented that Powder River Basin (PRB) coal-fired units, such as Gibbons Creek, have experienced difficulties in receiving PRB coal deliveries due to mine and transportation-related constraints and that any alterations to the proposed SIP could eliminate the feasibility of Texas lignite as a boiler fuel and place an even greater burden on PRB coal mine and railroad capabilities.

The commission has not included any changes to the proposed rule that would impact TMPA's Gibbons Creek Steam Electric Station.

ETECO expressed support for stronger rules to require significant emissions reductions from cement kilns and electric generating units, controls on compressor engines in the 39 East Texas Combustion counties, and improved emissions controls on major and minor sources in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission appreciates the support. As discussed elsewhere in this preamble, the East Texas Combustion applicability rule is revised to apply to 33 counties.

An individual commented that all major electric generating sources in East and Central Texas outside the Dallas-Fort Worth eight-hour ozone nonattainment area should be required to meet fuel-specific emission requirements comparable to those in place in the Dallas-Fort Worth and Houston-Galveston-Brazoria ozone nonattainment areas. BSA, Public Citizen, and SEED Coalition commented that the commission should expand the proposed EGU control strategies beyond the Dallas-Fort Worth eight-hour ozone nonattainment area. Another individual commented that the power plants in Central Texas should be required to meet the same emission standards in the Dallas-Fort Worth and Houston area. BSA, Commissioner Brooks, City of Dallas, City of Fort Worth, Judge Whitley, NCTCOG, Public Citizen, and SEED Coalition expressed support for the North Texas Clean Air Steering Committee (NTCASC) resolution recommending the TCEQ's proposed rulemaking to require all major electric generation units in East and Central Texas meet fuel-specific emission requirements similar to those currently required in the Dallas-Fort Worth eight-hour and Houston-Galveston-Brazoria ozone nonattainment areas. Judge Whitley added that the best available technology should be used to reduce pollution from power plants.

The expansion of either proposed or currently effective Chapter 117 rules for electric generating sources or the application of other new control strategies to new persons would not allow for appropriate public review and comment. With regarding to initiating new rulemaking to require all major electric generation units in East and Central Texas to meet emission specifications similar to those required in the Dallas-Fort Worth eight-hour ozone nonattainment area and Houston-Galveston-Brazoria ozone nonattainment areas, the commission may initiate such rulemaking in the future if additional reductions from these sources are determined to be necessary. In response to Judge Whitley's comment regarding best available technology, power plants are required to meet BACT when plants are newly permitted or when modifications are permitted. Additional controls may be required when reviewing appropriate control measures necessary for demonstrating attainment. No changes have been made in response to these comments.

BSA, ED, Public Citizen, and SEED Coalition supported strengthening the standards proposed for ICI sources in the Dallas-Fort Worth eight-hour ozone nonattainment area to the level of the Houston-Galveston-Brazoria ozone nonattainment area. The commenters suggested that, before finalizing the rulemaking, the commission should justify that the nominal 90% level of control is not feasible, that the proposed standards are as stringent as is reasonably cost-effective, and that further reductions are not necessary for the Dallas-Fort Worth eight-hour ozone nonattainment area to attain and maintain the eight-hour ozone standard. The commenters added that the commission has never shown that the 90% level of controls initially adopted for the Houston-Galveston-Brazoria ozone nonattainment area were technically or economically infeasible.

The commission appreciates the support. The commission is adopting achievable and cost-effective NO _X emission standards for the affected sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission does not arbitrarily assume a 90% or 80% level of control is feasible, cost-effective, or necessary for an attainment demonstration. An achievable and cost-effective level of control for a particular source category depends on the current levels of emissions, available control technologies for the source category, and other technical and economic factors that may be specific to a source or to a region. The commission determined the appropriate level of control for sources in Dallas-Fort Worth eight-hour ozone nonattainment area considering all appropriate factors, including information obtained during the public comment period. Discussion regarding the level of control required on specific source categories is provided elsewhere in this preamble. Information regarding the analysis of the level of controls necessary for attainment of the eight-hour ozone NAAQS is available in Chapters 2 and 3 of the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP. No changes were made to the rule based on these comments.

NRG Texas expressed support for the commission's decision to not require further NO _X reductions from EGUs in East Texas or the Houston-Galveston-Brazoria area for the proposed eight-hour ozone attainment demonstration. NRG Texas added that substantial NO _X reductions from mobile, off-road, and other sources would be far more effective at reducing ozone at key monitors.

The commission appreciates the support and agrees that NO _X reductions from mobile, off-road, and other sources are necessary to reduce ozone in the nonattainment areas. As discussed elsewhere in this preamble, while the commission is not requiring NO _X reductions from EGUs in East Texas and the Houston-Galveston-Brazoria ozone nonattainment area is this rulemaking, the commission may initiate such rulemaking in the future if additional reductions from these sources are determined to be necessary.

CHAPTER 117 REFORMAT

EPA expressed appreciation of the commission's efforts in undertaking such a voluminous rulemaking project to reformat Chapter 117 and six specific rule revisions at the same time.

The commission appreciates the comment.

EPA requested that the commission clearly identify if any particular portions of the Chapter 117 submittal would be withheld from the EPA-approved Texas SIP. EPA added that unless the commission identified such sections in the submittal package, EPA would consider the submittal as if the commission wants all Chapter 117 to be considered for inclusion in the Texas SIP.

As discussed elsewhere in this preamble, the following sections are excluded from the Texas SIP: §§117.110(c), 117.125, 117.210(c), 117.225, 117.310(c), 117.325, 117.410(d), 117.425, 117.1010(b), 117.1025, 117.1110(b), 117.1125, 117.1210(b), 117.1225, 117.1310(b), 117.1325, 117.2010(i), 117.2025, 117.2110(h), 117.2125, 117.3010(e), 117.3025, 117.3123(f), 117.3125, 117.3310(e), and 117.3325.

EPA commented that Chapter 117 and Chapter 101, Subchapter H, Emissions Banking and Trading (Divisions 1, 3, 4, and 5), are inter-related and both are going through rule revisions. EPA suggested that the commission make sure that the rule cross-references are accurate and up-to-date, and commented that close coordination between Chapter 117 and Chapter 101 rule writers was essential.

The commission is aware of the numerous cross-references between Chapter 117 and Chapter 101, Subchapter H. The primary purpose of the Chapter 101 rulemaking noted by EPA is to update section cross-references to the new Chapter 117 section numbering adopted by the commission.

EPA commented that the terms "Equation" and "Figure" are used interchangeably particularly when a formula or equation is described, and suggested that the interchangeability be mentioned or explained in the preamble or that "Equation" be used in all cases.

The commission disagrees with EPA's suggestion. The figures in Chapter 117 include tables, equations, and definitions associated with the equation. Use of the term "equation" is dependent on the context of the particular sentence and unilaterally using "equation" would be inappropriate. No changes were made to the rule in response to this comment.

EPA commented that the "RACT" meaning Reasonably Available Control Technology is used or referred to more than 240 times throughout Chapter 117; however, RACT is not defined in §117.10. EPA recommended that the commission adopt EPA's long-standing definition of RACT from the September 17, 1979 issue of the Federal Register (44 FedReg 53761), "the lowest emission limitation that a particular source can meet by applying a control technique that is reasonably available considering technological and economic feasibility."

While the commission agrees with EPA's definition of RACT, it disagrees with EPA's suggested change. The term RACT is only used in Chapter 117 as a descriptor to distinguish those standards and requirements the commission has adopted for RACT purposes from those adopted for other purposes. The commission decides what is considered to be RACT for a particular source category during the evaluation phase of rulemaking. Including a definition of RACT in §117.10 would neither clarify the rule nor improve enforcement of the RACT requirements of any particular rule requirement. Therefore, the commission declines to make the suggested change.

Calpine commented that the definition of auxiliary steam boiler under §117.10(3) is overly narrow and should be expanded to include auxiliary boilers at cogeneration facilities. Calpine suggested the definition of auxiliary steam boiler be "boilers that produce steam for purposes other than generating electricity, including, but not limited to, replacing steam produced by primary steam production facilities at an account which are not operating due to planned or unplanned maintenance, equipment failures or other operational considerations."

As the commission indicated in the proposal preamble as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10539), comments received regarding sections and rule language associated only with reformatting and minor stylistic changes will not be considered and no changes will be made based on such comments, unless the comment is in regard only to how the language is reformatted. The rule section associated with Calpine's suggestion is included in those sections that were proposed solely for reformatting purposes; therefore, Calpine's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

Calpine commented that auxiliary steam boilers are used to produce steam for purposes other than generating electricity; therefore, auxiliary steam boilers should be excluded from the definition of electric power generating system under §117.10(14)(A) and (B) and should not be subject to the requirements applicable to units that produce electricity.

As explained elsewhere in this preamble, the rule section associated with Calpine's suggestion is included in those sections that were proposed solely for reformatting purposes; therefore, Calpine's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

Devon suggested a clarification to §117.145(e), regarding reporting for engines, that would specify that reports were not required if no excess emissions occurred during the period.

As explained elsewhere in this preamble, the rule section associated with the Devon's suggestion is included in those sections that were proposed solely for reformatting purposes; therefore, Devon's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

Devon commented that totalizing fuel meters should not be required for internal combustion (IC) engines and turbines and suggested a change to §117.140(a)(1)(B) and (C), as well as §117.340(a)(1)(A)(ii) and (iii).

As discussed elsewhere in this preamble, the rule sections associated with the Devon's suggestion are included in those sections that were proposed solely for reformatting purposes; therefore, Devon's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

EPA requested that the commission confirm the correct reading of the text appearing in the 5th row in the OPT-IN UNITS Table of Figures §§117.115(f), 117.215(f), and 117.315(f). EPA provided the referenced texts for confirmation.

The information contained in the 5th row in the OPT-IN UNITS Table of Figures §§117.115(f), 117.215(f), and 117.315(f), as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10903, 10909, and 10914), as well as in this rule adoption, is correct.

EPA requested the commission clarify whether the term "MRC" in Figure §117.115(g)(1) refers to maximum rated capacity in million British thermal units based on input or output of the affect unit.

Maximum rated capacity in Figure §117.115(g)(1) refers to million British thermal units based on heat input. Emission specifications for boilers and process heaters under §117.110 are on a lb/MMBtu heat input basis; therefore, the maximum rated capacity under §117.115(g)(1) would be on the same basis.

EPA suggested adding the words "or order" to §§117.115(g)(4)(B), 117.205(b)(6), 117.215(g)(4)(B), and 117.315(g)(4)(B), revising the provisions to read "The multiplier may not be used to increase a limit set by permit or order."

As explained elsewhere in this preamble, the rule sections associated with EPA's suggestion are included in those sections that were proposed solely for reformatting purposes; therefore, EPA's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

EPA commented that variable "I" used in the definitions associated with the equations in Figures §§117.123(b)(1), 117.223(b)(1), 117.323(b)(1), and 117.423(b)(1), should be expressed as lowercase "i" to properly match the variable identified in the respective equations.

While the rule sections associated with EPA's comments are included in those sections that were proposed solely for reformatting purposes, the commenter's suggested change is non-substantive and the change is necessary to conform to rule style and Texas Register formatting requirements. The commission has revised the case of variable "i" in Figures §§117.123(b)(1), 117.223(b)(1), 117.323(b)(1), and 117.423(b)(1) to be consistent with the definition of the variable in those figures.

EPA commented that variable "T" used to express time in hours when firing in equation §117.205(b)(6) should be expressed as lowercase "t" since uppercase "T" is normally used to designate temperature and not time.

The commission does not consider the suggested change necessary because the variable "T" is clearly defined in §117.205(b)(6). EPA's definition of and use of uppercase "T" is only relevant to equations and figures used in EPA regulations. No change has been made to the rule based on this comment.

EPA suggested adding the words "measured or calculated" to §117.210(c)(2), revising the provision to read ". . . not exceed 10 ppmv measured or calculated at 3.0% O ₂ . . .."

As explained elsewhere in this preamble, the rule section associated with EPA's suggestion is included in those sections that were proposed solely for reformatting purposes; therefore, EPA's suggested change is beyond the scope of this rulemaking. No change has been made to the rule based on this comment.

EPA suggested adding the words "considered as" to §117.240(j)(2), revising the provision to read ". . . or other methods that are demonstrated to satisfaction of the executive director and the United States Environmental Protection Agency to be considered as equivalent."

As explained elsewhere in this preamble, the rule section associated with EPA's suggestion is included in those sections that were proposed solely for reformatting purposes; therefore, EPA's suggested change is beyond the scope of this rulemaking. Furthermore, the commission does not consider EPA's suggested change to add any clarity or value to §117.240(j)(2). No change has been made to the rule based on this comment.

EPA suggested adding the words "and operation" to §117.240(m)(2) and §117.340(n)(2), revising the provisions to read "The plan must include a schedule of increments of progress for the installation and operation of the required control equipment."

EPA suggested adding the words "to minimize or eliminate excess emissions" to §117.245(e)(2), revising the provision to read ". . . the corrective action taken or preventative measures adopted to minimize or eliminate excess emissions ." EPA also suggested the same change to §117.3045(d)(2).

EPA suggested adding the words "or reagents" to §117.3045(e)(4), revising the provision to read "the injection rate of reactant chemicals or reagents (if applicable). . .."

EPA commented that the commission should add a new subparagraph (E) to §117.252(c)(2) to require owners or operators to provide the method of substitute emissions data when the NO _X monitoring system is not providing valid data.

EPA requested the commission elaborate on the reasoning behind deleting existing §117.115(c) from the new §§117.1052, 117.1152, and 117.1252.

The existing §117.115(c) only specified the means by which the information was required to be submitted, i.e., electronically and on hard copy using forms provided by the executive director. The commission does not consider it necessary to mandate the method of submitting the information as long as the content is provided as required by the rule. Electronic submittals provided by owners or operators subject to this provision are not used in any specific manner that could not be satisfied by a hard copy submittal. Specifying electronic and hard copy submittals places an unnecessary requirement on the regulatory community for compliance with these particular requirements in Chapter 117.

EPA commented that the commission should add the term "emission" to §117.310(d)(2), revising the provision to read ". . . an alternative to the CO or ammonia emission specification of this section. . .." EPA expressed concern that the provision may create confusion between the emission specification in §117.310(a) and the specification of a reagent, meaning the grade, quality, or type of reagent. EPA suggested a similar change to §117.325(a).

EPA suggested adding "and the United States Environmental Protection Agency" to §117.323(b)(1), revising the provision to read ". . .he executive director and the United States Environmental Protection Agency may approve another method . . .."

EPA suggested adding the word "applicable" to §117.340(l)(1), revising the provision to read ". . .the executive director may use other applicable commission compliance methods. . .."

EPA commented that the reference to 58 FR 11110 in §117.323(b)(4) should be replaced with EPA document number EPA-452/R-1-001 or with any corresponding appropriate citation from Chapter 101, Subchapter H concerning offset ratios between RACT and non-RACT sources, if one exists.

Calpine commented that the proposed change to §117.1200(a)(2), regarding applicability of Subchapter C, Division 3, for major utility electric generation sources in the Houston-Galveston-Brazoria ozone nonattainment area, would expand the applicability of the division to include independent power producers (IPP) that are subject to the rules regarding ICI sources. While the emission specifications in the two divisions are equivalent, Calpine commented that the allowance allocation schedules under Chapter 101, Subchapter H are not equivalent, and that the proposed change will result in confusion in future compliance determinations. Calpine requested that the language in §117.1200(a)(2) be modified to reflect the current IPP applicability under the ICI rules.

The commission agrees with the commenter. Independent power producers in the Houston-Galveston-Brazoria ozone nonattainment area are subject to the ICI rules under adopted Subchapter B, Division 3 and should not be subject to the rules associated with utility electric generation under Subchapter C. Independent power producers were inadvertently included in the applicability sections of §§117.1000, 117.1100, 117.1200, and 117.1300, as well as in the definition of electric power generation system in §117.10(14)(A) for the purposes of Subchapter C. The commission has revised §§117.10(14)(A), 117.1000, 117.1100, 117.1200, and 117.1300, accordingly.

EPA commented that the citation of §117.3000(4) in §117.3020(l) should be §117.3000(a)(4).

The commission agrees and has corrected the cross-reference error.

EPA commented that the NO _X emission specification in §117.4205 of 600 ppmv, calculated as nitrogen dioxide (NO ₂ ), for nitric acid manufacturing units, should include NO ₂ equivalent of 600 ppmv in pounds NO ₂ per ton of acid produced to make the requirement comparable with EPA NSPS requirement in 40 CFR §60.72.

EPA commented that Chapter 117 provides for compliance flexibility in §117.9800 and §117.9810, and requested that the commission explain why Chapter 117 does not provide for the flexibility of exploring additional NO _X control options and pilot plant experimentation. EPA further commented that flexibility for pilot plant experimentations could be incorporated in §117.3123 and §117.3125.

With regard to EPA's question concerning why Chapter 117 does not provide for additional NO _X control options and pilot plant experimentation, the commission encourages sources to explore additional NO _X control options through a variety of mechanisms. As much as possible, the commission attempts to design control strategies, and the rules that enforce those strategies, in such a manner as to not require owners or operators to use specific control technologies. If an owner or operator desires to explore new control technologies, Chapter 117 should not present an obstacle in most cases, provided the source complies with applicable rule requirements.

Regarding EPA's suggestion to include provisions for pilot studies under §117.3123, while a provision for mandatory pilot study could be incorporated in this section, the commission does not consider such a provision necessary. The commission has determined the appropriate control level for the source cap under §117.3123 for the purposes of this rulemaking. Furthermore, the commission has not specified an exact technology for the sources to use to meet the source cap. Therefore, cement kiln companies in Ellis County have the flexibility to explore other control technologies, as long as the site complies with the source cap for that site and all other applicable requirements.

Regarding EPA's suggestion to include a pilot study provision in §117.3125, the alterative case-specific specification provisions are not applicable to NO _X emission specification. Section 117.3125 provides regulated entities a mechanism to petition the executive director for an alternative ammonia emission specification if the source cannot meet the ammonia emission specification in §117.3123. No changes have been made to the rules based on these comments.

EPA suggested adding the words "for example" to §117.8010(2)(b), revising the provision to read ". . .or example, in million British thermal units, horsepower, or megawatts, as applicable). . .."

Zephyr Environmental commented that the reorganization of the Chapter 117 is an improvement over the previous version and suggested further reorganizing the rule based on unit types by placing requirements for each unit type in a single division.

The commission appreciates the support of the reorganiziation of Chapter 117. Although some of the divisions are unit type specific (e.g., cement kilns), the reorganized Chapter 117 is primarily organized by region to allow regulated entities in a specific nonattainment area to focus on requirements applicable to that area. Further subdividing the rule into additional unit type specific divisions would add complexity and repetition. Therefore, the commission declines to make the suggested change.

SUBCHAPTER B: COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

General

Devon and ExxonMobil commented that the majority of the oil and gas sources are located in the western portion of the Dallas-Fort Worth eight-hour ozone nonattainment area and even if all of these sources were removed, there would be no change in the monitored ozone concentrations at the Frisco monitor.

The commission is unaware of any modeling demonstrating that the oil and gas sources in the western portion of the nonattainment area have no impact on the Frisco monitor. The western counties of the nonattainment area are still classified as nonattainment for the eight-hour ozone NAAQS, and reductions from the oil and gas sources in those counties are necessary to help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward attaining the NAAQS.

Owens Corning expressed support for the commission's efforts to attain the eight-hour standard in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission appreciates the support.

Acme objected to the definition of a major source as proposed by the TCEQ in §117.10(29) and §117.410(f)(4) and asserted that the retroactive application of the major source definition and the designation of December 31, 2000, as the major source determination date was arbitrary, capricious, and unlawful. Acme proposed that the definition of a major source exclude those facilities that became major after the finalization of the 2000 emissions inventory or in the event that the newly permitted sources that caused the facility to have a potential to emit greater than 50 tpy were never actually constructed. Finally, Acme proposed that the major source determination date correspond to the date the Dallas-Fort Worth eight-hour ozone attainment SIP is approved by EPA. Acme commented that the commission's estimated NO_X reductions may be erroneous because the actual emission rates at its kilns are lower than the AP-42 factor of 0.35 lb/ton brick that may have been used to report to the commission for emissions inventory purposes. Acme requested that the commission create an administrative process through which sources could be excluded as a major source if the source can demonstrate that the emissions reported in the 2000 emissions inventory were not representative of the actual emissions during that time and that actual emissions were below 50 tpy.

The commission disagrees with the commenter's requested changes. The suggested change to the definition of major source in §117.10(29) is beyond the scope of this rulemaking. In addition, while the commission prefers actual measured data from testing or monitoring as opposed to estimated emission factors, the emissions inventory used for modeling and air quality planning purposes is based on the emissions data reported by sources at that time. Allowing retroactive modification of inventory information would undermine enforceability of current commission rules. Furthermore, the prohibition of circumvention provisions in §117.410(f) are necessary to ensure that modeled reductions are achieved. If sources were allowed to reduce emissions to just below the major source threshold to circumvent the rules, the full amount of reductions necessary for attainment may not be achieved. Regarding Acme's comment about permitted sources that were not constructed, the potential to emit, as defined in §122.10(20), is the maximum capacity of a stationary source to emit any air pollutant under its physical and operational design and configuration. As such, a unit that was permitted but never constructed would not have any potential to emit based on its physical and operational configuration because the unit would not actually exist.

Regarding Acme's comments about December 31, 2000, being the trigger date for major source designation, the commission disagrees with Acme's assertion that 2000 is arbitrary, capricious, and unlawful. The year 2000 is the inventory year for the entire state from which the future projected attainment year is built. The year 2000 is used in the prohibition of circumvention provisions of §117.410(f) to ensure that anticipated reductions based upon this inventory year and the future projected attainment year actually occur.

The commission is charged with protecting air quality within the state and to design and submit a plan to the federal government to achieve attainment and maintenance of the federally mandated NAAQS, specific standards set by federal law. The commission's discretion is inherently bound by the requirement to meet the NAAQS. As documented elsewhere in this preamble and the revised Dallas-Fort Worth eight-hour ozone attainment demonstration SIP (as well as the preamble for the proposed rules), the emissions reductions resulting from these rules are necessary to make progress toward the attainment, and maintenance of, the eight-hour ozone NAAQS throughout the state. The commission has adopted numerous measures in the past and with this attainment demonstration that are designed to reduce emissions from sources that individually may not appear to provide significant benefits toward progress for the attainment of the NAAQS, but the overall reductions will make progress toward attainment. Therefore, the rules comply with federal law, since they are designed to meet the NAAQS. In addition, the rules implement the commission's authority under state law to protect air quality within the state, and to design and submit a plan to achieve attainment and maintenance of the federally mandated NAAQS. In addition, there is precedent for the prohibition of circumvention provision because the commission has, in a prior rulemaking, implemented a similar prohibition of circumvention for the Houston-Galveston-Brazoria ozone nonattainment area.

The commenter's suggested change to base the major source definition on the date that EPA approves the Dallas-Fort Worth eight-hour ozone attainment SIP is impossible to apply and comply with because the commission must use a previous inventory to determine rules and modeled reductions for the attainment demonstration. The commission cannot submit an attainment demonstration SIP based on an inventory year that has not yet occurred. No changes have been made to the rule based on these comments.

AeA and TI commented that there was no reference in the proposed rule for downtime for emission control equipment maintenance and requested that the rule include provisions allowing shutdown time for emission control equipment maintenance.

The commission contends that maintenance of emission control equipment should be performed during routine unit shutdown time. Allowing units to exceed emission standards would undermine enforcement of the rule and the planned reductions necessary for attainment. No change has been made to the rule based on this comment.

AeA and TI noted that newly issued federal regulations in 40 CFR 60 Subpart IIII allow for 100 hours annually for maintenance and testing of emergency generators and fire pump engines. TI added that this time is required to fully comply with all local and national fire protection codes. The commenters requested that the commission revise §117.403(a)(7)(D) to be consistent with the newly issued federal regulations for stationary engines and allow 100 hours for maintenance and testing.

The commission agrees with the commenters. The additional hours allowed under the exemption are not expected to result in significant NO _X emissions or contribute to ozone formation in any material amount. In addition, engines subject to this exemption are still required to comply with the restriction on hours of operation for testing and maintenance purposes between 6:00 a.m. and noon. Therefore, the commission has made the suggested change to §117.403(a)(7)(D).

AMT suggested that, should the commission withdraw the proposed rules regulating the ceramic tile source category, the commission should delete all requirements relating to ceramics found in §117.440(a)(1)(G) and (P) and (c)(1)(F).

The commission has not withdrawn the portions of the rule related to ceramic tile sources. Therefore, the requirements in §117.440(a)(1)(G) and (P) and (c)(1)(F) are necessary for the source to demonstrate compliance with the emission specifications of the rule. No change has been made to the rule based on this comment.

AMT commented that the references to ceramic kilns in §117.400 and §117.410(b)(7) do not include ceramic kilns used to produce ceramic tile. AMT further commented that the commission has no basis to include ceramic tile kilns within the SIP rules based on actions, hearings, or deliberations by the NCTCOG. AMT noted that although NCTCOG's consultants proposed to evaluate the ceramic tile industry, the ceramic tile industry was not directly mentioned or included in the final control measures catalog. AMT also commented that the term "ceramic kilns" is used in §117.403(b)(7)(B) and the term "ceramic tile" is used in §117.400(11) and §117.410(b)(13) and that the difference between these two terms are significant and legally relevant.

The commission disagrees with the commenter's interpretation of §117.400 and §117.410(b)(7). Ceramic kilns used to produce ceramic tile would be included in the more general group of ceramic kilns. Ceramic kilns used to produce ceramic tile are subject to §117.400 and §117.410(b)(7), unless otherwise exempt by an applicable exemption under §117.403. Regarding AMT's comment concerning the NCTCOG control measures catalog, the commission is not limited to the control measures investigated by NCTCOG. The commission understands the difference between ceramic kilns and ceramic tile. Ceramic tile is only used in context with dryers used in ceramic tile processes, and ceramic kiln is only used in context with kilns of that type. No changes have been made to the rule based on these comments.

AMT commented that as §117.410(b)(13) is currently worded, it is unclear as to which descriptors apply to the term "dryer." Therefore, AMT suggested that the regulation does not give fair notice to the regulated community on which dryers are to be regulated and should be deleted. AMT also noted that there is no discussion, evidence, or other supporting information in the NCTCOG control measures catalog for the control of dryers at ceramic tile manufacturing facilities. AMT proposed that §117.410(b)(13) be rewritten with the word "tile" deleted.

The commission disagrees with the comment that fair notice has not been provided to owners or operators of dryers. However, to avoid any potential minor misinterpretation of §117.400(11) and §117.410(b)(13), the commission has revised the language to specify natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic tile, calcining, and vitrifying processes. In addition, as discussed elsewhere in this preamble, the commission is not limited to control measures described in the NCTCOG control measures catalog. Furthermore, the commission provided analysis and discussion on the control of dryers in the proposal preamble as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10538 - 10607).

Chaparral asserted that the CO limit in §117.410(d)(1) was impossible to achieve for electric arc furnaces. Chaparral commented that steel production in electric arc furnaces requires the significant addition of carbon and the formation of CO is not primarily a combustion by-product. In addition, Chaparral maintains that the 3% O ₂ correction factor, although sensible for stack measurement of combustion by-products, is technically inappropriate for monitoring the stack emissions from electric arc furnaces because the majority of the stack gas results from particulate control and has high concentrations of excess air. Chaparral also noted that the Dallas-Fort Worth eight-hour ozone nonattainment area is in attainment for CO and therefore the proposed rule provides little or no basis for establishing the 400 ppmv at 3% O₂ limit for Chaparral's electric arc furnaces and steel reheat furnaces. The commenter indicated that Chaparral's electric arc furnaces and reheat furnaces subject to the proposed rule have existing CO limits in permits, and that these permits are the proper mechanism for setting CO emission limits. Chaparral requested that the CO limit be removed from §117.410(d)(1), exempt electric arc furnaces and reheat furnaces from those limits or in the event that these limits remain, that a 30-day rolling average be applied to the CO limit for electric arc furnaces and reheat furnaces with CEMS or PEMS.

As discussed elsewhere in this preamble, the commission is exempting electric arc furnaces used in steel production. Therefore, Chaparral's electric arc furnaces are not subject to the CO emission specification in §117.410(d)(1). The commission disagrees with the commenter regarding reheat furnaces. The 400 ppmv limit in §117.410(d)(1) is necessary to ensure that NO_X control strategies implemented as a result of this rule do not result in a corresponding increase in CO that may not have been considered at the time of permitting. In addition, the commission has provided a mechanism for regulated sources to petition the executive director for an alternative CO emission specification under §117.425. The commission also maintains that the rolling 24-hour average for compliance with the CO emission specification is reasonable for units equipped with CEMS or PEMS. No change has been made to the rule in response to this comment.

Texas Lime asserted that, based on its interpretation of §117.400, Subchapter B, Division 4 did not apply specifically to limestone dryers.

The commission agrees that limestone dryers would not be subject to Subchapter B, Division 4 provided the dryers were not natural gas-fired organic solvent, printing ink, clay, brick, ceramic tile dryer or a dryer used in calcining and vitrifying processes.

Exemptions

Devon and ExxonMobil commented that the exemption threshold for existing process heaters in §117.403 should be 10 MMBtu/hr due to the high cost of retrofit and low emission reductions from smaller process heaters. The commenters indicated that some smaller process heaters may have to be replaced due to flame impingement issues associated with installing low-NO _X burners. AMT requested that the exemption level for process heaters with an input heat rated capacity of 2.0 MMBtu/hr be raised to 5.0 MMBtu/hr due to the difficulty in attaining the 0.036 lb/MMBtu standard for their heaters with a maximum capacity less than 3.0 MMBtu/hr even with low-NO _X burners. AMT also suggested that the exemption limit for natural gas-fired dryers, heaters, and ovens in §117.403(a)(4) should also be raised to 5.0 MMBtu/hr.

The commission agrees that a higher exemption threshold is warranted for small process heaters and natural gas-fired dryers, heaters, and ovens because of potential difficulty in retrofitting existing units of this size and the limited NO _X emissions from these source categories below the suggested exemption level at major sources in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission has revised the exemption in §117.403(a)(1) to specify that process heaters equal to or less than 5.0 MMBtu/hr are exempt. The 2.0 MMBtu/hr exemption threshold for boilers is unchanged and adopted as proposed. The exemption in §117.403(a)(4) is also revised to exempt natural gas-fired dryers, heaters, and ovens equal to and less than 5.0 MMBtu/hr.

Johns Manville commented that the applicability of the rule with regard to heaters used for comfort heat purposes was unclear and suggested that heaters for comfort use purposes should not be subject to the rule. Johns Manville indicated that some comfort heaters used to provide heat to large work areas could be larger than the proposed 2.0 MMBtu/hr exemption threshold for natural gas-fired heaters.

The commission did not intend to regulate heaters used exclusively for providing comfort heat with this rulemaking. Therefore, the commission has revised §117.403 to include a new §117.403(a)(16) that exempts natural gas-fired heaters used exclusively for providing comfort heat to areas designed for human occupancy.

Devon and ExxonMobil commented that some oil and gas sites are required to have electric generating engines because there is no grid connection available. The commenters stated that such generators should be allowed if the engine meets the control requirements and that a provision should be added for short-term power generation as long as the generation does not exceed 10% of the time.

Subchapter B, Division 4 does not prohibit electric generating engines. Engines, electric generating or otherwise, that meet the applicable emission specifications in §117.410, and all other requirements, would not be in violation. In addition, exemptions are provided in §117.403 for emergency generators. No change has been made to the rule based on this comment.

Acme requested that major source brick kilns not be subject to Subchapter B, Division 4. Acme proposed that the exemption limit for select brick and ceramic kilns be altered from the currently proposed heat input based 5.0 MMBtu/hour to units with emissions below 0.2625 lb NO _X /ton of fired brick. Acme suggested that the 0.2625 lb NO _X /ton exemption limit is appropriate because NO _X reductions from units below this limit would not contribute significantly to the area's ozone attainment.

The commission disagrees with the suggested change to the exemption and the commenter's assertion that units with NO _X emissions less than 0.2625 lb/ton are not significant. The commission chose the 5.0 MMBtu/hr exemption level to exempt kilns that may be technically or economically infeasible to control due to the small size of the unit. In addition, the commission is not required to demonstrate that reductions from an individual unit contribute significantly to attainment. The commission has adopted numerous measures in the past and with this attainment demonstration that are designed to reduce emissions from sources that individually may not appear to be significant, but the overall reductions will advance attainment. The commission maintains that NO _X reductions from major source brick kilns will help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward attainment with the NAAQS. No change has been made to the rule based on this comment.

TI commented that although the proposed emission limits for natural gas boilers are technically feasible and that vendors and materials are available, some boiler vendors have expressed concerns that this is not the case for the liquid-fired part of the boiler. The boilers at TI are required to fire liquid fuel oil during emergency natural gas curtailments. TI added that these emergency conditions are rare, short in duration, and usually occur in winter months. The last such gas curtailment period in the Dallas-Fort Worth eight-hour ozone nonattainment area was in 2003. TI requested that the commission adopt an emergency fuel oil firing exemption for major and minor sources required to use fuel oil as an emergency back-up similar to the exemption in place for utility electric generation sources under §117.1303(b).

The commission agrees with the commenter and has adopted a new §117.403(c) to provide an emergency fuel oil firing exemption for gas-fired boilers. New §117.403(c) specifies that the emission specifications in §117.410(b)(1) and (d) do not apply to gas-fired boilers during periods that the owner or operator is required to fire fuel oil on an emergency basis, such as a gas curtailment, provided certain conditions are met. New paragraph (1) specifies that the fuel oil firing may only occur during the months of November, December, January, or February. This provision limits the exemption to non-ozone season months only. New paragraph (2) specifies that the fuel oil firing must not exceed a total of 72 hours in any calendar month specified in paragraph (1). Based on the information provided by the commenter, this amount of time should be sufficient to account for periods of fuel oil firing cited by the commenter is not expected to result in significant NO _X emissions or contribute to ozone formation in any material amount.

Technical Feasibility

EPA commented on the difference between the NO _X emission specification of 3.1 lb/ton of calcium oxide proposed in §117.410(b)(7)(A) for lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area and the NO _X emission specification of 0.66 lb/ton of calcium oxide for lime kilns in the Houston-Galveston-Brazoria ozone nonattainment area. In response to the commission's requesting comment on the emission specification proposed for lime kilns in §117.410(b)(7)(A), EPA suggested that the commission consider actual NO _X emissions from tests conducted in recent years from the lime kilns operating in Texas. EPA also provided information concerning California's San Joaquin Rule 4313-Lime Kilns, adopted March 27, 2003, and information from a Title V air permit for a pulp and paper facility that included NO _X emission standards for lime kilns of 0.44 lb/ton of calcium oxide. EPA requested a technical and economic justification for the final NO _X emission specification for lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission originally considered the Houston-Galveston-Brazoria ozone nonattainment area NO _X emission specification for the lime kiln source category in the Dallas-Fort Worth eight-hour ozone nonattainment area; however, during the stakeholder process, the commission received information that indicated the lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area are a different category of lime kilns. The 0.66 lb/ton of calcium oxide for the Houston-Galveston-Brazoria ozone nonattainment area is based on lime recovery kilns at pulp and paper mills, similar to the lime kilns in the Title V information provided by EPA. The lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area are lime manufacturing kilns. Lime manufacturing kilns use different feed materials, preheater and vertical shaft kilns, and higher temperatures and production rates. These differences make the 0.66 lb/ton emission specification infeasible for lime manufacturing kilns, based on currently available controls. In addition, recent BACT limits for lime manufacturing kilns range from 3.1 - 4.5 lb/ton of calcium oxide. The San Joaquin rule cited by EPA appears to apply to lime recovery kilns based on the feed materials described in the rule and would not be appropriate for lime manufacturing kilns. The emission specification adopted in this rulemaking, 3.7 lb/ton of calcium oxide, is based on BACT information on permitted lime manufacturing kilns as well as the production and emission rates specific to the lime manufacturing facility in the Dallas-Fort Worth eight-hour ozone nonattainment area. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10600). However, that fiscal analysis was based on the proposed emission specification and not the controls adopted in this rulemaking for lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission's decision to change the control level for these lime kilns is based on technological feasibility and not economic feasibility. The cost impact to the owners or operators of lime kilns in the Dallas-Fort Worth eight-hour ozone nonattainment area will be less than projected in original fiscal analysis.

EPA commented on the difference between the NO _X emission specification of 0.10 lb/MMBtu proposed in §117.410(b)(8)(B) for reheat furnaces in the Dallas-Fort Worth eight-hour ozone nonattainment area and the NO _X emission specification of 0.062 lb/MMBtu for reheat furnaces in the Houston-Galveston-Brazoria ozone nonattainment area. EPA requested a technical and economic justification for the 0.10 lb/MMBtu NO _X emission specification for reheat furnaces in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission originally considered the Houston-Galveston-Brazoria ozone nonattainment area NO _X emission specification for the reheat furnaces in the Dallas-Fort Worth eight-hour ozone nonattainment area. However, during the stakeholder process, the commission received information that indicated the specific reheat furnaces in Dallas-Fort Worth eight-hour ozone nonattainment area are significantly larger, of different design, and operate at higher temperatures than the reheat furnaces in the Houston-Galveston-Brazoria ozone nonattainment area. In addition, because the Houston-Galveston-Brazoria ozone nonattainment area has a cap and trade program in place, the source may not necessarily meet an emission specification on an individual basis but rather the overall reductions are accomplished on an area-wide basis. The emission specification proposed and adopted with this rulemaking, 0.10 lb/MMBtu, was determined based on documented BACT limits for similar permitted units and emissions data from the reheat furnaces in the Dallas-Fort Worth eight-hour ozone nonattainment area. This emission specification represents approximately a 50% reduction from the facility's permitted rates. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599).

EPA requested a technical and economic justification for the NO _X emission specification in §117.410(b)(8)(C) of 0.30 lb/ton of product for electric arc furnaces used in steel production.

The commission provided a technical discussion as well as fiscal analysis of the proposed controls for this source category in the proposal preamble published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599). However, as discussed elsewhere in this preamble, the commission has decided to exempt electric arc furnaces used in steel production from this rulemaking.

EPA requested a technical and economic justification for the NO _X emission specification in §117.410(b)(8)(D) of 0.45 lb/ton of product for lead smelting blast (cupola) and reverberatory furnaces used in conjunction.

The commission determined the 0.45 lb/ton of product emission specification for this source based on the specific operating conditions at the facility of this source category that operates in the Dallas-Fort Worth eight-hour ozone nonattainment area. As discussed in the proposal preamble and elsewhere in this preamble, owners or operators may be required to use a combination of low-NO _X burners and FGR or possibly post-combustion controls such as SNCR to achieve this emission specification. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599).

EPA requested a technical and economic justification for the NO _X emission specification in §117.410(b)(10)(A) of 1.30 lb/ton of glass pulled for glass melting furnaces.

The commission based the proposed 1.3 lb/ton of glass pulled on the NO_X emission limits from EPA's consent decree for the Saint Gobain facility in Madera, California. After further analysis of BACT and emission and production limits from the facility in the Dallas-Fort Worth eight-hour ozone nonattainment area, the commission has revised the NO_X emission limit to 4.0 lb/ton glass pulled. This limit is consistent with newly drafted regulations for similar source types at San Joaquin Valley Air Pollution Control District (SJVAPCD) and Ozone Transport Commission (OTC). The 1.3 lb/ton of glass pulled NO _X emission specification in the consent decree was for a new unit, not an existing unit. Furthermore, the container glass furnace planned for the Madera, California facility is a different design than the furnace located at the Saint Gobain facility in Waxahachie. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599). The commission's decision to revise the emissions specifications for this source type was based on the additional technical information provided by commenters and was not based on an economic analysis.

EPA requested a technical and economic justification for the NO _X emission specification of 1.45 lb/ton of product pulled in §117.410(b)(10)(B) and (C) for mineral wool-type electric fiberglass melting furnaces and mineral wool-type fiberglass regenerative furnaces.

The commission based the proposed limit of 1.45 lb/ton of product pulled for mineral wool-type fiberglass electric and regenerative furnaces on informal comments made by Johns Manville during the stakeholder process. Johns Manville indicated that the regenerative furnaces at the Johns Manville facility could reach NO _X emission limits between 1.4 and 1.8 lb/ton product pulled. After reviewing formal comments received from Owens Corning, the commission has determined that the proposed emission specification of 1.45 lb/ton of product pulled is not appropriate for mineral wool-type fiberglass cold-top electric or non-regenerative gas-fired melting furnaces. The commission has revised the emission specifications in §117.410(b)(10)(B) for mineral wool-type fiberglass cold-top electric melting furnaces to 4.0 lb/ton product. The emission specification of 4.0 lb/ton product for mineral wool-type fiberglass cold-top electric melting furnaces is based on the SJVAPCD rule. In addition, the commission has revised the emission specification in §117.410(b)(10)(D) for mineral wool-type fiberglass non-regenerative gas-fired melting furnaces to 3.1 lb/ton product. This limit is based on the permit limit for the unit at the Owens Corning facility. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599). The commission's decision to revise the emissions specifications for this source type was based on the additional technical information provided by commenters and was not based on an economic basis.

EPA requested a technical and economic justification for the NO _X emission specification in §117.410(b)(11) of 0.036 lb/MMBtu for gas-fired curing and forming ovens used in mineral wool-type or textile fiberglass.

As discussed elsewhere in this preamble, the emission specification for gas-fired curing ovens is based on the use of low-NO _X burners. In response to comments from Owens Corning and as explained elsewhere in this preamble, the commission has exempted forming ovens and forming processes from this rule. A fiscal analysis of the controls for this source category was performed by the commission for proposal and was published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599).

Devon and ExxonMobil agreed that the proposed 0.5 g/hp-hr NO _X emission specification for rich-burn engines was obtainable, but suggested that the minimum size engine requiring controls should be 50 hp.

The commission agrees with the commenter that 50 hp is a reasonable exemption threshold because the number of engines less than that size located at major sources of NO _X in the nonattainment area are expected to be minimal and have minimal emissions. The adopted rule includes a new §117.403(a)(13) that exempts stationary, gas-fired, reciprocating internal combustion engines that are less than 50 hp. The commission is limiting this exemption to gas-fired engines only.

Devon and ExxonMobil commented that NO _X emission reductions from lean-burn gas-fired engines was very costly and that there are currently no known lean-burn engines that consistently meet the proposed 0.5 g/hp-hr standard. The commenters indicated that the current technical limitation for lean-burn engines is 0.7 g/hp-hr NO _X . In addition, the commenter indicated that the rule would result in all lean-burn engines being replaced with less efficient fuel rich-burn engines because add-on NO _X controls, such as SCR, for lean-burn engines are uneconomical and EGR is not proven, or if applied would reduce fuel efficiency. The commenters proposed that existing lean-burn engines installed prior to June 1, 2007, should be limited to 0.7 g/hp-hr, and all new lean-burn engines should be required to meet 0.5 g/hp-hr. Devon and ExxonMobil also suggested that the proposal allow for trading within the Dallas-Fort Worth eight-hour ozone nonattainment area, as well as trading from sources outside the nonattainment area that likely have an impact on the air quality of the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission disagrees with the commenters' assertion that 0.70 g/hp-hr is the current technical limitation of lean-burn engines. A review of two major engine manufacturers' specifications and emission rates for available lean-burn engines indicates that 0.50 g/hp-hr is achievable on a range of engine models and sizes. The commission acknowledges that control of gas-fired lean-burn can be more expensive to control than rich-burn engines; however, lean-burn engines comprise a significant portion of the emissions from gas-fired engines in the nonattainment area. However, a number of lean-burn engines in the Dallas-Fort Worth eight-hour ozone nonattainment area are already meeting a 0.70 g/hp-hr NO _X emission rate. The amount of additional reductions resulting from the small incremental decrease to 0.50 g/hp-hr is minimal and could require SCR to achieve the small decrease. In addition, the overall difference in total reductions between the proposed 0.50 g/hp-hr emission specification and the commenter's suggested 0.70 g/hp-hr emission specification is only approximately 0.2 tpd for major sources subject to this rule. Therefore, the commission has adopted a NO _X emission specification of 0.70 g/hp-hr for existing lean-burn engines placed into service prior to June 1, 2007, that have not been modified, relocated, or reconstructed on or after that date. Lean-burn gas-fired engines installed, modified, relocated, or reconstructed on or after June 1, 2007, must meet 0.50 g/hp-hr NO _X to ensure that as new lean-burn engines are installed or existing lean-burn engines are modified, relocated, or reconstructed, the engines will be required to meet the lowest achievable emission specification.

The commenters' suggestion of a trading program specifically for the Dallas-Fort Worth eight-hour ozone nonattainment area is beyond the scope of this rulemaking; however, the commission points out that there are currently available trading options open to the commenter under Chapter 101. The adopted rules do allow trading as a means of compliance flexibility by reference to §117.9800.

J-W Power expressed concerns regarding lean-burn and rich-burn gas-fired engines within the Dallas-Fort Worth eight-hour ozone nonattainment area similar to the comments J-W Power submitted for the East Texas Combustion rule. The commenter added that meeting the NO _X emission specifications in the Dallas-Fort Worth eight-hour ozone nonattainment area would require removing all of J-W Power's lean-burn engines prior to the compliance date and cost $3.5 million in relocation and installation fees. J-W Power noted the limited capacity of engine manufacturers to produce rich-burn engines and cited the current lead-time on these engines is 55-85 weeks. J-W Power recommended the standards for gas-fired engines in the nonattainment area be consistent with the standards for the East Texas Combustion rule suggested by J-W Power.

The lean-burn engine emission specifications in the proposed East Texas Combustion rule are not sufficient to achieve the necessary NO _X reductions from lean-burn engines in the nonattainment area. However, as discussed elsewhere in the preamble, the commission has revised the emission specification for lean-burn engines to 0.70 g/hp-hr for existing lean-burn engines placed into service prior to June 1, 2007, and have not been modified, relocated, or reconstructed on or after that date. Lean-burn gas-fired engines installed, modified, relocated, or reconstructed on or after June 1, 2007, must meet 0.50 g/hp-hr NO _X . The 0.50 g/hp-hr emission specification for rich-burn gas-fired engines is achievable and the commission has made no change to the emission specifications for this type of engine.

ETT requested that the commission consider revising the rule to include provisions for hybrid-drive natural gas compressor systems that can be operated by either a gas-fired engine or an electric motor. ETT commented that hybrid-drive compressor systems offer significant environmental benefits by improving compressor uptime, reducing emission events, transferring NO _X emissions from the higher emitting engines to the cleaner and more efficient electricity generators while operating the electric motors. ETT noted that the proposed output-based standard for utility electric generators is one-third the standard for gas-fired engines. ETT asserted that because the hybrid-drive compressor can switch to gas-fired engine drive during peaking electricity demand, hybrid-drive use will not increase the need for more generation capacity. The commenter added that the ETT hybrid-drive compressors are capable of running on the electric motor 90% of the time and that the gas-fired engines are equipped with SCR systems that can achieve a 1.0 g/hp-hr emission rate. However, ETT indicated that the proposed 0.5 g/hp-hr standard would require the installation of additional controls to meet the standard while firing gas. Therefore, ETT requested that the commission allow NO _X emissions averaging over a 12-month period for hybrid-drive compressor systems for demonstrating compliance with the 0.5 g/hp-hr standard. In addition, ETT requested that this averaging mechanism only be allowed for hybrid drive compressor systems capable of operating without emissions more than 75% of the time. ETT also requested that the commission consider including a short-term NO _X limit of 1.0 g/hp-hr in the rule for natural gas-fired engines used in hybrid-drive compressor systems. Finally, ETT requested that the East Texas Combustion rule and the Dallas-Fort Worth eight-hour ozone nonattainment area Minor Source rule include this limited averaging time.

While the commission acknowledges that hybrid-drive compressors may offer some benefits over standard gas-fired engine driven compressors, as well as standard electric motor driven compressors, the commission declines to make the suggested change. Because the commenter's gas-fired engines are already equipped with controls, the owner or operator should be able to modify the controls to meet the emission standards adopted in the final rule without significant cost. Furthermore, the suggested requirements to qualify for the alternative averaging mechanism may affect regulated entities that would not have opportunity to comment on the requirements if adopted in the rule. In addition, as discussed elsewhere in this preamble, the rule allows the use of ERCs and discrete emission reduction credits (DERCs) for compliance under §117.9800. For an existing compressor engine replaced with a hybrid-drive compressor engine that has not received TERP funding, the owner or operator may also generate DERCs during zero emission operation using electricity for compliance with NO _X emission specifications according to the provisions of 30 TAC Chapter 101, Subchapter H, Division 4. Following Chapter 101, Subchapter H, Division 4 guidelines regarding proper certification of emission reductions and notice of intent to use, certified DERCs may then be used by owners or operators to comply with the emission specifications during gas-fired operation. No change has been made to the rule based on this comment.

Acme commented that the emission specification proposed of 0.175 lb/ton is based on low-NO _X burners. This technology has not been demonstrated in the United States on brick kilns, and the cost associated with the installation of low-NO _X burners on brick kilns was grossly underestimated. Acme indicated that the proposed emission standard was not appropriate for brick kilns because low-NO_X burners are not available for brick kilns. Acme suggested that a 40% reduction would be feasible through operational and production changes. AMT asserted that process changes possibly necessary to achieve the emission specifications, such as lowering the thermal energy consumption requirements of the fired product, or changes to the tile body may cause a loss of market share and profitability and therefore the cost estimates in the NCTCOG control measures catalog Control Measure # 69 are grossly underestimated.

The commission based the NO _X emission specification of 0.175 lb/ton on the application of combustion and process modifications, installation of low-NO _X burners, or staged combustion or some combination of these controls. Although the application of low-NO_X burners alone may not necessarily achieve the 0.175 lb/ton product emission specification in all cases, the commission maintains that a combination of these controls should enable sources to achieve the emission specification. Furthermore, from the supplemental information provided by Acme, the adopted emission specification represents approximately a 10 to 30% reduction from recent stack test data for some of Acme's brick kilns. These reductions should be well within the range achievable through the use of the above-referenced control technologies. However, as discussed elsewhere in this preamble, the commission is allowing an option of a 40% reduction from the daily NO _X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 emissions inventory.

Regarding Acme and AMT's comments concerning cost, the commission's fiscal analysis for brick and ceramic kilns did not use the NCTCOG cost estimates. The fiscal analysis provided in the proposal preamble published in the December 29, 2006, issue of the Texas Register (31 TexReg 10599) estimated the total capital costs for all brick and ceramic kilns to be as much as $3.5 million. This cost estimate was based on the commission's analysis of the anticipated control technologies used to comply with the emission specifications associated with the source category. Furthermore, the commission is not able or required to account for market share and profitability factors in performing the fiscal analysis. These factors are influenced by economic decisions made by owners and shareholders, and the commission has no means to predict the outcome of these decisions.

AMT commented that the proposed NO _X emission limit of 0.175 lb/ton product is not appropriate for ceramic tile kilns. AMT referenced EPA's National Emission Standards for Hazardous Air Pollutant standards as demonstration that the EPA recognized the differences between brick and ceramic kilns. The commenter also noted that AMT's ceramic kilns use natural gas and that the energy consumption was based on the green or unfired weight of product; therefore, the use of a final product weight standard would artificially increase the reported NO _X emissions. AMT also suggested an alternative NOX emission specification of 0.27 lb/ton of product for ceramic kilns based on a 50% reduction from the EPA AP-42 emission factor of 0.54 lb/ton of product for ceramic kilns.

While the commission acknowledges that NO _X emissions lb/ton would be different if calculated based on unfired weight of product, the commission maintains that the product output weight is appropriate for determining NO _X emission on lb/ton product basis. Variability in the unfired material could introduce uncertainty in the final calculated emissions. Furthermore, basing the emission standard on the fired product weight will encourage efficiency with regard to emissions, whereas an unfired material weight basis might have the opposite result. However, the commission agrees with the comment that the adopted 0.175 lb/ton product emission specification may not be appropriate for all brick and ceramic kilns. Therefore, the commission has revised §117.410(a)(7)(B) to include an alternative compliance option that allows owners or operators to achieve a 40% reduction from the daily NO _X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 emissions inventory. In addition, the commission agrees that a higher emission specification for ceramic kilns is necessary because the assumed uncontrolled emission factor is greater than for brick kilns. Therefore, the commission has included a separate emission specification option of 0.27 lb/ton of product for ceramic kilns as suggested by AMT.

AMT commented that the proposed emission standard in §117.410(b)(13) was not achievable for spray dryers used in ceramic tile processes. AMT asserted that due to the configuration and operation of the AMT spray dryers the proposed 0.036 lb/MMBtu NO _X emission specification was not achievable through combustion modifications and that post combustion controls, such as SCR and SNCR, were not appropriate due to the low exhaust temperature of the spray dryers. AMT proposed an alternative emission specification of 0.15 lb/MMBtu for spray dryers.

Based on the information provided by the commenter and the relatively low NO _X emissions from ceramic tile spray dryers in the nonattainment area, the commission agrees that an alternative emission standard is appropriate for spray dryers used in ceramic tile processes and has revised the rule as suggested. Based on the process information provided by AMT, spray dryers used in ceramic tile manufacturing processes have technical limitations that would limit an owner or operator's ability to meet the 0.036 lb/MMBtu emission specification. The control technology that would normally be applicable to achieving the 0.036 lb/MMBtu emission specification for typical natural gas-fired dryers may not be available for spray dryers used in ceramic tile manufacturing processes because of the low exhaust gas temperature and the configuration of the fired heater in relation to the dryer portion of the system.

Saint Gobain expressed concerns with the proposed NO _X limits for glass melting furnaces. Saint Gobain noted that the currently proposed NO _X emission limit of 1.3 lb/ton glass pulled is based on a consent decree that the EPA reached with Saint Gobain for the Saint Gobain facility in Madera, California. The commenter added that the 1.3 lb/ton limit was based on a new oxy-fuel furnace design and would require the installation of an untested and undemonstrated fused-cast crown design. In addition, Saint Gobain indicated that the oxy-fuel furnaces are a different design from the Waxahachie regenerative furnace and that oxy-fuel firing was not an add-on or retrofit control technology. Saint Gobain commented that compliance with the currently proposed NO _X limit would require the demolition of their regenerative furnace and the construction of the fused-cast crown oxy-fuel furnace as well as an oxygen plant.

Saint Gobain noted that the SJVAPCD, where the Madera plant is located recently amended a comprehensive regulation for glass furnaces that has also been adopted by the northeastern states OTC. This regulation sets a NO_X emission limit of 4.0 lb/ton. Saint Gobain urged the commission to either exempt their facility from the rulemaking and enter into a case-by-case agreed order, or adopt the SJVAPCD/OTC NO _X emission limit of 4.0 lb/ton glass pulled. Saint Gobain added that there are demonstrated cost-effective add-on combustion technologies available and appropriate to their Waxahachie regenerative furnace that could reduce NO _X emissions in excess of 115 tons per year at the 4.0 lb/ton limit.

As discussed elsewhere in this preamble, the 1.3 lb/ton glass pulled emission specification was proposed based on the EPA consent decree. For the reasons provided by the commenter, the commission agrees that the 1.3 lb/ton glass pulled emission specification is not appropriate for the container glass furnaces at the Waxahachie facility because the Waxahachie furnaces are existing units and of a different design. The commission has revised the NO _X emission specification to 4.0 lb/ton glass pulled as suggested.

Saint Gobain requested that the commission provide an alternate idling limit addressing a phenomenon unique to glass furnaces that requires the facility to keep glass molten within the regenerative furnace even during non-productive periods. Saint Gobain noted that an alternative idling limit is included in the SJVAPCD rule and is necessary due to the operating nature of the units.

The commission agrees that the 4.0 lb/ton glass pulled emission specification would not be feasible during idling operations due to the extremely low production of glass during idling. Rather than specify a definition of idling and prescribe an alternative standard during idling operations, the adopted rule specifies that during periods of operation less than 25% of permitted glass production capacity, the NO _X emission limit is the maximum allowable pound per hour emission rate specified in a permit issued before June 1, 2007. The 25% threshold for this distinction is equivalent to the SJVAPCD rule.

Owens Corning commented that the glass melting furnaces located at the Owens Corning facility, especially the electric glass melting furnaces, require the addition of a sodium nitrate oxidizer to allow for the melting of the glass cullet as well as reduce waste glass, raw batch materials, and cost of materials. Owens Corning added that the sodium nitrate oxidizer is the primary source of NO _X from these sources, not fuel combustion. Owens Corning and NAIMA asserted that the proposed limit of 1.45 lb/ton of product for mineral wool furnaces was unreasonable due to technical limitations, and urged the commission to adopt the 4.0 lb/ton limit used by the OTC and SJVAPCD. Owens Corning added that the electric furnaces could reach the 4.0 lb/ton by limiting the amount of nitrogen-based melting aid and oxidizer. In addition, Owens Corning commented that adopting the SJVAPCD limit would still result in a 0.96 tpd reduction from the V-2, and V-3 electric furnaces, and that the region would only be losing 0.4 tpd. Owens Corning also requested clarification regarding the rule applicability as it applies to mineral wool type regenerative furnaces. Owens Corning's V-1 furnace is a gas-fired, oxy-firing, non-regenerative furnace and would not be technically regulated by the proposed rule. Owens Corning commented that the V-1 furnace already uses oxy-firing and its permit limit is below the 4.0 lb/ton; therefore, Owens Corning suggested that the final emission specification for attainment demonstration (ESAD) for fiberglass melting furnaces be 4.0 lb/ton product.

The commission agrees with Owens Corning that the proposed emission specification of 1.45 lb/ton of product pulled is not appropriate for mineral wool-type fiberglass cold-top electric or non-regenerative gas-fired melting furnaces. The commission has revised the emission specifications in §117.410(b)(10)(B) for mineral wool-type fiberglass cold-top electric melting furnaces to 4.0 lb/ton product and the emission specification in §117.410(b)(10)(D) for mineral wool-type fiberglass non-regenerative gas-fired melting furnaces to 3.1 lb/ton product. The emission specification of 4.0 lb/ton product for mineral wool-type fiberglass cold-top electric melting furnaces is based on the OTC and SJVAPCD limit as suggested. The NO _X emission specification of 3.1 lb/ton product for mineral wool-type fiberglass non-regenerative gas-fired melting furnaces is based on the permit limit for the unit at the Owens Corning facility.

Owens Corning requested a rule clarification for §117.410(b)(11) as it applies to curing and forming ovens. Owens Corning commented that there is no oven-like structure in its forming process that uses fiberizer burners, which are used to turn molten glass into glass fibers. The commenter also indicated that the fiberizer burners are by nature not amenable to a low-NO_X , low temperature configuration. Owens Corning requested clarification whether forming processes that do not employ an oven would be subject to §117.410(b)(11).

The commission did not intend to regulate forming processes that do not include an oven-like structure or the fiberizer burners described by the commenter. The commission's intent was to regulate ovens that are used in the forming of finished products from fiberglass or mineral wool materials. Based on the description provided by the commenter, the fiberizers are forming processes to produce fiberglass materials. Furthermore, Owens Corning's fiberizers represent the majority of emissions from this source category. Therefore, the commission has revised the rule language in §§117.400(9), 117.403(a)(15), 117.410(b)(11), and 117.440(a)(1)(M) to only specify fiberglass and mineral wool curing ovens and exempt forming ovens and forming processes.

Owens Corning commented that its curing process uses a phenolic-based binder, the use of which results in NO _X emissions when the ammonia and other nitrogen-containing compounds off-gas from the binder and form NO _X with available oxygen. The commenter proposed that the commission use technology specific regulations such as low NO _X burners, oxy-firing, or the equivalent rather than specify a lb/MMBtu emission limit as an input-based standard on curing ovens. Owens Corning asserted that a lb/MMBtu standard would essentially impose restrictions on the use of phenolic binders at the plant. Owens also recommended this technology-based regulation for its incinerators, and proposed the final ESADs in §117.410 distinguish incinerators and ovens used in fiberglass manufacturing and apply a technology-based regulation.

The commission agrees that the use of nitrogen-bound chemical additives could make achieving the NO _X emission specifications for curing and forming ovens infeasible. Due to non-combustion thermal NO_X being formed through the use of these additives, low-NO _X burners and FGR may not be able to achieve the emission specification. In addition, the low operating temperature of these processes make post-combustion control techniques such as SCR and SNCR infeasible. Therefore, the commission has provided an exemption in §117.403(a)(12) for curing and forming ovens used in mineral wool-type fiberglass manufacturing in which nitrogen-bound chemical additives are used.

Regarding Owens Corning's suggestion for incinerators, the commission's inventory analysis indicates that Owens Corning's incinerators should be below the 40 MMBtu/hr exemption provided in the rule. In the event that Owens Corning does have an incinerator with a maximum capacity greater than or equal to 40 MMBtu/hr, the emission specifications for incinerators already provide the option of an 80% reduction that is not required to be on a heat input basis. Post-combustion controls such as SCR have been demonstrated to achieve NO _X reductions from incinerators of at least 80%.

Chaparral requested the commission remove electric arc furnaces from the rulemaking because the current permit allowable for Chaparral's electric arc furnaces were equivalent to the proposed limits and there would be no associated NO _X reductions from the proposed limit. Chaparral added that the majority of NO _X is thermal NO_X created by the electric arc and not by combustion and that Chaparral units already use oxy-firing, the suggested NO _X control technology, for fuel-efficiency purposes. Chaparral also requested that the NO _X emission specifications for electric arc furnaces of §117.410(b)(8)(C), should it remain, specify the use of oxy-fuel burners rather than the lb/ton limit. Chaparral commented that control efficiency requirements and emission limits are not appropriate to electric arc furnaces as the majority of the NO _X is thermal from the electrodes and not tied to production rates.

Due to the potential technical issues and substantial costs associated with the facility's compliance with the rule for the electric arc furnaces, and the fact that the facility has already achieved the reductions planned for electric arc furnaces under the proposed rule, the commission agrees that electric arc furnaces used in steel production should not be subject to the rule. The commission has revised the applicability to exclude electric arc furnaces used in steel production, and provided an exemption for electric arc furnaces used in steel production in §117.403.

Chaparral claimed that it has not had sufficient time to determine if Chaparral's reheat furnaces can technically and economically meet the proposed NO_X limit of 0.1 lb/MMBTu and CO limit of 400 ppmv at 3% O ₂ , dry basis. Chaparral asserted that due to some products having a higher energy demand and associated higher NO_X emissions than others, the proposed NO _X limits for reheating furnaces would be more practical, economically feasible, and consistent with the regulatory goals if the limits in §117.410(b)(8)(A) and (B) were to be applied only during the peak ozone season. Chaparral indicated production of the larger more energy intensive products could be scheduled in the off-season.

Based on the commission's analysis, the commenter's reheat furnaces should be able to achieve the emission specifications in the adopted rule through combustion modifications, installation of low-NO _X burners or FGR, or a combination of these control technologies. However, the commission acknowledges that shifting seasonal production is sometimes a viable means of reducing emissions and the commenter's request for flexibility to shift production to non-ozone season is reasonable in this case. Therefore, the commission has revised the adopted §117.410(b)(8)(A) and (B) to specify that for heat treating and reheat furnaces equipped with NO _X CEMS or PEMS that the emission specifications only apply between March 1 to October 31 of each calendar year. The requirement that the unit be equipped with NO _X CEMS or PEMS is necessary because the seasonal changes in emissions would make only performing an initial test insufficient for demonstrating compliance. Regarding Chaparral's comments concerning the CO limit, §117.425 provides a mechanism for owners or operators to petition the executive director for an alternative CO emission specification.

Chaparral requested that an Alternative Plant-Wide Emission Limit compliance option be included in Subchapter B, Division 4. Chaparral noted that there was not a viable emissions banking and trading program in the Dallas-Fort Worth eight-hour ozone nonattainment area, and that because the source cap was based on the average heat input in 2000-2001 calendar years, Chaparral would require the additional flexibility of an Alternative Plant-Wide Emission Limit option because production capacity has increased significantly since that time.

The commission is phasing out the Alternative Plant-Wide Emission Limit as an alternative approach in Chapter 117. The Alternative Plant-Wide Emission Limit was originally adopted for RACT purposes and is an antiquated alternative means of demonstrating compliance. For the rules adopted for the Dallas-Fort Worth eight-hour ozone nonattainment area, the commission prefers unit-by-unit emission specifications, the optional source cap, or unit type specific approaches, such as the approach adopted for lime kilns or the ozone season only option provided to the commenter as discussed elsewhere in this preamble. These approaches provide greater assurance that planned reductions will actually be achieved. The commission asserts that with the options provided under the adopted rule, the commenter should be able to comply with the rule without the Alternative Plant-Wide Emission Limit. No change has been made to the rule based on this comment.

Texas Lime commented that the proposed limit of 3.1 lb/ton of calcium oxide (CaO) in combination with the requirement that NO _X be monitored using either a CEMS or PEMS in §117.440 is more stringent than what is commonly regarded as BACT. Texas Lime noted that although the permit limit for the Gallatin lime kiln is 3.1 lb/ton CaO, the Gallatin kiln is not required to maintain a CEMS or PEMS and was only required to demonstrate the rate during a three-hour stack test. The commenter also noted that the Gallatin kiln is not yet operational and therefore the proposed rate has not yet been demonstrated. Texas Lime commented that the newer kilns at Gallatin are designed with preheaters, highly energy-efficient combustion systems, and are significantly shorter than the older Texas Lime kilns. Texas Lime has recently retrofitted its old long kilns with preheaters, replaced the wet scrubbers with baghouses, and installed state-of-the-art control systems which has improved fuel efficiency by 27% and correspondingly reduced NO _X emissions. Texas Lime noted that despite the recent retrofits, the length of the older kilns leads to greater radiant heat loss and inherent compromises in combustion retrofits with older designs, the Texas Lime kilns cannot achieve the same fuel and energy efficiency or NO _X emission rates. Texas lime suggested that an alternative plant-wide emission limit of 4.1 lb/ton CaO on a 30-day rolling average monitored with a CEMS or PEMS may be technically and economically feasible for its kilns. This emission limit would result in a 28% reduction in NO _X emissions, equating to 440 tons per year based on actual production rates for Kilns 5 and 6 in 2005/2006. Texas Lime commented that the flexibility of an alternative plant-wide emission option is available in the Houston-Galveston-Brazoria ozone nonattainment area and requested this option be included in §117.410(e). Texas Lime also requested that because Kiln 4 NO _X emissions were included in the 2000 baseline, the closure of Kiln 4 should be taken into account when determining how further control measures resulting from the rule impact their site in the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission agrees with Texas Lime that the proposed NO _X emission limit of 3.1 lb/ton of CaO is infeasible for older, less efficient kilns. Therefore, the commission has revised the NO _X emission specification in §117.410(b)(7)(A) to allow for compliance with the 3.7 lb/ton CaO limit on an individual unit-by-unit basis or on a site-wide production weighted average basis. The equation for calculating the site-wide production weighted average would be based on the actual lb/ton emission rate and daily production rate of each kiln. Through an analysis of BACT and emission and production rate data from the Texas Lime facility, the commission is confident that the 3.7 lb/ton limit can be met on a site-wide average using proper NO _X emission controls and good engineering practices. Regarding Texas Lime's comments concerning the alternative plant-wide emission specification option, sources in the Houston-Galveston-Brazoria ozone nonattainment area are not allowed to use the alternative plant-wide emission specification as an option. This option was revoked in prior rulemaking for major sources in the Houston-Galveston-Brazoria ozone nonattainment area under existing §117.207(j) and new §117.315(i). As discussed elsewhere in this preamble, the commission is not allowing the alternative plant-wide emission specification as an option for the new rules adopted for the Dallas-Fort Worth eight-hour ozone nonattainment area. The site-wide production weighted average option provided for lime kilns in the adopted rule provides sufficient flexibility for Texas Lime to comply with the rule.

Monitoring, Testing, Recordkeeping, and Reporting

Devon and ExxonMobil commented that totalizing fuel meters should not be required for IC engines and turbines and suggested a change to §117.440(a)(1)(D) and (E). The commenters indicated that horsepower and actual hours of operation should be used to determine emissions.

The commission agrees and has provided an additional alternative to totalizing fuel flow meters in §117.440(a)(2)(D) that allows the use of a continuous monitoring system that continuously monitors horsepower and hours of operation as an alternative to install fuel flow meters for engines and turbines. Associated recordkeeping is also required in §117.445(f)(3)(C) for owners or operators that elect this option.

Devon and ExxonMobil suggested that §117.445(e) be revised to not require reporting on engines if no excess emissions occurred during the period.

The provisions in §117.445(e) are consistent with current requirements for engines in the Dallas-Fort Worth eight-hour ozone nonattainment area under existing §117.219 as well as other nonattainment areas. No change has been made to the rule based on this comment.

Devon and ExxonMobil commented that the requirement in §117.445(f) that records should only be required for two years for minor sources to coincide with recordkeeping requirements for other minor sources of emissions and the provisions of 30 TAC §106.352.

The requirement to maintain records for five years is consistent with other recordkeeping requirements under Chapter 117. In addition, the five-year record retention requirement is necessary for agency investigators to have adequate historical documentation to verify compliance with requirements specific to Subchapter B, Division 4 that are not considered in §106.352. No change has been made to the rule based on this comment.

AeA and TI commented that there was no provision in the rule to allow downtime for fuel flow meter calibration, testing, and maintenance, although the rule requires these meters be installed on all boiler units and be accurate to within ± 5%. The commenters requested that the commission adopt language in the rule allowing downtime for flow meter calibration, testing, and maintenance.

The commission agrees that some time should be allowed for owners or operators to perform calibration, testing, and maintenance on the totalizing fuel flow meters. Therefore, adopted §117.440(a) is revised to specify that the owner or operator must continuously operate the totalizing fuel flow meter at least 95% of the time that the unit is operating, averaged over a calendar year.

Chaparral commented that in the event that a NO _X and CO limit is retained in the adopted rule for electric arc furnaces, the rule should exempt these units from any requirement to monitor or test the units for compliance with these specifications. The two electric arc furnaces at Chaparral are contained in a large melt-shop from which their emissions and emissions from other sources are commingled and gathered through a positive pressure system into five baghouses for dust and particulate removal. These baghouses have 24 emission points, and Chaparral asserted it would be technically impossible to determine the NO _X and CO emission rates of the two electric arc furnaces from the total melt-shop effluent.

As discussed elsewhere in this preamble, the commission has exempted electric arc furnaces used in steel production. Therefore, Chaparral's electric arc furnaces are not subject to the testing and monitoring requirements in §117.435 and §117.440. No change has been made to the rule in response to this comment.

TI expressed its concern with any further NO _X reductions for point sources while urging the commission to consider cost per ton of emission reductions. TI estimated costs for reductions from TI's natural gas-fired boilers would be approximately $2 million to make 14 tons reductions or approximately $142,000 per ton, and if it is required to control NO _X to the liquid-fired boiler emission specifications during emergency fuel oil firing, these costs could reach an estimated $5 million per ton. TI suggests these costs should be compared to other NO _X reduction programs such as mobile source reductions funded under TERP.

Chaparral commented that without considering annual costs, Chaparral would incur capital costs of $6 million to achieve reductions of 353 tons per year. The commenter noted that due to the smaller amount of reductions attained from the two smaller mills at the Chaparral site, the cost per ton at these mills would be four or five times higher than those at the larger mill. Chaparral commented that this cost is not practical and economically feasible for the associated tons of reduction.

The commission does consider cost per ton when performing control strategy analyses; however, the commission must also consider technical feasibility, amount of reductions necessary to demonstrate attainment, and legal authority when evaluating control measures. The commission has limited authority to regulate motor vehicles due to federal preemption. While the commission acknowledges that the cost per ton of NO _X reduced would likely be higher for a smaller unit, the commission points out that units of much smaller size than the units in question by the commenters are required to make reductions as well under the adopted rule. Substantial NO _X reductions are necessary for the Dallas-Fort Worth eight-hour ozone nonattainment area to make progress toward attainment with the NAAQS. If the commission only focused control strategies on the largest of units, insufficient reductions would be achieved and the area would not reach attainment as expeditiously as practicable. In addition, TI's cost estimates appear to only include first-year costs and reductions. Reductions in NO _X emissions will be realized every year after the first year and must be considered as well. The commission's fiscal analysis considered annualized costs and total reductions over the first five years. If only first-year capital costs and first-year reductions are used, the cost per ton is significantly inflated and is not representative of the on-going benefits of the rule. As discussed elsewhere in this preamble, the commission has provided an exemption for gas-fired boilers that are required to fire fuel oil for emergency purposes for limited periods of time.

SUBCHAPTER C: COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 4: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

General

Calpine expressed support for the commission's proposed output-based NO_X emission standard in §117.1310(a)(1)(C). Calpine commented that the output-based standard should be expanded to apply to gas-fired turbines because this would encourage cleaner, more efficient power generation for a wider range of electric generation facilities. Calpine also commented that, for combined-cycle units, the MW-hour output should be based on total MW-hour output produced by the unit, including the contribution from waste heat recovery and steam turbine output.

FPL commented that although the proposed rules are a fair and balanced implementation of the federal requirements given the many challenges facing the Dallas-Fort Worth ozone nonattainment area, FPL suggested the output-based standard be applied to combined cycle combustion turbines on the basis that it would encourage efficiency, effectively integrating energy efficiency into the emissions control program. FPL noted that increased efficiency reduces all pollutants, including NO _X , sulfur dioxide (SO ₂ ), CO, and carbon dioxide (CO ₂ ). In addition, the output-based standard for combined cycle would allow for a direct comparison between different generation technologies and fuel types, and would better economically support emission allowance trading. FPL commented that the output-based standard was intended to apply to energy efficient gas-fired combined cycle combustion turbine peaking units; however, the exemption of all stationary gas turbines of a certain age, regardless of what type of fuel is burned, is in conflict with the intention of the output-based specification to encourage energy efficient units. FPL recommended that if the output-based emission specification was intended to apply to combined cycle combustion turbines, then the exemption is unnecessary and should be removed.

While the commission appreciates the support for the output-based standard and agrees with the commenter's statements regarding the benefits of output-based standards, removal of the exemption would impact other parties that would not have the opportunity to comment on the change or other rule requirements because they were exempt under the rule proposal. No change has been made to the rule based on these comments.

Calpine commented that the proposed standards in §117.1310(a)(2) and (a)(3)(A)(i) and (B)(i) include standards for auxiliary steam boilers and combustion turbines that apply while firing natural gas, but there is no standard for other gaseous fuels such as refinery off-gas or hydrogen. Calpine requested clarification from the commission as to whether the proposed rules are intended to apply to other gaseous fuel-fired units.

The standards in §117.1310(a)(2) and (a)(3)(A)(i) and (B)(i) are identical to the current standards in existing §117.105(a), which specifies that the standards apply when firing natural gas or a combination of natural gas and waste oil, and §117.105(f)(1) and (g)(1), which specify that the standards apply when firing natural gas. It is not the commission's intent to expand this applicability.

The City of Garland expressed support for the rule as proposed for adoption by the commission. The commenter agreed that the specifications in §117.1310(a)(1)(A) relating to utility boilers that are part of a small utility system were appropriate. City of Garland also provided Garland Power and Light's informal comments of September 15, 2006, which included a Position Statement indicating that the removal of the small utility system provision would result in the City of Garland shutting down its electric utility operations.

The commission appreciates the City of Garland's comment in support of the proposed rule. No change has been made to the small utility system emission specification in §117.1310(a)(1)(A).

Technical Feasibility

BSA, ED, Public Citizen, and SEED Coalition expressed support for the proposed Dallas-Fort Worth eight-hour ozone nonattainment area Electric Generating Units Rule, but suggested that the emission specification for small utility systems should not be different from the emission specification for large utility systems. BSA, ED, Public Citizen, and SEED Coalition commented that any exceptions should be based on whether the unit's emissions are de minimis and do not adversely affect air quality in the region. TXU requested that all utility boilers in the Dallas-Fort Worth eight-hour ozone nonattainment area be regulated "on a level playing field" and therefore recommended that the differentiation between "small utility systems" and "large utility systems" be removed from §117.10, and §117.1310. TXU noted that this change would result in an additional 0.4 tpd reductions in NO _X emissions in the area.

The commission appreciates the support for the rule. Regarding the separate emission standard for small utility systems, there is only one operational small utility system in the Dallas-Fort Worth eight-hour ozone nonattainment area. The commission has determined that subjecting this one small utility system to the same emission control requirements of the large utility systems would not be economically reasonable.

TXU commented that it is a member of the Association of Electric Companies of Texas (AECT) and expressed support for the AECT comments. TXU commented that the proposed rules will likely result in a decrease in the generation resources available in the Dallas-Fort Worth eight-hour ozone nonattainment area due to the forced retirement of certain EGFs and suggested that ERCOT will have to factor this reduced generation availability into ERCOT's reserve margin forecasts. TXU also suggested that the commission apply the currently proposed emission specifications on a site-wide or "regulated entity" basis, so that compliance may be demonstrated by averaging the emissions from all the utility boilers on a site.

Exelon commented that all of the utility boilers at the Mountain Creek and Handley stations are peaking units and the failure to include a system cap compliance option would force the shutdown of Mountain Creek Units 6 and 7, two natural gas-fired peaking units. Exelon added that Mountain Creek 6 and 7 are peaking units and therefore cannot maintain temperatures necessary for effective catalytic reduction of NO _X . Exelon also asserted that peaking Mountain Creek Units 6 and 7 are necessary to provide reactive power requirements to maintain system reliability and these units were dispatched by ERCOT under "Out of Merit Orders" for approximately 30% of the units' combined operating hours in 2005 and 2006. Exelon asserted that removing the system cap as a compliance option from EGU owners and operators in the Dallas-Fort Worth eight-hour ozone nonattainment area is arbitrary and unfair because the system cap remains an option in the Houston-Galveston-Brazoria ozone nonattainment area. Exelon requests the agency retain the system cap compliance option for EGUs under Subchapter C, Division 4 or incorporate a system-wide averaging compliance option.

It is not the commission's intent to adversely affect system reliability in the Dallas-Fort Worth area through implementation of attainment demonstration rulemaking. The commission disagrees with Exelon that removing the system cap as a compliance option is arbitrary and unfair and the system cap is not an option in the Houston-Galveston-Brazoria ozone nonattainment area. Electric generating facilities in the Houston-Galveston-Brazoria ozone nonattainment area are required to comply with the system cap in existing §117.108, now adopted in §117.1220. The commission may provide system or source caps as an alternative means of compliance or as a mandatory means of compliance to achieve reductions, such as in mandatory system caps for electric generating facilities in the Houston-Galveston-Brazoria ozone nonattainment area and the mandatory source cap for the cement kilns in Ellis County adopted with this rulemaking under §117.3123. Similarly, the commission can remove the system cap as an option in order to achieve reductions. If a system cap were allowed to remain in place for the Dallas-Fort Worth eight-hour ozone nonattainment area, no reductions would be achieved from EGUs in the nonattainment area, which is not the commission's intent. However, in order to address Exelon's issues associated with Mountain Creek Units 6 and 7, the commission is providing a system-wide heat-input weighted averaging option for compliance with the NO _X emission limits. This option will still achieve NO _X reductions from EGUs in the area and maintain the region's system reliability. The commission has revised §117.1310(a)(1)(D) to allow for a system-wide heat-input weighted averaging option for compliance with the large utility system NO _X emission specification of 0.033 lb/MMBtu.

Monitoring, Testing, Recordkeeping, and Reporting

Exelon commented that units subject to the proposed rule would be required to conduct ammonia slip testing and that Exelon units had recently already performed such testing. The commenter added that ammonia slip testing is expensive and should not be required to just confirm the results of recently performed testing, especially when the unit is subject to ammonia monitoring of current §117.114(a)(4) and proposed new §117.8130. Exelon requested that units newly subject to the eight-hour specifications not be required to repeat ammonia slip testing if it has been performed within ten years of March 1, 2009.

The commission disagrees with the commenter's assertion that ammonia testing is expensive. Ammonia testing can normally be done in conjunction with other testing; however, even as a stand-alone test, the commission estimates that an initial ammonia test would cost approximately $2,500 - $3,000. In addition, Exelon's units cannot be subject to the ammonia monitoring requirements of current §117.114 because that section is only applicable to units subject to current §117.106(c), which only applies to utility electric generating units in the Houston-Galveston-Brazoria eight-hour ozone nonattainment area. Because Exelon's units are not subject to the ammonia monitoring requirements of §117.114, it is possible some variations in the ammonia slip may have occurred since the prior ammonia test. Furthermore, the initial test for ammonia also serves a specific purpose in determining the correction factor "d" in the mass balance equation in §117.8130. Depending on the ammonia monitoring option selected by Exelon under §117.8130, the recent ammonia test cited by Exelon may not satisfy all requirements of the rule. Therefore, the commission declines to make the suggested change.

FPL commented that stationary gas-fired turbines used for peaking service that only operate during peak demand hours of the day cannot maintain compliance with the one-hour block average CO emission limit of 132 ppmv due to the large variations in related emissions inherent with frequent startup and shut down. FPL requested that the commission take these technical limitations into account when performing any revisions to the CO standard.

The commission disagrees with the commenter that a different averaging methodology is necessary for stationary gas-fired turbines used for peaking service to meet the proposed CO standard. In addition, stationary gas-fired turbines placed into service after 1992 are exempt from the rule and thereby exempt from the CO standard in §117.1310(b). Based on the commission inventory information, there are no stationary gas-fired turbines used for peaking service that were placed into service prior to 1992 in the Dallas-Fort Worth eight-hour ozone nonattainment area. No change has been made to the rule based on this comment.

SUBCHAPTER D: COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

DIVISION 2: DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

General

ED expressed support for the proposed Dallas-Fort Worth eight-hour ozone nonattainment area Minor Source NO _X Rule.

The commission appreciates the support.

EPA expressed support for the monthly Btu limitations for the low usage exemptions in §117.2103(b)(1) and (2).

The commission appreciates the support; however, the commission has decided to exempt boilers and process heaters from the rule. Therefore, the low fuel usage exemption proposed in §117.2103(b)(1) and (2) is not included in the adopted rule.

EMA suggested the proposed regulations not be approved and finalized at this time, and that commission staff work further with interested stakeholders to address and correct the problematic issues in the current proposed rule.

The commission disagrees with the commenters' suggestion to not finalize the rules. The rules are necessary to achieve NO _X reductions that are needed for the Dallas-Fort Worth eight-hour ozone nonattainment area to make progress toward attainment with the NAAQS. Revisions have been made to the adopted rules to address certain issues raised by commenters that the commission agreed warranted changes.

Exemptions

Devon and ExxonMobil commented that the exemption threshold for process heaters in §117.2103 for minor sources should be higher because such sources are very small NO _X emission sources, and suggested exemption thresholds of 15 MMBtu/hr for existing process heaters and 10 MMBtu/hr for new process heaters. The commenters also indicated that some smaller process heaters may have to be replaced due to flame impingement issues associated with installing low NO _X burners.

After further evaluation, the commission has determined that process heaters at minor sources of NO _X do not represent a significant source of emissions in the Dallas-Fort Worth eight-hour ozone nonattainment area. Emission reductions from process heaters under the proposed rule would be minimal. Therefore, the commission has decided to exempt process heaters from the adopted rule.

EMA commented that under Subchapter D, Division 2, if the commission is going to provide exemptions based on de minimus emissions or size, equivalent criteria should be used in order to provide a level playing field across technologies. EMA suggested that, if a 2 MMBtu/hr boiler receives an exemption, it follows that an engine with a horsepower rating less than or equal to 250 hp should also be exempt. EMA recommended that the final rule should provide exemptions for boilers, engines, and turbines that are of equal power or emissions impact.

The commission does not consider it appropriate to apply arbitrary size exemptions across different source categories regardless of the type of equipment in that category, as suggested by the commenter. This is especially true in the example suggested by the commenter because boiler horsepower is not equivalent to engine horsepower. In addition, engine rating in MMBtu/hr can vary significantly depending on engine type and manufacturer. Exemptions are more appropriately determined based on the source category and the type of service. The commission maintains that the 50 hp exemption in the adopted rule is appropriate for stationary engines and is consistent with similar rules previously adopted for the Houston-Galveston-Brazoria ozone nonattainment area. No change has been made to the rule based on this comment.

EMA recommended revising the language concerning exemptions for emergency engines. EMA stated §117.2103(a)(2)(E) provides an exception for emergency engines installed prior to June 1, 2007, but excludes the exemption for emergency engines placed into service after that date. EMA asserted that the intent in §117.2103(a)(2)(E), (H), and (I) were not clear, and the regulatory language was confusing and should be revised to provide owners and operators clear direction in the acceptable use of emergency engines and cite correct references to the NSPS standards. Also, EMA recommended the exemptions proposed in subparagraphs (H) and (I) should apply to all engines not just diesel engines. EMA recommended the commission maintain the exception for emergency engines past the June 2007 date proposed in the current regulation. EMA stated that emergency engines can include both diesel and gaseous-fueled engines, but the proposed language sometimes refers only to diesel engines and the proposed rule should not distinguish between fuel types.

The exemptions associated with the commenter's suggestion have been renumbered to §117.2103(5), (8), and (9) due to other changes made to the exemptions based on comments received. The commission contends that the exemption provisions in §117.2103(5), (8), and (9) are clear. The exemption in §117.2103(5) is only revoked for diesel engines. New gas-fired emergency engines that meet the restriction on hours per year will still qualify for exemption under §117.2103(5). Emergency diesel engines may still qualify for exemption under §117.2103(8) or (9). The purpose of §117.2103(8) and (9) is to ensure that as diesel engines are replaced, modified, or relocated, the engines will either be required to meet the emission specifications or will be replaced with cleaner diesel engines that meet the EPA standards in 40 CFR §89.112(a), Table 1 (October 23, 1998). No change has been made to the rule based on this comment.

EMA recommended clarifying the phrase in §117.2103(a)(2)(I)(i) "in other than emergency situations." EMA contends, as the phrase is written, it could be interpreted to mean the engines operating under emergency conditions are not exempt for the rule requirements, even if they operate less than 100 hours per year.

The provision in §117.2103(9)(A) is designed to allowed owners or operators 100 hours per year to operate the engines for testing and maintenance purposes. There is no restriction on hours of operation for emergency use. The commission has made no changes to the rule based on this comment.

Technical Feasibility

Devon and ExxonMobil agreed that the 0.5 g/hp-hr NO _X emission specification is obtainable on rich-burn engines, but commented that NO _X emission reductions from lean-burn gas-fired engines was very costly and that there are currently no known lean-burn engines that consistently meet the proposed 0.5 g/hp-hr standard. Devon and ExxonMobil indicated that the current technical limitation for lean-burn engines is 0.7 g/hp-hr NO _X . In addition, the commenters indicated that the rule would result in all lean-burn engines being replaced with less efficient fuel rich-burn engines because add-on NO _X controls, such as SCR, for lean-burn engines are uneconomical and EGR is not proven, or if applied would reduce fuel efficiency. The commenters proposed that lean-burn engines in Collin, Dallas, Denton, and Tarrant Counties be required to meet 0.7 g/hp-hr, other existing lean-burn engines installed prior to June 1, 2007, should be limited to 2.0 g/hp-hr, and all new lean-burn engines should be required to meet 0.7 g/hp-hr.

The commission disagrees with the commenters' assertion that 0.70 g/hp-hr is the current technical limitation of lean-burn engines. The commission has identified retrofit options for owners or operators of lean-burn engines to meet the 0.50 g/hp-hr emission standard. In addition, as indicated elsewhere in this preamble, a review of two major engine manufacturer's specifications and emission rates for available lean-burn engines indicates that 0.50 g/hp-hr is achievable on a range of lean-burn engine models and size ranges. The commenters' proposed alternative emission specifications would result in a significant loss of NO _X emission reductions necessary for the Dallas-Fort Worth eight-hour ozone attainment demonstration. However, as discussed elsewhere in this preamble, the commission has adopted NO_X emission specifications for lean-burn gas-fired engines at major sources of 0.70 g/hp-hr for existing lean-burn engines placed into service prior to June 1, 2007, and 0.50 g/hp-hr for lean-burn gas-fired engines installed, modified, relocated, or reconstructed on or after June 1, 2007. The overall difference in total reductions between the proposed 0.50 g/hp-hr emission specification and the adopted 0.70 g/hp-hr emission specification is only approximately 0.1 tpd for the minor source rule.

EMA recommended that the commission adopt different emissions standards for certain engine applications. Some stationary engine applications must meet unique operating requirements that affect the level of emission reductions that can be achieved in those applications. EMA further stated the current commission proposed emission standards use a one-size-fits-all approach and is not technically or economically feasible at the emissions levels proposed by the commission.

The commission has already provided alternative emission specifications and certain exemptions for engines based on size, fuel type, and application that the commission determined to be warranted. The commenter has not provided any information regarding the type of engine or service of concern. Therefore, the commission has no basis to determine if any additional exemptions or alternative specifications are necessary. The commission made no changes to the rule based on this comment.

EMA stated the proposed emission standard of 0.6 g/hp-hr for landfill gas-fired engines is not technically feasible. EMA recommends that the NOx standard for landfill gas engines be set at 3.0 g/hp-hr and this is an achievable emissions standard for such applications and is in-line with the proposed standard in EPA's NSPS regulation. EMA further recommended that the emissions standard also be applicable to digester gas engines and other applications where needed.

The commission has identified a number of landfill gas-fired engines in the Houston-Galveston-Brazoria area that have been able to achieve the 0.6 g/hp-hr standard. Therefore, the commission disagrees with the commenter's assertion that 0.6 g/hp-hr standard is not technically feasible for landfill gas-fired engines. No change has been made to the rule based on this comment; however, as a result of the change to the lean-burn gas-fired emission specifications discussed elsewhere in this preamble, existing lean-burn gas-fired engines subject to the minor source rule will be limited to 0.70 g/hp-hr.

EMA recommended the commission consider establishing different emission standards for existing and new engines as was done for diesel engines in the proposed rule. Another option recommended by the commenter is to consider exempting existing engines from the new standards. EMA recommended that the commission adopt a less stringent emission standard for natural gas fired engines. The commission should adopt the emission standards for spark-ignited engines as proposed by EPA in the NSPS. Adoption of this approach would result in a NO _X emission standard of 2.0 g/hp-hr beginning with new engines in July 2007 with a step down to 1.0 g/hp-hr by July 2010. EMA asserted that the NSPS regulations for both compression-ignition and spark-ignited engines will result in significant reductions throughout Texas.

The commission disagrees with EMA's recommendations that the state should adopt NSPS standards. EPA's NSPS standards are nation-wide standards designed for attainment and nonattainment areas alike. The proposed EPA NSPS standards for engines are not sufficient to achieve the necessary reductions from stationary engines in the Dallas-Fort Worth eight-hour ozone nonattainment area. Furthermore, the commenters' suggestion to exempt existing engines from the rule would result in no reductions from this category of sources. As explained elsewhere in this preamble, the commission has determined that NO _X reductions from stationary gas-fired engines are necessary for the region to make progress toward the eight-hour ozone NAAQS. While the commission agrees that EPA's NSPS regulation will ultimately result in reductions, these reductions will not occur in time to benefit the Dallas-Fort Worth eight-hour ozone nonattainment area by the attainment date. No change has been made to the rule based on this comment. Based on other comments received, the commission has adopted a tiered emission specification approach for lean-burn engines based on date of installation, modification, reconstruction, or relocation.

EMA recommended the commission adopt different CO levels that are based on engine application, size, and date of installation. For landfill gas and digester gas engines, EMA recommended a CO emission standard of 5.0 g/hp-hr. EMA recommended a CO emission standard of 4.0 g/hp-hr for all other gaseous-fueled engines, and for diesel engines, EMA urged the commission to harmonize with the NSPS standards.

The CO standards in §117.2110 have been demonstrated as achievable on numerous engines in the Beaumont-Port Arthur, Dallas-Fort Worth, and Houston-Galveston-Brazoria ozone nonattainment areas. The commission considers the 3.0 g/hp-hr to be appropriate for most engines; however, the rule already provides for alternative CO emission specifications under §117.2125 if an owner or operator cannot achieve the CO emission specification in the rule. No change has been made to the rule based on this comment.

J-W Power and CSI expressed concerns regarding lean-burn and rich-burn gas-fired engines within the Dallas-Fort Worth eight-hour ozone nonattainment area. J-W Power added that meeting the NO _X emission specifications in the Dallas-Fort Worth eight-hour ozone nonattainment area would require removing all of J-W Power's lean-burn engines prior to the compliance date and cost $3.5 million in relocation and installation fees. J-W Power recommended that lean-burn engines at minor sources be required to meet the emission standards proposed by J-W Power for the East Texas Combustion rule. EOG and CSI commented that the cost of controlling lean-burn engines is excessive and added that others have estimated the cost at $13,000 to $20,000 per ton of NO _X reduction. EOG stated this cost cannot be justified when compared to the anticipated small reduction of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area based on these controls. CSI requested the commission delay the compliance date for rich-burn engines until the spring of 2009.

While the commission acknowledges that lean-burn engines are more expensive to control than rich-burn engines, lean-burn engines at minor sources account for approximately 1.8 tpd NO _X reductions. NO_X reductions from lean-burn stationary gas-fired engines at both major and minor sources in the nonattainment area are necessary to help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward the NAAQS. However, as discussed elsewhere in this preamble, the commission has revised the NO _X emission specification for existing lean-burn gas-fired engines to 0.70 g/hp-hr. Lean-burn gas-fired engines installed, modified, relocated, or reconstructed after June 1, 2007, will be required to meet 0.50 g/hp-hr NO _X . In addition, the commission has determined that additional time may be necessary for owners or operators of lean-burn engines at minor sources to comply with the rules. Therefore, the compliance date for lean-burn engines in §117.9210 has been adjusted to March 1, 2010. Regarding CSI's request to delay the compliance date for rich-burn engines, the March 1, 2009, compliance date provides sufficient time for owners or operators to comply with the requirements of the rule. Therefore, the commission declines to make the suggested change to the compliance date for rich-burn engines.

Monitoring, Testing, Recordkeeping, and Reporting

EMA recommended the requirement for engines using NSCR to be equipped with an automatic AFR be removed from the proposed rule. EMA states there may be other methods, approaches, and options that will better control emissions that can be used in place of an AFR.

The requirement to install AFR controllers for engines equipped with NSCR is necessary to ensure proper operation of the NSCR. While there may be other potential methods, the commenter has not identified these methods. Therefore, the commission has no basis to consider the alternative methods for inclusion in the rule. The commission does not consider it appropriate to remove the AFR requirement from the rule without a suitable replacement or alternative. No change has been made to the rule based on this comment.

Devon and ExxonMobil commented that §117.2135(a) requires totalizing fuel flow meters on IC engines and turbines and that such fuel flow meters were not necessary and should not be required.

The totalizing fuel flow meter requirement in new §117.2135(a) is only applicable to boilers and process heaters claimed exempt under the low fuel usage exemption in new §117.2103(b). Engines and turbines were not required to install fuel meters under the proposed rule; however, as discussed elsewhere in this preamble, the commission has exempted boilers and process heaters from the adopted rule. Therefore, the fuel metering requirement in §117.2135(a) is no longer necessary and is excluded from the adopted rule.

SUBCHAPTER E: MULTI-REGION COMBUSTION CONTROL

DIVISION 2: CEMENT KILNS

General

EPA commented that the current EPA-approved Texas SIP has an emission factor of 2.8 tons per day for dry preheater-precalciner or precalciner type kilns. EPA requested the commission explain why the 2.84 tons per day NO _X emission factor used in §117.3123(b) should not be perceived as a SIP relaxation.

The 2.8 number referenced by EPA for dry preheater-precalciner or precalciner type kilns in the current EPA-approved Texas SIP, found in existing §117.265(a)(4) and adopted in new §117.3110(a)(4), is in units of pounds per ton of clinker, not tons per day. The actual tons per day of NO _X emissions resulting from 2.8 pounds per ton of clinker would depend on the production of the unit, but the production rates for the three dry preheater-precalciner or precalciner type kilns are such that the tons per day emission rates range from 3.4 to 5.5 tons per day, based on 2003 emissions inventory data. Because the emission factor of 2.84 tons per day used in §117.3123(b) would result in reductions from this range of actual emission rates, the emission factor would not be a SIP relaxation. No changes were made to the rule based on this comment.

EPA suggested replacing the word "and" with "or" between §117.3140 and §117.3142 referenced in §117.3145(a) and between the section titles in brackets following the references.

The commission agrees with EPA's suggested change that §117.3145(a) should be §117.3140 or §117.3142 and has made the suggested change. However, the commission disagrees with the suggested change regarding listing of section titles. Texas Register formatting requires the use of "and" in the list of section title references.

EPA commented that §117.3145(c)(1)(C) requires records of NO_X emission rate on a basis of a rolling 30-day average and a rolling 90-day average. EPA requested an explanation why §117.3145(c)(1)(C) does not require records of NO _X emission rate on a daily basis.

Holcim, PCA, and TXI commented that the proposed rule is a major environmental rule, as stated in the preamble, subject to the APA of Texas Government Code, §2001.0225, and that Texas law requires heightened scrutiny for the promulgation of major environmental rules. Holcim and PCA commented that the commission provided no support that the rules seek to implement a specific standard set by federal law, that the rules do not implement an express requirement of state law, and the commission has broad discretion to determine the measures necessary for achieving compliance with the NAAQS. Holcim, PCA, and TXI contend that the commission has failed to quantify the ozone benefits expected by imposing controls on cement kilns, failed to quantify compliance costs to the cement industry, and failed to compare those costs to costs and effectiveness of alternative controls such as more stringent emission reductions from automobiles. Holcim, PCA, and TXI commented that §2001.0225 requires inclusion of a regulatory impact analysis to identify the problem the rule is intended to address, determine whether the rule is necessary, and describe costs and benefits in as quantitative a manner as possible.

The commission disagrees with the comments, with two exceptions. First, the commission agrees that the rules regarding control of emissions from cement kilns meet the definition of a major environmental rule. Second, the commission agrees that it has discretion to determine the measures necessary for achieving compliance with the NAAQS.

As noted in the DRAFT REGULATORY IMPACT ANALYSIS portion of the proposal, Texas law requires a regulatory impact analysis for major environmental rules only if certain criteria are met. The commission's final analysis regarding the applicability of the regulatory impact analysis requirement can be found in the FINAL REGULATORY IMPACT ANALYSIS section of this preamble. Both the draft and final analyses concluded that although the rules applicable to cement kilns meet the definition of a major environmental rule, the rules do not meet any of criteria that require the regulatory analysis required by Texas Government Code, §2001.0225(b).

The commission is charged with protecting air quality within the state and to design and submit a plan to the federal government to achieve attainment and maintenance of the federally mandated NAAQS, specific standards set by federal law. The commission's discretion is inherently bound by the requirement to meet the NAAQS. As documented elsewhere in this preamble and the revised Dallas-Fort Worth eight-hour attainment demonstration SIP (as well as the preamble for the proposed rules), the emissions reductions resulting from these rules are necessary to make progress toward the attainment and maintenance of the eight-hour ozone NAAQS throughout the state. The commission has adopted numerous measures in the past and with this attainment demonstration that are designed to reduce emissions from sources that individually may not appear to provide significant benefits toward progress for the attainment of the NAAQS, but the overall reductions will make progress toward attainment. The rules do not exceed a standard set by federal law, since they are designed to meet, not exceed the relevant standard set by federal law - the NAAQS. Rules adopted to meet these federal standards do not trigger the statutory language in Texas Government Code, §2001.0225(a) requiring a regulatory impact analysis. The Third District Court of Appeals upheld this interpretation in Brazoria County v. Texas Comm'n on Envtl. Quality , 128 S.W. 3d 728 (Tex. App.- Austin 2004, no writ).

Although no regulatory analysis is required, the information that the commenters apparently seek was included in the proposed rulemaking and is also discussed in this rule adoption. In addition to the determination of whether rules meet the definition of major environmental rule, this regulatory analysis statute requires that the commission incorporate certain information in the notice of the proposed rules. The commission complied with this requirement. (See the FISCAL NOTE: COST TO STATE AND LOCAL GOVERNMENT section of the proposal preamble published in the December 29, 2006, issue of the Texas Register (31 TexReg 10538, 10596 - 10602) and the DRAFT REGULATORY IMPACT ANALYSIS section of the proposal preamble (31 TexReg 10538, 10602-10605).) These portions of the proposal discuss the benefits anticipated from adoption and implementation of the rules, which is the reduction of NO _X emissions, which are precursors to ozone formation, in the Dallas-Fort Worth eight-hour ozone nonattainment area. Lowering the level of ozone would benefit the public by enhancing the protection of public health and the environment. The costs for the regulated community associated with the rules applicable to cement kilns were provided. Additional information regarding the basis for the selection of the controls, which included data and methodology used in the commission's selection of a single method of compliance, and therefore forming the basis of the costs was also included in the preamble. The commission relied primarily upon the "Assessment of NO _X Emissions Reduction Strategies for Cement Kilns--Ellis County: Final Report," as described elsewhere in the proposal preamble, which contained cost data provided by Holcim, PCA, and other cement kilns, as well as other data. The commenters provided no additional quantitative cost data for the commission to analyze. Further, the costs and evaluation of control options are discussed in a quantitative manner. The adoption of a source cap instead of requiring specific control technology provides maximum compliance flexibility to owners and operators and achieves a greater amount of greater reductions.

The proposal also identified costs to governmental entities and the public. The use of various subheadings throughout the preamble by major topic for the rulemaking provided information in a manner that a reasonable person reading the analysis would be able to identify the impacts of the proposed rules. Finally, the notice provided the opportunity for public comment.

While the commission has discretion in determining which set of programs and controls are needed to meet the federal standard, the commission does not have authority to implement certain measures. For example, the commission is federally preempted by the FCAA from setting emissions standards for mobile vehicles. Alternative control measures were evaluated as part of the commission's assessment of Reasonably Available Control Measures (RACM) for the Dallas-Fort Worth attainment demonstration SIP, which can be found in Chapter 4 and Appendix I, available on the commission's Web site at: http://www.tceq.state.tx.us/nav/eq/sip.html.

PCA and TXI contended that the commission's photochemical modeling shows NO _X reductions from Ellis County cement plants will not have measurable impact on critical monitors in the Dallas-Fort Worth eight-hour ozone nonattainment area and that neither "high control" nor "low control" scenarios show the Dallas-Fort Worth eight-hour ozone nonattainment area attaining ozone standards. The commenter submitted a memo from Trinity Consultants that it claims confirms that reductions offered by cement manufacturers in other comments to this rule proposal will not result in measurable impacts on Frisco or Denton monitors, the critical monitors in the Dallas-Fort Worth eight-hour ozone nonattainment area. Additionally, PCA and TXI commented that because mobile source emissions contribute at least 70% of the NO _X emissions and 50% of the VOC emissions in the Dallas-Fort Worth area, it is clear that any real improvement in the Dallas-Fort Worth ozone situation will be the result of reductions in emissions in the mobile source category, not cement kiln NO _X emissions.

The commission disagrees with the commenter's assertion that NO _X reductions from the cement kilns in Ellis County will not help the Dallas-Fort Worth eight-hour ozone nonattainment area make progress toward the NAAQS. The Dallas-Fort Worth eight-hour ozone nonattainment area must demonstrate attainment with NAAQS at all monitor locations, not just the Frisco and Denton monitors. Initial sensitivity modeling runs indicated that NO_X reductions from the cement kilns will benefit the western portion of the nonattainment area, especially the Fort Worth Northwest (C13) monitor which is near the population centers in Tarrant County. The initial "low control" kiln modeling run indicated a 0.50 parts per billion (ppb) reduction in ozone at the C13 monitoring site. In addition, recent modeling sensitivity runs indicate that modeled ozone levels at this and some other locations in the western portion of the nonattainment area will be close to the eight-hour ozone NAAQS. The 10.4 tpd reductions anticipated from cement kilns under the adopted rule represent approximately half of the total point source NO _X reductions in the Dallas-Fort Worth eight-hour ozone nonattainment area. Additional information concerning photochemical modeling conducted for the DFW area can be found in Chapters 2 and 3 of the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP. Regarding the comment about mobile source emissions, the commission agrees that reductions from mobile sources are necessary for the Dallas-Fort Worth eight-hour ozone nonattainment area to make progress toward attaining the NAAQS, but the commission disagrees that NO _X reductions from cement kilns will not improve the ozone levels in the nonattainment area. In addition, the commission has limited authority to regulate motor vehicles due to federal preemption. No changes have been made to the rule based on this comment.

Downwinders opposed the proposed Dallas-Fort Worth eight-hour ozone attainment SIP because it violated a binding legal agreement because it will not be submitted by June 15, 2007, will not achieve attainment as expeditiously as practicable, and did not consider all reasonable measures.

The commission has complied with the settlement agreement and intends to submit the Dallas-Fort Worth eight-hour ozone SIP to EPA by June 15, 2007. The Dallas-Fort Worth eight-hour ozone attainment demonstration SIP meets all legal requirements of the FCAA. The compliance schedule for the cement kilns under the adopted rule will achieve significant NO _X reductions by the attainment date, which is as expeditious as practicable. All technologically and economically reasonable measures were considered for the Dallas-Fort Worth eight-hour ozone attainment demonstration as discussed elsewhere in this preamble and in the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP. The SIP and the adopted rules in Chapter 117 include those measures that will reduce NO _X emissions by the attainment date to help the nonattainment area make progress toward the eight-hour ozone NAAQS. No changes have been made to the rule based on this comment.

NCTCOG requested the commission clarify how the cement kiln source cap is determined when the range of acceptable reductions is 35- 50% and whether the strategy reflects a conservative 35% reduction.

The source cap approach proposed by the commission was based on the cement kiln study projected ton per day emission rates, which were based on the estimated reductions for wet and dry kilns. The strategy does not reflect a conservative 35% reduction, but a 35- 50% reduction of the tpd emission rates from a site depending on the type of kilns located at that site. For a site with all wet kilns, the source cap should reflect approximately 35% reduction. As discussed elsewhere in this preamble, the commission has revised the calculation method for determining the source caps.

BSA, Public Citizen, and SEED Coalition commented that the commission should expand the proposed cement kiln control strategies beyond the Dallas-Fort Worth eight-hour ozone nonattainment area and added that reductions from those sources are needed to get the area closer to cleaner air.

The expansion of either proposed or currently effective Chapter 117 rules for cement kilns or the application of other new control strategies to new persons would not allow for appropriate public review and comment. No changes have been made to the rule based on this comment.

Technical Feasibility/Controls

Ash Grove stated that preliminary SNCR data on one of its kilns suggest §117.3123(b) can be met and that SNCR is the only reasonable option for NO _X control on its kilns.

The commission appreciates Ash Grove's comments and efforts in evaluating SNCR technology for the cement kilns located at Ash Grove's facility. The commission expects these reductions will contribute to progress toward attainment of the NAAQS in the Dallas-Fort Worth eight-hour ozone nonattainment area. As discussed elsewhere in this preamble, the source cap approach specified by these rules allows companies to determine the most appropriate control for their operations.

PCA and TXI supported the commission approach to require appropriate control technology for Ellis County cement kilns. Holcim supported the commission's efforts to achieve attainment of the ozone NAAQS in the Dallas-Fort Worth eight-hour ozone nonattainment area and lower NO _X emission levels and the determination to use SNCR technology for NO _X control in cement plants. However, Holcim, PCA, and TXI asserted that the technology is inconsistent with the proposed source cap and imposes unrealistic restrictions for at least two Ellis County plants. Holcim, PCA, and TXI also contended that cost estimates in the preamble are inaccurate if technologies other than SNCR are necessary for compliance. PCA and TXI asserted that the proposed source cap ignores many important and critical differences among kilns. PCA and TXI stated that Ellis County kilns have been proactive in reducing emissions, while doubling production since 1996, that one kiln is already using BACT and achieving 30% NO _X reductions by not operating two kilns. PCA and TXI stated that one plant is already using SNCR, while others are evaluating it. PCA and TXI also commented that one plant has achieved 43% NO _X reductions using low NO _X burners, mid-kiln firing, and other approaches, and is testing SNCR. Holcim, PCA, and TXI stated that 50% reductions are not achievable with SNCR at Holcim based on test results and that the study report inaccurately estimates the level of reductions achievable with SNCR on some Midlothian kilns, and that actual performance varies widely between precalciner kilns. Holcim also commented that even if the level of reductions estimated by the study were reachable that level may not be attainable on a consistent basis. The commenters maintained that one dry kiln at TXI is already permitted as BACT at 1.95 pounds NO _X per ton clinker, identical to new permits at CEMEX New Braunfels and TXI Hunter, and that the proposed rules would imply an emissions level of 1.27 pounds per ton at that kiln. Holcim, PCA, and TXI also commented that the proposed source cap arbitrarily excludes emissions from kilns that began operating after 2000 and that the explanation of the source cap in the preamble is inconsistent with SNCR because it will require reductions that exceed those achievable with SNCR.

The commission appreciates the detailed and informed comments as well as the cement industry's efforts to reduce NO _X emissions in the Dallas-Fort Worth eight-hour ozone nonattainment area. The source cap and proposed rule do not specify a particular control technology but provide sufficient flexibility for owners and operators to comply using the most effective combination of controls, operating practices, and process modifications. The commission acknowledges that SNCR is already being used at one plant and tested at the other two plants. As discussed elsewhere in this preamble, the commission has revised the source cap calculation to address some of the concerns raised by the commenter. Regarding exclusion of kilns in computing the source cap, as discussed elsewhere in this preamble, the commission has revised the source cap calculation method to be based on production rates for the calendar years 2003, 2004, and 2005. All ten cement kilns currently operated in Ellis County were active in those years.

Holcim stated that the source cap requires a 50% NO _X reduction from historical emission levels at its site, but does not account for permitted production increases. The commenter stated that achieving the source cap would require them to meet 1.55 pound NO _X per ton clinker, substantially lower than BACT for new kilns (1.95 lb/ton) and instead proposed a source cap of 8.5 tons per day based on 2006 ozone season operating data.

The commission disagrees with the commenters proposed cap of 8.5 tons per day. Based on data submitted to the commission's Industrial Emissions Assessment Section, the commenter's production rates have not substantially increased since 2001; however, the emissions inventory data for the commenter's kilns indicate an upward trend in NO _X emissions over the same time. Therefore, the commenter's upward trend in NO _X emissions is not the result of increased production rate. The source cap approach adopted in the rulemaking uses actual production rate data from 2003 to 2005, plus one standard deviation of total production at an account, by kiln type (wet or dry), over the same three years, a NO _X emission factor of 1.7 pound per ton of clinker for dry preheater-precalciner or precalciner kilns, and a NO _X emission factor of 3.4 pound per ton of clinker for wet kilns. The addition of one standard deviation to the average production rate used in the equation will account for production variability in the target period and provide for some conservative increases in production by increasing the source caps. The use of one standard deviation will ensure that this increase is applied equitably based on the actual variability in production over the 2003- 2005 period. While the emission factor is lower than the factor the commenter asserts as BACT, the 1.7 pound per ton of clinker has been demonstrated on a dry preheater-precalciner or precalciner kiln in Ellis County without the addition of the SNCR or other controls considered as part of the cement kiln study. Therefore, the commission contends that the source cap under the adopted rule is appropriate for the commenter's site which includes dry preheater-precalciner or precalciner kilns. As discussed elsewhere in this preamble, the commission has designed the adopted version of the source cap approach to recognize the best performing kilns for each category while establishing a cap approach that requires feasible and equitable reductions from all three sites in Ellis County, while providing flexibility for compliance options. The source cap proposed by the commenter would reward the site for having inefficient performing preheater-precalciner or precalciner kilns. The commission asserts that efficient processes should be encouraged whenever possible. The commission also recognizes that some cement kilns in Ellis County have substantially reduced NO _X reductions and become more efficient than other kilns located in the area.

TXI supported the requirement for appropriate technology to reduce NO_X from Ellis County cement kilns; however, TXI added that an equitable and consistent approach is vital. The commenter proposed an approach that would apply different emission rate limits for different kiln types. TXI asserted that a source cap approach may restrict economic development in the Dallas-Fort Worth eight-hour ozone nonattainment area by restricting capacity expansions needed to meet increased demand, and that the proposed source cap will have inequitable impact because computation of the cap excludes units operable after 2000, penalizing companies that have already made significant NO _X reductions. Further, the commenter asserted that the source cap equation contains errors in assuming emissions reductions of 30% at each wet kiln, ignores production increases permitted in 2005, and requires an infeasible control approach. The commenter further asserted that the proposed source cap requires a 47% overall reduction in addition to reductions already achieved, implying an emission limit of 1.45 pounds NO _X per ton clinker (lb/ton) at its dry kiln, which is lower than a recent BACT level of 1.95 lb/ton, or a 35% reduction. TXI stated that further NO _X reductions on the dry kiln, beyond 35% already achieved, should not be required, are arbitrary, and no dry kiln has ever achieved 35% reduction from 1.95 lb/ton or 1.27 lb/ton. The commenter stated that the rule should account for recently permitted production increases, which could be accomplished by multiplying the existing source cap (21,119 pounds NO _X per day) by the ratio of the authorized production increase (up 0.6 million tons per year from 2.2 million tons), then multiplying this by 0.65 (thereby reducing it by 35%). The commenter stated that 30-35% reductions should be achievable on its four wet kilns using SNCR, with ammonia "slip" occurring as reductions approach 35%.

The commission maintains that the rule does not specify a particular control technology that must be used to meet the source cap, but is designed to provide flexibility to owners and operators to control emissions in the manner most appropriate to their circumstances. The commission disagrees with the commenter's suggestion of different emission rate limits for different kiln types. There are significant differences in the pound per ton of clinker NO _X emission rates from the same type kilns in Ellis County. These differences complicate establishing a technically feasible and equitable emission specification for each type of kiln in Ellis County. For example, an emission specification based on a 35% reduction from the best performing wet kilns in Ellis County could result in the owner or operator of wet kilns at another site being forced to either shut down the wet kilns or install advanced and potentially unproven controls. Alternatively, if the emission specification is based on units with the higher emission rate, cleaner kilns would already be achieving this rate and would not be required to make reductions. While the commission acknowledges that cleaner cement kilns should be recognized under the rule, achievable reductions must be obtained from all the cement kiln sites in Ellis County to help the Dallas-Fort Worth eight-hour ozone nonattainment area attain the NAAQS. Under a source cap approach, differences between kilns of the same type and of different type can be balanced to establish an equitable and feasible cap that requires all sites to achieve reasonable reductions. The source cap approach will provide the commenter greater flexibility for compliance than the suggested ESAD approach because the commenter has both types of cement kilns at the TXI facility in Ellis County. However, the commission does agree that the proposed source cap calculation methodology may have inadvertently created an inequitable distribution of emissions for some of the sites. The commission has reevaluated the cap approach and determined that a production rate-based source cap would be more equitable. As discussed elsewhere in this preamble, the adopted source cap calculation uses average annual production rates from 2003 through 2005, plus one standard deviation of total production at an account, by kiln type (wet or dry), over the same three years, and a NO _X emission factor in pounds per ton of clinker based on the type of kiln. As discussed elsewhere in this preamble, the addition of one standard deviation to the average production rate used in the equation will account for production variability in the target period. The commission contends that the adopted source cap approach is equitable and recognizes that some cement kilns in Ellis County have made substantial reductions in NO _X emissions, both on a ton per day and a pound per ton of clinker basis.

Ash Grove, Holcim, PCA, and TXI recommended the source cap only apply during ozone season (generally considered to be May 1 - October 31) because most exceedances have been measured during this period, it would be consistent with recent prevention of significant deterioration (PSD) permitting decisions, and operation of SNCR during the colder months increases the risk of ammonia slip. Holcim, PCA, and TXI suggested that the cement kilns would continue to comply with current requirements for the one-hour SIP during non-ozone season.

The commission partially agrees with the commenters. Applying the new source cap control requirements to ozone season only would limit some of the potential effects that may result from SNCR controls, such as increased particulate emissions and opacity. Therefore, the commission has revised the rule to only require compliance with the source cap under §117.3123 for March 1 through October 31 for each calendar year, ozone season for the Dallas-Fort Worth eight-hour ozone nonattainment area. As suggested by the commenters, cement kilns currently subject to the requirements of §117.3110 or §117.3120 would remain subject to those requirements during non-ozone season months, November through February of the following calendar year. The exemption in §117.3103(c) has been revised to indicate that Portland cement kilns that are subject to §117.3123 are exempt from §117.3110 and §117.3120 from March 1 through October 31 of each calendar year.

City of Fort Worth commented that the commission should require the local cement kilns to unilaterally install and operate selective non-catalytic reduction technology to reduce NO _X emissions. BSA, City of City of Fort Worth, NCTCOG, Public Citizen, and SEED Coalition expressed support for the NTCASC resolution recommending the commission require the kiln owners to install SNCR technology on all kilns in Ellis County.

The commission disagrees with the commenters and the NTCASC resolution. The commission's preferred approach to achieving reductions is to establish emission standards and allow the regulated entity the flexibility to choose the most appropriate control technology available.

When possible, the commission avoids specifying the exact control technology to achieve the desired reductions for a particular control strategy. The commission prefers to specify an achievable emission limitation and allow the regulated company to choose the most applicable and best control technology for their specific situation. Mandating specific control technologies could create a disincentive to investigate newer technologies in the future that might result in additional reductions. The source cap approach proposed by the commission allows sources to optimize controls and possibly take advantage of other measures to reduce NO _X emissions. In addition, as discussed elsewhere in this preamble, the intent of the source cap approach is to establish a maximum cap on the total NO _X emissions from cement kilns at each account. The provisions of the new rule will prohibit expanding the source cap based on new units installed after calendar year 2005 or by increasing production rates in the future. Before an increase in NO _X emissions from a change in operation from one unit or the installation of a new kiln could occur, a corresponding decrease in NO _X emissions will be required from another existing unit, unless the account's NO _X emissions were already sufficiently below the source cap to offset the increase.

PCA and TXI submitted documents to support the assertion that neither SCR nor LoTOx constitute RACT for cement kilns. PCA and TXI asserted that neither technology could be pilot tested and in place by the March 1, 2009, deadline. PCA and TXI commented that no other agency, including EPA, has required these technologies as BACT, Lowest Achievable Emission Rate (LAER), or RACT, and that speculation that SCR could achieve 80-85% reductions, when the only known unit operating is achieving only 50% reductions, is inappropriate. PCA and TXI also asserted that according to its own comprehensive analysis, other technologies, namely SCR and LoTOx, are unproven, unreliable, and not cost-effective. Holcim, PCA, and TXI asserted that neither SCR nor LoTOx constitute RACT, BACT, nor LAER, that neither is required by EPA, and that neither should be considered for Ellis County cement kilns.

Under the adopted source cap approach, neither SCR nor LoTOx should be required to comply with the source cap and the SNCR controls should be sufficient to achieve compliance, provided the source's kilns are well controlled through previous controls installed and best practices to minimize emissions. Further discussion concerning the commission's determination regarding SCR and LoTOx controls on the portland cement kilns in Ellis County is provided elsewhere in this preamble and in the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP.

Public Citizen commented that the plan failed to reduce emissions from kilns to a safe level.

As discussed elsewhere in this preamble and in the Dallas-Fort Worth eight-hour ozone attainment SIP, the rules are stringent while providing sufficient flexibility to ensure controls are in place and operating in time to make progress toward attainment of the eight-hour ozone standard as required by Federal law. Further discussion concerning the health effects issues in the Dallas-Fort Worth eight-hour ozone nonattainment area is contained in the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP. No change has been made to the rule based on this comment.

BSA, Public Citizen, and SEED Coalition stated that the plan could be much better regarding cement kilns and the commission did not provide sufficiently detailed analysis to justify the choice of 35-50% NO _X control rather than 80-85% control from Midlothian cement plants or at a minimum, over 50%. The commenters also asserted that the commission should provide a more adequate explanation for the choice of the proposed source cap besides the "weight of evidence." The commenters further commented that the commission should provide a cost per ton analysis for the 80-85% control level to enable comparison of the two control levels. The commenters suggested that the commission extend the proposed rules to cement kilns outside the nine-county nonattainment area, adding that reductions from those sources are needed to get the area closer to cleaner air.

The source cap adopted with this rulemaking requires substantial reductions from all kilns in Ellis County and these reductions will be achieved by the attainment date for the eight-hour ozone standard. The commission disagrees that the suggested 80-85% control level could be implemented by the attainment date. As discussed elsewhere in this preamble and the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP, the commission considered all potentially reasonably available control measures to develop a plan that is fully compliant with all federal requirements. Cost per ton analysis on the 80-85% control level is included in the cement kiln study; however, the commission's decision to require a control level of 35-50% is based on technical feasibility rather than cost. Regarding the commenter's suggestion to apply the rules to more counties, the expansion of either proposed or currently effective Chapter 117 rules for these sources or the application of other new control strategies to new persons would not allow for appropriate public review and comment. No change has been made to the rule based on these comments.

One individual agreed the source cap approach for cement kilns is fair and flexible, but strongly encouraged requiring 80% reductions and modification of the cap to achieve an additional 10 tons of NO _X reductions. However, the commenter disagreed that SCR is not as well established for control of cement kilns as SNCR, and asserted that RACT should govern control selection. The commenter noted that EPA guidance states RACT need not be available "off-the-shelf," but should be stringent, even technology forcing, considering technological and economic feasibility and that the commission should adopt stringent, technology forcing, tough and restrictive standards, even if this requires significant economic sacrifices. The commenter included a report on SCR performance at a dry kiln in Italy, a copy of an electronic mail mentioning two vendor quotes for 90-95% NO _X reductions with SCR for a California facility, and a letter from a LoTOx vendor proposing 90% NO _X reduction. The commenter also recommended establishing a single description for applicability of the cement kiln source cap, rather than multiple terms "installed," "in operation," and "operational." Finally, the commenter recommended applying a single emission level (K factor) for both wet and dry kilns in the computation of the source cap for each site, corresponding to an overall 80% reduction in NO _X emissions at each account, as an incentive to retire older, higher emitting kilns.

The commission appreciates the detailed and informed comments, but disagrees that SCR is well established and is RACT for the cement kilns located in Ellis County. The commission has no information indicating that SCR has been proposed or tested on any wet process cement kiln. Seven of ten kilns in Ellis County are wet kilns. Very few SCR systems have been tested on dry process kilns, none of which has been attempted in the United States. The commission is familiar with the report on the Italian kiln, which is a dry process kiln. The information regarding the kiln in California mentions vendor quotes but not the amounts, nor target emissions rates, nor type of kiln. This information does note that neither of the vendors has ever retrofitted SCR to a cement kiln. The commission has contacted the LoTOx vendor, and while the vendor asserts the LoTOx system could be applied to cement kilns, LoTOx has never been installed on cement kilns. The vendor also stated that the system would likely cost more than other options and would require more time to construct and optimize. Regarding establishing a single term to refer to an operational kiln, applying a single emission factor for all types of kilns in the source cap equation would not be appropriate. As discussed elsewhere in this preamble, there are significant differences between the two types of cement kilns in Ellis County. Prescribing a single emission factor, either on a ton per day or pound per ton of clinker basis, would not be equitable and could make compliance with the rule infeasible for owners or operators of certain kilns. The commission does not intend to force owners or operators to shut down kilns to comply with the rule. Additional information regarding the commission's analysis of control technologies for cement kilns is available elsewhere in this preamble and in the Dallas-Fort Worth attainment demonstration SIP. No changes have been made to the rule based on these comments.

Representative Burnam commented that the proposed plan continued to let the Midlothian cement kilns off the hook and that the plan did not demand advanced controls on these cement kilns. GFWSC and many individuals stated that the plan is not sufficiently stringent on cement kilns in Ellis County, that these sources should be required to install controls that achieve 80-90% NO _X reductions, and that technology to achieve this is cost-effective and readily available. Some stated that the current plan was unacceptable and others requested the commission to require cement plants to cut emissions as much as possible, but more than the proposed 35-40%. Commenters stated that effective control technologies exist but the cement industry does not want to install the best pollution control. One individual stated that failure to control these emissions was criminal and that the commission favored an industry-backed plan. IEA commented that the cement kilns need to reduce as much as possible, since they are one of the biggest sources, at least in Tarrant County.

The commission disagrees that technology to eliminate 80-90% of NO_X emissions from wet process cement kilns is "available." The cement kiln study described these technologies, SCR and LoTOx, as "transferable" to wet kilns from other similar processes, an assessment that entails lengthy and costly research, development and testing before full deployment, if warranted, could be considered. Further, neither technology has been attempted on wet process kilns. Seven of ten kilns in Ellis County are wet process kilns. Even on dry kilns, SCR has only been used on kilns that are dissimilar to those in Ellis County. The commission has not proposed to require a specific technology, but instead has carefully evaluated the findings of the cement kiln study to develop a plan that provides flexibility for kiln operators to comply in the most cost-effective, technically sound, and expeditious manner possible. The commission is aware of its responsibilities under the FCAA and intends to submit a SIP that satisfies all requirements of the law. Finally, the commission has received substantial adverse comment on the plan from industry, but has determined that the adopted source cap approach is a flexible and feasible plan to reduce NO _X emissions by the greatest amount possible with available technologies that can be installed and operational by the attainment date.

Downwinders stated that a new Italian plant is achieving the lowest NO_X emissions in the world with SCR technology. In addition, Downwinders asserted that a cement company, the third largest in the world, admitted that SCR is effective, and even uses a case for SCR in documents submitted to Florida. Downwinders added that this cement company says SCR for cement kilns could be proven with a pilot test. Downwinders asserted that the proposed rules arbitrarily select SNCR for NO _X controls on cement kilns, rather than SCR or LoTOx, which the commenter claims are RACT, allowing wet kilns to operate at higher emission rates than dry kilns, whereas SNCR pilot testing at Holcim shows NO _X reductions between 40 and 50%. The commenter disagreed that SCR is not as well established as SNCR for cement kilns.

The commission maintains that the source cap and proposed rule do not specify a particular control technology, but provide sufficient flexibility for owners and operators to comply by the March 1, 2009, compliance date using the most effective combination of controls, operating practices, and process modifications. Further, the adopted source cap and compliance date are feasible while being fair and equitable to all sources.

Regarding SNCR pilot testing at Holcim, reductions of 45-50% were achieved on one kiln, 35% on the other, whereas the proposed rules would require roughly 45-50% reductions for the Holcim site overall. The adopted rules do not require any particular control technology; however, SNCR has proven to be a cost-effective method of achieving substantial NO _X reductions at the Ellis County kilns, whereas SCR has not.

Regarding the Italian kiln, the commission recently became aware of that kiln and disagrees with the commenter's assertion because the kiln in question is a dry kiln. Seven of ten kilns in Ellis County use the wet process, an older technology for producing specialty cements, with inherently higher emissions on a lb/ton of clinker basis. The commission is unaware of any wet kiln in the world that has attempted SCR. In addition, while a pilot test for SCR has been performed on the dry cement kiln in Italy, full-scale SCR has not been installed and the pilot test indicated highly variable results. One dry kiln in Ellis County, using new process designs rather than end-of-pipe controls, has lower emissions (1.38 lb NO _X /ton clinker in 2005) than recent BACT on kilns in Florida and Arizona (1.95 lb/ton) using SNCR. BACT (termed BAT in Europe) in Italy is 2.5 lb/ton clinker. Regarding SCR and LoTOx as RACT, no RACT determination has been made regarding these technologies for cement kilns. Additional information regarding the commission's determination regarding RACT is provided elsewhere in this preamble and in the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP.

Regarding the claim that a cement manufacturer "admitted" that SCR is effective, the commission contacted the Florida Department of Environmental Quality and reviewed the BACT application of the cement company in question, which required the applicant to analyze and compare SNCR and SCR for proposed (dry) Kiln #3. The commission also contacted the applicant directly and learned that the company made no such claim regarding SCR in its application. The applicant did not admit SCR is effective nor did the applicant support its installation at the new kiln in Florida. The applicant indicated in the BACT analysis that before SCR could be considered, a pilot study lasting from one to three years would be necessary. No change has been made to the rule based on these comments.

BSA, ED, Public Citizen, and SEED Coalition disagreed with the commission's determination that the 35- 50% level of control is the most appropriate level of control for cement kilns. BSA, ED, Public Citizen, and SEED Coalition commented the assessment report suggested that available technologies could achieve potentially over 80% reductions. The commenters suggested that the commission should adopt the more stringent level of control or commit to an enforceable process that would lead to field evaluation and subsequent reconsideration of technologies found to achieve greater reductions.

As discussed elsewhere in this preamble and the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP, the commission does not consider SCR to be demonstrated for the cement kilns located in Ellis County. While further testing might support the application of SCR technology to cement kilns, the control level and source cap approach adopted with this rulemaking will reduce emissions in time to help the Dallas-Fort Worth eight-hour ozone nonattainment area meet the NAAQS. No change has been made to the rule based on this comment.

Commissioner Brooks, Judge Whitley, Downwinders, and a number of individuals recommended that cement kilns be required to conduct pilot studies of advanced controls. Commissioner Brooks added that pilot testing of new technology was inexpensive. Judge Whitley commented that the best available technology should be used to reduce emissions from cement kilns. Downwinders stated that only $2 million and 18 months were needed for two pilot studies of advanced technologies that could mean 90% reduction in pollution from plants that are the largest industrial polluters in the area. Downwinders asserted that the state was not interested in doing a pilot study of the advanced controls. Downwinders added that local officials and EPA called for pilot studies of advanced controls to determine if such reductions were possible and that TCEQ was ignoring local input by not incorporating resolutions passed by the NTCASC and recommended to TCEQ.

BSA, City of Fort Worth, NCTCOG, Public Citizen, and SEED Coalition expressed support for the NTCASC resolution recommending the TCEQ require the kiln owners to conduct pilot tests for LoTOx and/or SCR technologies, assuming that the technologies proved to be cost-effective in achieving reductions at or below 1.9 lb/ton of clinker and that they do not materially affect plant operations and/or facilities. BSA, City of Fort Worth, NCTCOG, Public Citizen, and SEED Coalition also expressed support for the NTCASC resolution recommending the commission require the kiln owners to conduct pilot tests for LoTOx and/or SCR technologies no later than September 2007 so that reductions demonstrated from the pilot study can be incorporated into the 2009- 2010 SIP. The NTCASC further recommended that all efforts be made to seek outside funding assistance for the cement industry and that EPA, TCEQ, NCTCOG, cement plant owners, and local environmental groups all be involved in administering and monitoring pilot tests.

The commission contacted the Energy and Environmental Research Center (EERC) at the University of North Dakota regarding pilot testing of SCR and was provided a very preliminary estimate of $500,000 to $700,000 to conduct pilot testing of SCR on one cement kiln. Pilot testing on additional kilns would require substantially more funds. The EERC is the only entity known to the commission to conduct pilot testing of SCR using a mobile test bed. The commission also contacted a vendor of LoTOx and learned that pilot testing of LoTOx would cost about $250,000 for one kiln. The commission agrees that the duration of pilot testing could be approximately 18 months. However, the commission disagrees that the pilot testing of either of these technologies could be performed in time to help the Dallas-Fort Worth eight-hour ozone nonattainment area achieve the NAAQS by the attainment date. After completion of the pilot testing and evaluation of the results, even if the results indicated that SCR or LoTOx were appropriate for the cement kilns in Ellis County, there would not be sufficient time to implement controls prior to the attainment date in 2010. In addition, the pilot study only evaluated catalyst configuration and ammonia injection rates and did not evaluate the ultimate NO _X reduction capability or long-term reliability of SCR. The control strategy adopted with this rulemaking will achieve a reduction of approximately 10.4 tpd in NO _X emissions from the cement kilns in Ellis County by the attainment date. The commission is always interested in advancing emission control technology; however, the goal of this rulemaking is to bring the Dallas-Fort Worth eight-hour ozone nonattainment area into attainment with the eight-hour ozone NAAQS. No change has been made to the rule based on these comments.

Holcim, PCA, and TXI contended that the cement kiln study is inconsistent, inaccurate, incomplete, and unreliable in its assessment of reductions achievable with available technologies, and that it ignores many cost and technical barriers. Many individuals suggested that the commission is ignoring its cement kiln study, and asserted that the cement kiln study found that the cement industry can easily reduce pollution by 80-90% using "advanced controls," meaning SCR or LoTOx, and that these are cost-effective and cheaper than measures currently used. Downwinders added that local officials and EPA called for pilot studies of advanced controls to determine if such reductions were possible, but the state refused to acknowledge the report and lied about its findings. Downwinders mentioned a letter from the governor's office indicating there is no difference between SCR and SNCR and that SNCR was not practical. Downwinders also commented that the Dallas-Fort Worth eight-hour ozone SIP does not implement the conclusions of the Cement Kiln Study.

In 2005, the commission commissioned a study of potential NO _X control technologies for the wet process and dry process cement kilns located in Ellis County, which found that only one, SNCR had been sufficiently tested and found to be effective for both types of kilns in Ellis County. SNCR has been found to reduce NO _X emissions by 35-50% from both wet process and dry process cement kilns. Other technologies studied were found to be "transferable" to wet process cement kilns from other applications, requiring substantial testing and development before full deployment. The commission disagrees with the commenters' assertion that SCR or LoTOx can be easily implemented on the cement kilns in Ellis County and with the assertion that these controls are cheaper than current measures. While the 2006 cement kiln study concluded that SCR and LoTOx were "available" for the three dry kilns, the study authors admitted that the definition of "available" in the study does not correspond to the legal definition of "available" as used by the EPA. While using industry standard terminology, the study authors were clear to state that the definition of "available" for purposes of the study was different from the industry standard. The study states that, for purposes of the study, "available" means a technology that is "commercially available and in use on similar types of cement kilns." SCR and LoTOx are commercially available and are in use on numerous types of industrial equipment. However, neither SCR nor LoTOx has been applied to wet process cement kilns, and only SCR has even been attempted on dry process cement kilns with results that are in question and that cannot necessarily be transferred to the kilns in Ellis County. The few cement kilns known to be using SCR, all located in Europe, are known to have different process designs, different feed materials, and different fuels.

As discussed in the fiscal analysis of the proposal preamble published in the December 29, 2006, issue of the Texas Register (31 TexReg 10601), total capital costs for installation of SNCR for all ten cement kilns in Ellis County are estimated to be approximately $15.3 million to $17.7 million. Annual costs for operation of SNCR are estimated to be between $300,000 to $1 million per kiln. Setting aside consideration of costs for pilot testing, development, and optimization of SCR customized for the kilns in Ellis County, SCR is more costly to install and operate than SNCR. Using cost estimates presented in the cement kiln study, capital costs for installation of SCR were estimated to be $60.9 million for all ten kilns, compared to $16.4 million for SNCR. Capital costs for installation of LoTOx were estimated to be $49.5 million. Annual costs to operate and maintain SCR systems on all ten kilns, including capital servicing costs, were estimated to be $20.5 million, compared to $5.9 million for SNCR. Annual costs for LoTOx were estimated to be $15.4 million. Even requiring these units to operate only during ozone season does not change the relative costs, though it might be expected to reduce the operation and maintenance portion of annual costs by about one-third. In terms of cost per ton of NO _X emissions reduced, SNCR is more cost-effective than SCR and LoTOx. Cost-effectiveness estimates for SNCR presented in the cement kiln study range from $1,400 to $2,300 per ton of NO _X . Cost-effectiveness for SCR, on the other hand, were estimated to be considerably higher: $1,600 to $5,500 per ton of NO _X . LoTOx cost-effectiveness estimates ranged from $2,100 to $3,000 per ton. The commission considers the costs for SCR and LoTOx to be unacceptably high compared to the readily available alternative.

Regarding statements about the cement kiln study, the commission made the report available on its Web site as soon as possible following reviews for contractual completeness and quality assurance. The commission did not attempt to influence the authors of the report in any way, carefully reviewed its findings, and relied on these findings to assess the feasibility and costs of NO _X control technologies for both dry and wet cement kilns. Regarding the statement concerning a letter from the governor's office, the commission contacted the governor's office and was informed that no such letter was issued by the governor's office. No change has been made to the rule based on these comments.

PCA and TXI recommended that because of the experimental nature of SNCR, the ammonia limit in §117.3123(f) should be developed on a kiln-by-kiln basis.

The ammonia emission specification in §117.3123(f), 10 ppmv at 7% oxygen, dry basis, should be achievable; however, owners or operators of kilns that cannot attain the ammonia emission specification may petition the executive director for an alternative emission specification under §117.3125. The compliance schedule provides the owners or operators sufficient time to optimize control systems and determine if a request for an alternative emission specification may be necessary. No change has been made to the rule based on this comment.

Ash Grove commented that ammonia limits must include allowance for background ammonia contained in feed materials and that the proposed limit anticipates emissions associated with injection not baseline, and recommended changes to §117.3123(f). Ash Grove also commented that §117.3125(a) references a non-existent emission specification and that §117.3123(c) requires monitors under §117.3142 to demonstrate compliance. Ash Grove noted that without additional CEMS for ammonia, it will be unclear whether the proposed limit will be met.

Regarding background ammonia, any background ammonia contained in the feed materials would only lessen the amount of ammonia or urea injection needed for NO _X control. Therefore, the commission disagrees with the suggestion that a higher ammonia emission specification is warranted based on a possible cumulative effect on ammonia slip. Regarding Ash Grove's comment on §117.3125(a), the proposed and adopted §117.3125(a) correctly references the ammonia emission specification in §117.3123(f). Monitoring to demonstrate compliance with the ammonia emission specification is required in §117.3142(a)(3). No change has been made to the rule based on this comment.

Holcim, PCA, and TXI commented that, based on SNCR test results on precalciner kilns, the proposed ammonia standard seems reasonable, particularly when coupled with alternative case-specific ammonia specification in §117.3125.

The commission appreciates the support.

Monitoring, Testing, Recordkeeping, and Reporting

Ash Grove commented that ammonia monitoring required in §117.3142(a)(3) and specified in §117.8130 applies to gas- and liquid-fired units that inject urea or ammonia, but does not mention solid-fired units, such as the units operated by Ash Grove.

Regarding Ash Grove's comment concerning §117.8130, it was the commission's intent that cement kilns using ammonia or urea injection for NO _X control be required to conduct ammonia monitoring, regardless of the fuel type. The commission has revised the language in §117.3142(a)(3) to clarify the ammonia monitoring requirements.

Ash Grove noted that the equation for hourly NO _X emissions in §117.3142(b)(1) is inconsistent with standards used to perform relative accuracy test audits, the equation appears to be incorrect, and oxygen correction is unnecessary and burdensome, and suggested striking the requirement for oxygen correction. Ash Grove also requested clarification on §117.3142(b) and whether a daily total means 24 hours or actual hours of operation per day and how daylight savings time adjustments should be considered.

Regarding the factor used in the equation for computing hourly NO_X , the equation cited by the commenter would yield approximately the same factor as the EPA Method 19 conversion factor. However, the EPA factor for converting ppmv to pounds per dry standard cubic foot is the appropriate factor and the commission declines to make the suggested change.

Regarding Ash Grove's comment about oxygen correction, the NO _X mass emission rate calculated using both concentration and flow corrected to 7% oxygen should be identical to the calculated result using uncorrected concentration and flow. The commission specified that corrected concentration and flow be used in the calculation to be consistent with recordkeeping requirements for corrected concentration and flow. However, the commission agrees that this step is unnecessary for demonstrating compliance with the source cap and has revised the equation in §117.3142(b)(1) and associated recordkeeping requirements accordingly.

Regarding Ash Grove's comment on the definition of N in §117.3142(b)(2) and daylight savings time, the purpose of the equation in §117.3142(b)(2) is to determine the total NO _X emissions for the calendar day regardless of whether the calendar day is a standard 24-hour day or is one hour longer or shorter due to daylight savings time changes. The commission has revised §117.3142(b)(2) to specify that the daily total NO _X emissions is the sum of the hourly NO _X emissions rather than sum of the 24 hourly NO _X emissions.

Ash Grove asserted that the daily and 30-day rolling average records required by §117.3145(c)(4) would create redundant recordkeeping requirements and were unnecessary and overly burdensome. Ash Grove commented that hourly and minute records are already maintained and are sufficient to demonstrate compliance. Ash Grove indicated plans to ensure compliance by establishing a kiln hourly limit that would ensure compliance with the 30-day rolling average and periodically calculating the 30-day rolling average.

The commission disagrees with Ash Grove's comments regarding the records required by §117.3145(c)(4). The daily and 30-day rolling average records are necessary for commission investigators to determine compliance with the source cap. No change has been made based on this comment.

BSA, Public Citizen, and SEED Coalition commented that 30-day averaging is too flexible to provide accurate assessment for ozone alerts and undermines enforceability of the 11 tpd reductions expected from cement kilns. The commenters recommended a 24-hour limit for the source cap.

NO _X emissions from cement manufacturing are by nature highly variable. The suggested shorter averaging period would be an unreasonable burden and sources would not be able to comply with the source cap as adopted under a 24-hour averaging period. No change has been made to the rule based on this comment.

DIVISION 3, WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

HSC opposes the weakening of the water heater standards. HSC commented that stringent standards are needed to reduce VOC and NO _X emissions for all sources. HSC commented that the area is out of attainment and the SIP does not demonstrate attainment and questioned why the commission was weakening pollution rules.

The commission disagrees with HSC that the proposed rules will weaken the water heater standards. This proposed rulemaking implements requirements from HB 965, 79th Legislature, 2005 that affect the current Residential Water Heater rule. HB 965 required the commission to conduct a survey to determine whether the residential water heater manufacturers could meet the 10 ng/J emission limit specified in the applicable regulations by the January 1, 2007, compliance date. Staff completed the technical and economic feasibility study in cooperation with industry and trade associations by December 31, 2005.

As part of the study, the commission was provided a list of seven manufacturers of natural gas-fired residential waters. Of the seven manufacturers, three indicated that they would not formally respond to the survey since they do not manufacture residential water heaters affected by the 10 ng/J NO_X emission standard in §117.465(b)(2). The four remaining water heater manufacturers indicated that they could not manufacture a residential natural gas-fired water heater compliant with the 10 ng/J NO_X emission limit by January 1, 2007. Therefore, residential natural gas-fired water heaters meeting the 10 ng/J NO _X emission limit are not available.

As required by HB 965, the commission held a public hearing on the findings of the technical and economic feasibility study for residential water heaters on February 28, 2006. Commenters attending the public hearing were in favor of repealing the section of the rule that establishes a NO _X emissions limit of 10 ng/J for residential natural gas-fired water heaters. The combination of comments received and uncertainties in the water heater manufacturers' ability to produce water heaters compliant with the current rule have precipitated the proposed changes to the rule and SIP. The 40 ng/J standard will be retained to prevent backsliding. The commission made no changes to the rules in response to this comment.

EPA commented that the initial Texas water heater rule has been a part of the approved Texas SIP since 2000 and that Texas declared SIP credit toward its attainment plan in 2000. Therefore, EPA requested TCEQ either include the technical and economic analysis in the final Chapter 117 submission or at least include references to the documents and such documents must be made accessible to the public.

The commission provided a technical and economic analysis for Section 110(l) purposes in the proposal preamble of the Chapter 117 rule revisions as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10543). As discussed elsewhere in this preamble, the technical analysis justifying the repeal of this emission standard based on the study required by HB 965 and comments received that manufacturers are currently unable to produce residential natural gas-fired water heaters that can meet the 10 ng/J NO _X emission specification. This study is available on the commission's Web site at http://www.tceq.state.tx.us/implementation/air/sip/waterheater.html.

Regarding the replacement reductions for the Houston-Galveston-Brazoria ozone nonattainment area, EPA commented that the water heater rule revision repealing the 10 ng/J standard on residential water heaters may be met with excess reductions obtained from minor NO _X sources under a currently effective rule provided the substitutions meet certain requirements. The replacement reductions must not have previously received SIP credit, been used in SIP modeling for future dates, and not interfere with any applicable requirement concerning attainment or the FCAA. EPA requested an analysis demonstrating that the identified excess emission reductions obtained in place of the reductions that would have resulted from the water heater rule complies with Section 110(l) of the FCAA and have not been used or credited elsewhere.

As the commission indicated in the proposal preamble as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10543), the modeled and SIP creditable reductions associated with 30 TAC Chapter 117, Subchapter D, Division 2 (now Subchapter D, Division 1) only includes those sources that were part of the MECT Program. The MECT Program includes a potential-to-emit de minimis exemption threshold of 10 tpy. A large number of sources in the Houston-Galveston-Brazoria ozone nonattainment area are subject to 30 TAC Chapter 117, Subchapter D, Division 2, but are exempt from the MECT Program. While this rule is included in the current approved Texas SIP, the SIP creditable reductions associated with the rule only include those sources that are subject to the MECT Program. As Table 4-1 of the Houston-Galveston-Brazoria ozone nonattainment area SIP revision shows, the 333.5 tpd reductions for point source NO _X controls were credited with the MECT Program. Boilers located at sites that are exempt from the MECT Program in the Houston-Galveston-Brazoria ozone nonattainment area would be predominately, if not exclusively, classified as area sources and not included in the point source inventory. The area source NO _X reductions credited from control on gas-fired heaters and small boilers is the 0.5 tpd in question from 30 TAC Chapter 117, Subchapter D, Division 1 (now Subchapter E, Division 3). Subchapter D, Division 1 applies to boilers, process heaters, and water heaters with a rated capacity up to 2.0 MMBtu/hr. Boilers rated at 2.0 MMBtu/hr or less are exempt from Subchapter D, Division 2; therefore, there is no possibility of potential overlap between the two regulations.

The 0.7 tpd excess emissions estimated from 30 TAC Chapter 117, Subchapter D, Division 2 only include reduction estimates from gas-fired boilers located at sites exempt from the MECT Program. Information for these boilers was provided by the Texas Department of Licensing and Registration (TDLR), which requires boilers larger than 400,000 Btu/hr to be registered. Some of the information required with this registration includes boiler rating in MMBtu/hr, fuel type, owner, business name, and location. The commission estimated the excess reductions based on TDLR boiler information by first excluding boilers rated at 2.0 MMBtu/hr and less and those boilers located at those sources that were known or suspected to be subject to the MECT Program. The majority of remaining boilers were located at sites that would be extremely unlikely to exceed the 10 tpy threshold, e.g., school, hotels, office buildings, dry cleaners, large residential buildings, etc. Conservative estimates of boiler operation as well as business operation were applied to these sources to estimate boiler usage as well as exclude those boilers that would likely qualify for the low fuel usage exemption in the rule. EPA approved AP-42 emission factors were used to estimate uncontrolled NO _X emission rates and reductions were calculated based on the controlled rate of 0.036 lb/MMBtu in the effective rule.

Regarding the replacement reductions proposed for the Dallas-Fort Worth eight-hour ozone nonattainment area, EPA commented that the water heater rule revision repealing the 10 ng/J standard on residential water heaters can be approved as long as Texas submits an approvable eight-hour ozone attainment demonstration for the Dallas-Fort Worth eight-hour ozone nonattainment area and the SIP demonstrates attainment as expeditiously as practicable. In addition, EPA requested that the commission use the 5% IOP SIP figures published in the August 22, 2006, issue of the Federal Register (71 FR 48870) rather than the figures provided on page 4-13 of the Dallas-Fort Worth eight-hour ozone attainment SIP.

The commission has made the suggested change to the table showing the Dallas-Fort Worth eight-hour ozone nonattainment area 5% IOP reductions.

EPA suggested adding the word "genuine" to §117.3215(a), revising the provision to read ". . .the input rating as it appears on the genuine rating plate. . .."

CenterPoint and TGS supported the repeal of the 10 ng/J emission standard for Type 0 water heaters. The commenters stated when the current unavailability of low NO _X water heater technology and the additional cost expected for that technology are considered together, the commission's proposed repeal is most closely aligned with the legislature's intent in HB 965.

The commission appreciates this comment in support of this part of the proposed rule.

BSA, ED, Public Citizen, and SEED Coalition commented that the commission should clarify that the increased emissions from the repeal of the 10 ng/J standard in the water heater rule have been included in the modeling. The commenters added that they did not consider it adequate to replace the lost emission reductions with previously adopted VOC controls, and that additional reductions should be adopted since the attainment demonstration does not demonstrate attainment.

The commission disagrees with the commenters statement that there is an increase in emissions from the repeal of 10 ng/J standard for residential water heaters. The commission is repealing the 10 ng/J standard for residential water heaters because manufacturers are not currently able to meet this standard; however, the commission is retaining the current 40 ng/J standard that manufacturers are currently capable of meeting and are available in the market. As explained elsewhere in this preamble, replacement reductions for the 0.5 tpd reductions claimed were taken from the excess reductions achieved by the commission's 5% IOP SIP. As EPA indicated in the Federal Register (71 FR 48870), when proposing approval of the 5% 2005 IOP SIP, the commission's reductions from the adjusted 2002 baseline were 4.43% NO_X and 1.25% VOC, and the total reductions were 5.68%. The 5.68% meets the requirements of the 5% guidance and leaves a small surplus of 0.68%. The commission's obligation under the Texas 5% 2005 IOP SIP is a 5% that is the sum of the percent VOC reduction and the percent NO _X reduction. Therefore, the commission is free to achieve more or less reductions from either NO _X or VOC, provided the sum of the individual percent reductions equals 5%. The 0.68% surplus achieved equates to 4.23 tpd NO _X reductions, which is more than sufficient to replace the 0.5 tpd reductions claimed for the Small Boiler, Process Heater, and Water Heater rule. It should be noted that the commission is only repealing the 10 ng/J standard for residential water heaters and not the entire rule. While the commission does not currently have a means of accurately estimating the reductions, the emission standards for the other unit-types subject to the rule will still achieve NO _X reductions in the nonattainment area and state-wide. The 0.5 tpd claimed for the Dallas-Fort Worth and Houston-Galveston-Brazoria ozone nonattainment areas were conservative estimates based only on residential water heaters and did not include the real reductions from other units subject to the rule.

DIVISION 4: EAST TEXAS COMBUSTION

General

Judge Adams commented that he was very proud of the work the TCEQ staff has done over the past ten years to improve the air quality in North Texas. Judge Adams supported the commission going outside of the nonattainment areas to implement strategies that will help the Dallas-Fort Worth eight-hour ozone nonattainment area come into attainment. Judge Adams commented that the proposed East Texas Combustion rules should be applied to all of the East Texas counties, and this would provide 83 tpd of NO _X reductions.

The commission appreciates Judge Adams' comments and support. Regarding the commenter's request to apply the East Texas Combustion rule to all East Texas counties, the commission acknowledges that substantially more reductions could be accomplished by expanding the rules to the other counties in East Texas. While such a measure might potentially benefit other areas, the commission's initial sensitivity modeling indicated that applying controls to all gas-fired engines in East Texas would only have a slightly increased benefit to the Dallas-Fort Worth eight-hour ozone nonattainment area. This increased benefit was, on average, less than 0.02 ppb ozone reduction. Furthermore, the expansion of the proposed Chapter 117 rules for these sources or the application of other new control strategies to new persons would not allow for appropriate public review and comment. The commission might consider expanding the applicability of the rule to other areas if such a measure was necessary to benefit other nonattainment or near-nonattainment areas.

ED expressed support for the proposed East Texas Combustion rule, but commented that the rule should apply to all units within 200 kilometers and that there was no reason why sources in certain counties should be exempt.

The commission appreciates the support for the rule. Regarding the counties included in the applicability of the East Texas Combustion rule, the commission selected those counties where significant numbers of gas-fired engines were known or anticipated to be located, and where reductions in NO _X emissions from these engines would benefit the Dallas-Fort Worth eight-hour ozone nonattainment area. Regarding the commenters' suggestion to apply the rule to more counties, the expansion of the proposed Chapter 117 rules for these sources or the application of other new control strategies to new persons would not allow for appropriate public review and comment. The commission might consider expanding the applicability of the rule to other areas if such a measure was necessary to benefit other nonattainment or near-nonattainment areas.

BSA, City of Fort Worth, NCTCOG, Public Citizen, and SEED Coalition expressed support for the NTCASC resolution recommending controls on combustion engines in East Texas as well as within 200 kilometers of the North Central Texas nonattainment area.

The commission appreciates the support for the East Texas Combustion rule. The expansion of the proposed Chapter 117 rules for these sources or the application of other new control strategies to new persons would not allow for appropriate public review and comment. No change has been made to the rule based on this comment.

APC, Devon, EOG, Eastman, ExxonMobil, TIPRO, TPA, TXOGA, and XTO recommended the commission withdraw the proposed East Texas Combustion rules and reassess the cost and effectiveness of the proposal. APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA recommended the commission not adopt the East Texas Combustion Rules, citing the uncertainty in the status of the Phase I rule from the recent D.C. Circuit Court ruling and the unrealistic expectations of lean-burn control technologies. J-W Gathering indicated the increased operating costs would ultimately increase the cost of natural gas for consumers and requested a delay in the implementation of the East Texas Combustion Rules to enable all affected parties to fully evaluate this cost increase. PVOG commented that further review and better understanding of the commission's rationale of the impact these emissions reductions would have on the nonattainment area before requiring one industry (combustion source operations, mostly oil and gas industry) to spend hundreds of millions of dollars to comply with the newly proposed rules in Chapter 117, Subchapter E, Division 4.

APC, Devon, ExxonMobil, TIPRO, and TPA stated that with no valid deadlines in place governing the date by which eight-hour ozone nonattainment areas must achieve attainment, the commission is proceeding with an artificial deadline of June 15, 2007. The commission should postpone or suspend its current rulemaking, particularly the East Texas Combustion Rule, until there is a clear guidance from EPA on how it expects to modify the requirements of eight-hour ozone SIPs to address the holdings of South Coast and for clarification as to what deadlines apply.

APC, Devon, ExxonMobil, TIPRO, TPA, and XTO commented the South Coast Opinion vacated EPA's Phase 1 Implementation Rule for the eight-hour ozone NAAQS, which defined basic aspects of the eight-hour standard such as classifications, attainment dates, and anti-backsliding policies and repealed the one-hour ozone NAAQS. The commenters stated that the SIPs the commission is developing for Dallas-Fort Worth eight-hour ozone nonattainment area (and the Houston-Galveston-Brazoria ozone nonattainment area) are not currently governed by any attainment deadlines. APC, Devon, ExxonMobil, TIPRO, and TPA commented with the repeal of the Phase I Rule, it is unclear what methodology the commission is authorized to follow in its transition toward compliance with the eight-hour ozone NAAQS and its eight-hour ozone SIP. Importantly, the regulated community has no clear idea of the rules and standards that will govern the SIP and, in turn, be applied to it.

The commission disagrees with the commenters' suggestion to withdraw the East Texas Combustion rule. Regardless of the court decision's final outcome and any changes to EPA's rules, the commission is obligated to pursue emission reductions that will get the area in attainment as expeditiously as practicable. As discussed elsewhere in this preamble, EPA guidance does provide for taking credit for reductions outside the nonattainment area. The commission has adopted similar rules in the past that apply to attainment counties, and in some cases statewide, to help nonattainment area attain the NAAQS. However, as discussed elsewhere in this preamble, the commission has decided to exclude lean-burn engines from the East Texas Combustion rule. This change is anticipated to result in substantial financial savings for owners or operators of stationary gas-fired engines in the counties included under the adopted rule.

Regarding the comments pertaining to the D.C. Circuit Court opinion issued on December 22, 2006, South Coast AQMD v. EPA , 472 F. 3d 882 (D.C. Cir., 2006), the court granted certain petitions in part, vacated the rule, and remanded the rule to the EPA for further proceedings. EPA requested and was granted an extension to the deadline for appeal of the ruling, until March 22, 2007. The Phase I rule specified requirements for the preparation, adoption, and submittal of SIPs for the eight-hour ozone standard, in addition to revoking the one-hour ozone standard for an area one year after the effective date of the designation of an area for the eight-hour standard. Since this ruling may be appealed, the full impact of this ruling will not be known until the ruling is final and EPA has promulgated new rules. While it is likely that SIP planning efforts will be impacted, the commission has no information regarding how control strategies may be impacted by this decision. Regarding the June 15, 2007, deadline, this deadline is not artificial and originated from the 1990 FCAA Amendments that state that a SIP revision is due three years after an area is designated nonattainment.

NETAC disagreed with the comments made by the commission in the preamble of the proposed rule that the Tyler-Longview area would benefit from NO_X emissions reductions achieved by the East Texas Combustion rule. NETAC asserted that the proposed compliance date would be too late to help the Northeast Texas Early Action Compact Area avoid a nonattainment designation by demonstrating attainment by December 31, 2007. Additionally, NETAC commented that the East Texas Combustion rule may be counterproductive because it would be a disincentive to earlier voluntary emission reductions. The commenter indicated that NETAC's pilot project has successfully retrofitted five rich-burn natural gas compressor engines and that NETAC has sought funding from the commission under the TERP and Supplemental Environmental Program (SEP) to pay for implementing emission controls through gas compressor engine retrofits on a voluntary basis. NETAC requested the commission clarify through rule, the response to comments, or both, that it is not the commission's intent to impair NETAC's ability to obtain funding for a voluntary emission reduction program that would be implemented prior to the compliance deadline of the proposed rule.

The commission did not initiate the East Texas Combustion rule in an attempt to impair NETAC in any way. The purpose of the East Texas Combustion rule is to reduce NO _X emissions in attainment counties that contribute to ozone in the Dallas-Fort Worth eight-hour ozone nonattainment area. As noted elsewhere in this preamble, the comment in the preamble of the proposed rule was an anecdotal comment regarding potential additional benefits of the East Texas Combustion rule; however, the commission maintains that NO _X reductions achieved from the East Texas Combustion rule will benefit the Northeast Texas Early Action Compact Area. As adopted, the commission estimates that the rule will reduce NO _X emissions by approximately 7.0 tpd in the 5-county Tyler-Longview area. Additional benefit will also be realized by substantial reductions from neighboring Panola County. While the commission supports NETAC's efforts to demonstrate attainment by December 31, 2007, and to reduce emissions through voluntary measures, it is unlikely that NETAC could accomplish an equivalent level of reductions in the short-term or even by the adopted compliance date through voluntary implementation of controls on the same category of engines.

EPA expressed support for the language in §117.3310(d) concerning determination of a unit's classification as of December 31, 2000.

The commission appreciates the support.

Devon commented that there was no existing justification in EPA rules for regulating oil and gas operations in attainment areas for the benefit of nonattainment areas. In addition, Devon commented that regulating attainment areas is setting a bad precedent in public policy given that the rule package does not regulate the mobile source emissions that make up 70% of the emissions in the nonattainment area. Devon expressed concern that the rule would result in minimal emission reductions and would unfairly burden affected operators with increased costs and compliance risks, especially operators of existing units in these attainment counties.

APC commented that the proposed East Texas Combustion Rule shifts the burden of compliance to operators of engines in areas that have maintained attainment rather than focusing enforcement and regulatory actions on nonattainment areas. Eastman suggested that before imposing emission limits on attainment counties that all potential source reductions within the Dallas-Fort Worth eight-hour ozone nonattainment area should be fully explored since the majority of Dallas-Fort Worth eight-hour ozone nonattainment area NO _X emissions come from mobile sources, and photochemical modeling shows that local reductions in NO _X emissions has the greatest impact on reducing ground level ozone formation. PVOG states this is an unprecedented proposal of a regulation that would require emission reductions in an attainment area for the benefit of a nonattainment area.

The commission disagrees with the comment that there is no existing justification in the EPA rules for regulating emission sources in attainment areas for the benefit of nonattainment areas. The commission agrees that reductions in mobile source emissions would advance attainment of the eight-hour ozone standard in the Dallas-Fort Worth eight-hour ozone nonattainment area; however, the commission does not have the legal authority to require lower engine emission standards for motor vehicles. Furthermore, this rulemaking is not unprecedented in its application to attainment counties. The commission has previously adopted regulations on point sources in attainment counties to further attainment of nonattainment areas, e.g., 30 TAC Chapter 117, Utility Electric Generation in East and Central Texas. Controls adopted in this rulemaking implement stringent controls on major and minor sources of NO _X in the Dallas-Fort Worth eight-hour ozone nonattainment area; therefore, the commission disagrees with the comment that efforts have not been focused on the nonattainment area.

PVOG expressed concern for the lack of communication from the commission to the natural gas operators within the 39-county area affected by the East Texas Combustion rules. PVOG stated that the affected natural gas operators were not properly notified of potential impacts to their operations because the rules were disguised as an amendment to the Dallas-Fort Worth eight-hour ozone attainment SIP and thus easily overlooked by operators outside of the nine-county Dallas-Fort Worth eight-hour ozone nonattainment area. PVOG recommended the commission send notification to the operators of affected sources and include a clear statement of the rules, compliance time frames, and the rationale for regulating these 39 counties.

The commission has made no attempt to disguise the East Texas Combustion rule and has provided adequate notice to industries that would be impacted by the rule. The commission has conducted stakeholder meetings for the new rules developed as a part of the Dallas-Fort Worth eight-hour ozone attainment demonstration, including the East Texas Combustion rule. A stakeholder meeting was held in Longview on September 7, 2006, that was specifically for the East Texas Combustion rule. Public hearings on the rule were held in Austin, Arlington, Dallas, Houston, Longview, and Midlothian. In addition, the commission provided a 45-day comment period in lieu of the standard 30-day period. The information suggested by PVOG is provided in the preamble discussion of the rule proposal as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10538 - 10607) and was made available to the public on the commission's Web site 19 days before the commission voted to approve publication of the rule proposal.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA supported the use of emission reduction credits (ERCs) to meet the proposed emission specifications. The commenters requested additional clarification on how this program would work for the 39-county attainment area. In addition, APC, Devon, ExxonMobil, TIPRO, and TPA urged the commission to adopt a provision for emission averaging among sites owned and operated by the same person similar to that provided for in the Pipeline Facility Permit (PFP).

The East Texas Combustion rule allows the use of DERCs as a means of compliance flexibility for the East Texas Combustion rule by reference to §117.9800. The use of ERCs under §117.9800 and Chapter 101, Subchapter H is only applicable in nonattainment areas and would not be available to sources subject to this rule. Regarding the commenter's suggestion to allow emission averaging among sites owned and operated by the same person, emissions averaging based on g/hp-hr across engines and sites would undermine the enforceability of the rule. The commission would have no means of estimating reductions if owners or operators were allowed to average emission rates across multiple engines and sites without regard to size of engine or activity. The PFP provision noted by the commenter did allow averaging across engines; however, this averaging provision has also prevented the commission from taking any SIP credit for any reductions that might have been occurred for compressor engines under §116.779. Such an approach would require establishing a system-cap approach, similar to the system-cap approach allowed for EGFs in some nonattainment areas. Significant changes would be necessary to establish a pipeline system-cap type approach that are beyond the scope of this rulemaking.

Eastman suggested the commission consider incorporating a NO _X emissions cap and trade program into the East Texas Combustion Rules because providing rule flexibility will still result in NO _X emission reductions and may prevent some owners and operators from shutting down older units and reducing their workforce.

This commenter's suggestion of a cap and trade program for the East Texas Combustion rule is beyond the scope of this rulemaking; however, as noted elsewhere in this preamble, there are trading options available under the proposed rules. The rules allow the use of DERCs as a means of compliance flexibility for the East Texas Combustion rule by reference to §117.9800.

TIPRO commented many of these companies do not fall under TCEQ permitting regulations and the costs associated with these new regulations will be the first introduction of a new class of small business owners to the TCEQ.

The commission acknowledges that these sources are newly regulated under Chapter 117, but disagrees that the rule would introduce a new class of small business owners to TCEQ. The commission has adopted rules previously that regulate small businesses and small institutions. Sources subject to Chapter 117 in the Houston-Galveston-Brazoria ozone nonattainment area include small businesses and institutions such as dry cleaners, hospitals, schools, hotels, and other minor sites. Furthermore, the commission disagrees that these facilities are not subject to permitting regulations. Any facility that emits an air contaminant in Texas must obtain authorization, unless it is de minimis . The companies in question may be authorized under permit by rule through Chapter 106, but this is also a type of permit.

APC, Devon, ExxonMobil, TIPRO, and TXOGA objected to the provision in §117.3310(c) that specifies the maximum rated capacity used to determine applicability of the emission specifications or exemption status must be the greater of the maximum rated capacity as of December 31, 2000, or the maximum rated capacity after that date. The commenter indicated the emission rates should be based on the current rated capacity and horsepower.

The commission disagrees with the commenters. If an engine increases in capacity, it should be held to the appropriate and more stringent emission specification of the larger size. However, decreasing an engine's size should not be a means of circumventing the control requirements of the rule. No change has been made to the rule based on this comment.

EMA and ExxonMobil recommended the CO level for gas-fired engines fueled on pipeline natural gas should be set at 4.0 g/hp-hr, and for landfill gas engines at 5.0 g/hp-hr. TXOGA requested that the CO emission specification in §117.3310(e)(1) be removed because CO is not an ozone precursor.

While CO is an indicator of proper operation of combustion processes, the focus of the East Texas Combustion rule is to reduce transport of NO_X and ozone into the Dallas-Fort Worth eight-hour ozone nonattainment area. As indicated by the commenter, CO is not an ozone precursor. In addition, the commission has not performed analyses to determine the impact, if any, of CO emissions from attainment counties on the Dallas-Fort Worth eight-hour ozone nonattainment area. Therefore, the commission has determined that the CO emission specification and the associated testing and recordkeeping requirements are unnecessary for the purposes of the East Texas Combustion rule.

APC, Devon, ExxonMobil, TIPRO, and TXOGA suggested that the provisions regarding alternative case-specific specifications should be revised to remove reference to CO and include NO _X .

The commission disagrees with the commenter that the provisions for alternative case specific specifications in §117.3325 should include NO _X . Allowing regulated sources to petition for alternative NO _X emission specifications would not ensure that modeled reductions would be achieved and could endanger EPA approval of the rule. As discussed elsewhere in this preamble, the CO emission specification has be removed from §117.3310. Therefore, §117.3325 has been revised to reflect this change.

Exemptions

APC, Devon, ExxonMobil, Faulconer, TIPRO, TPA, and TXOGA recommended that engines with a maximum rated horsepower capacity of less the 240 hp be exempt from the rule. The commenters suggested that engines less than 240 hp should be exempt due to concerns with the reliability of controls on this class of engines. Commenters indicated that load swings on this class of engine can be abrupt and continuous, which will not allow add-on emission controls to obtain steady state operation.

The commission disagrees with the commenters that engines of this size category cannot be retrofitted for technical reasons; however, the commission has decided to exempt rich-burn gas-fired engines less than 240 hp for separate reasons. Based on the commission's estimates and comments received, hundreds of rich-burn engines fall under this size range. As suggested by commenters regarding the compliance schedule, attempting to implement controls on all engines 50 hp and greater could place an excessive burden on manufacturers and vendors of control equipment. The commission anticipates that controls on rich-burn engines 240 hp and greater in the 33 counties included in the East Texas Combustion rule can be implemented in time to benefit the Dallas-Fort Worth eight-hour ozone nonattainment area by the attainment date. While substantial reductions from smaller rich-burn engines could still be realized, attempting to implement controls on the numerous smaller engines could present an obstacle to achieving the overall benefit to the nonattainment area.

APC, Devon, Eastman, ExxonMobil, TIPRO, TPA, TXOGA, Westlake, and XTO suggested exempting existing lean-burn engines due to technical and economic feasibility issues associated with lean-burn engine controls discussed elsewhere in this preamble. For the purposes of this exemption, some commenters suggested existing engines would be engines placed into service prior to June 1, 2007.

As discussed elsewhere in this preamble, the commission has exempted all lean-burn engines from the rule. The commission may pursue reductions from lean-burn engines in the East Texas Combustion rule at a later date.

PVOG suggested the commission include a grandfather clause exempting older engines or using a tiered compliance schedule in the East Texas Combustion Rule.

As discussed elsewhere in this preamble, the commission has exempted lean-burn engines from the rule and rich-burn engines less than 240 hp. An additional year has been provided for rich-burn engines to meet the emission specifications and to comply with all other requirements of the rule.

APC, Devon, ExxonMobil, TIPRO, TXOGA, and TPA suggested adding an exemption that would exempt engines that meet the emission specifications of the East Texas Combustion rule through New Source Review (NSR) amended permits or through filing forms APD-CERT or PI-7Cert. The commenters indicated that this would maintain federal enforceability of the East Texas Combustion rule emission rates and shift the compliance requirements to NSR, which is more familiar to operators in attainment counties. TXOGA provided example rule language for the exemptions that would apply to existing or new engines, or in-kind replacements of existing or new engines, if a PI-7CERT, APD-CERT, or permit revision or alteration is submitted by the appropriate compliance date and the NO _X emission rates are equivalent to the schedule in §117.3310(a).

The commission has provided adequate exemptions under the rule. The suggested NSR permit-based exemption criteria suggested by the commenters would add unnecessary complexity to the rule and suggested mechanisms would not always ensure that the emission standards are being met due to varying testing requirements under NSR permitting. Therefore, the commission declines to make the suggested change.

APC, Devon, ExxonMobil, TIPRO, and TXOGA suggested that the commission could exempt both smaller, difficult to control engines and existing lean-burn engines while still being able to achieve needed reductions to satisfy SIP requirements. APC, Devon, ExxonMobil, TIPRO, and TXOGA added that these engines could be exempt because of reductions from the Reciprocating Internal Combustion Engine (RICE) Maximum Achievable Control Technology (MACT), Voluntary Emission Reduction Program (VERP), PFP, shutdowns, replacements, and other controls.

The commission has exempted lean-burn engines from the East Texas Combustion rule at this time. While the commission has also raised the exemption threshold to 240 hp for rich-burn engines, this change is not due to technical infeasibility. As discussed elsewhere in this preamble, the commission changed the exemption due to the difficulty in retrofitting the number of smaller engines in time to benefit the Dallas-Fort Worth eight-hour ozone nonattainment area by the attainment date.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA suggested that the commission broaden the exemption for emergency or low load engines to include engines authorized under §106.511 or otherwise meet the use type and operating conditions of §106.511. Devon commented that low use engines should be exempt because of the high cost of control compared to the emission reduction.

The commission has already provided adequate exemptions under §117.3303, including exemptions for engines used exclusively for emergency purposes. Therefore, the suggested change is not necessary.

Modeling

Devon suggested that Wise, Hood, and Somervell Counties should be removed from the list of 39 counties subject to the proposed rule. APC, ExxonMobil, TIPRO, TPA, TXOGA, and XTO requested that Bosque, Cooke, Grayson, Hood, Somervell, and Wise Counties be removed from the list of counties in §117.3300. The commenters indicated that these westerly counties are not within any prevailing wind pattern for the Dallas-Fort Worth eight-hour ozone nonattainment area and that subjecting counties in the western quadrant of the Dallas-Fort Worth eight-hour ozone nonattainment area to the East Texas Combustion Rule would have little impact on reducing ozone in the Dallas-Fort Worth eight-hour ozone nonattainment area. APC, Devon, ExxonMobil, TIPRO, and TPA commented the cost of implementing controls to engines in these counties greatly exceeds the negligible benefits they might provide within the Dallas-Fort Worth eight-hour ozone nonattainment area. Based upon a survey of limited operators, TPA indicated the costs of compliance in just Wise County would be approximately $7.6 million. TIPRO suggested the benefits of the proposal are minute, unproven, and do not justify inflicting such economic hardship to small business. The modeling used to estimate potential benefits include atypical wind patterns. TIPRO asserted that the wind patterns during the covered period are usually east/southeasterly and engines in multiple counties included under the proposed rule would not be contributing to the exceedances that the rule aims to reduce.

The commission has performed additional modeling sensitivity runs to evaluate the benefit of including Bosque, Cooke, Grayson, Hood, Somervell, and Wise Counties in the East Texas Combustion rule. These sensitivity runs indicate that the Dallas-Fort Worth eight-hour ozone nonattainment area would only benefit approximately 0.05 ppb reduction in ozone from including these six counties under the rule. Based on this information, the commission agrees that these counties should not be included in the rule and has revised the applicability of the rule accordingly.

APC and EOG commented that the commission's emission model is based on older emission inventory data and does not account for NOx emission reductions that have occurred over the last decade. APC further commented that it appears the commission did not take into consideration the benefits associated with the last decade of increased regulation nor is it considering the future benefits that will be generated by the ongoing implementation of existing regulations. EOG commented that based on prevailing wind direction during ozone season, this reduction of increment may not occur.

Eastman and Westlake commented that imposing controls on attainment areas should be a last resort and was not justified. Eastman, TIPRO, and Westlake commented that the predicted ozone reduction of 0.3 ppb is less than 0.5% of the federal ozone standard and is within the margin of error of the modeling program and will not significantly contribute to attainment of the eight-hour ozone standard in the Dallas-Fort Worth eight-hour ozone nonattainment area. Westlake further stated that it is unreasonable to impose penalties on counties outside of the Dallas-Fort Worth eight-hour ozone nonattainment area, especially when they are not even neighboring counties to the Dallas-Fort Worth eight-hour ozone nonattainment area and are located downstream of prevailing winds. TIPRO added that this projected benefit was calculated without factoring in measures that have been already been implemented since the modeling data year 1999. It assumes reductions of an amount that have already been reduced significantly, leaving much less to be achieved than the rule attempts to accomplish.

The commission disagrees with the comments that the predicted ozone reduction will not occur. Other control measures adopted with the rulemaking individually result in much less ozone reduction in the Dallas-Fort Worth eight-hour ozone nonattainment area. No single control measure alone will bring the nonattainment area into attainment with the eight-hour ozone NAAQS. Only through the adoption of multiple control strategies simultaneously will there be sufficient reductions for the Dallas-Fort Worth eight-hour ozone nonattainment area to demonstrate attainment with the NAAQS. The commission is not restricted to just the neighboring attainment counties. While the commission acknowledges that some reductions have occurred since 1999, these reductions are not sufficient to benefit the nonattainment area. In addition, as discussed elsewhere in this preamble, the commission's analysis of 2000 and 2003 inventory information indicates that NO _X emissions from stationary gas-fired reciprocating internal combustion engines in the 33 counties included in the adopted rule have actually increased in some counties. No change has been made to the rule based on these comments.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA expressed concern that based on the results of a study conducted by the University of Texas at Austin, the NO _X emission reductions anticipated from implementing the East Texas Combustion Rules would be offset by the increased NO _X emissions from the 15 coal-fired electric generation plants to be constructed in the East Texas area. ExxonMobil commented that since there would be no net benefit to ozone concentration in the Dallas-Fort Worth eight-hour ozone nonattainment area it is unnecessary to spend millions of dollars complying with the East Texas Combustion Rules. APC, Devon, ExxonMobil, TIPRO, and TPA recommended the commission consider the impacts from the 15 new coal-fired plants in the Dallas-Fort Worth eight-hour ozone nonattainment area before progressing any further with the East Texas Engine Combustion Rule. APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA suggested at a minimum, the commission should remodel the 39-county region and incorporate all known emission increases/decreases it anticipates in the 39-county air shed to determine if the emission reductions from the East Texas Combustion rule will have a positive long-term impact on the Dallas-Fort Worth eight-hour ozone nonattainment area.

The commission disagrees with the commenters' assertion that proposed coal-fired electric generation plants will offset any benefit from the East Texas Combustion rule. Not all of the proposed coal-fired electric generation plants may be permitted or if permitted, these coal-fired electric generation plants would be required to meet stringent emission control requirements. Many of the stationary, gas-fired reciprocating internal combustion engines subject to the East Texas Combustion rule are older engines that have not been required to install stringent controls, and in some cases the engines may be virtually uncontrolled. The prospect of new sources does not alleviate the need to control older existing sources. Furthermore, while electric power generation facilities represent the highest NO _X emitting source category in the attainment counties of East Texas, stationary gas-fired engines, particularly those in the oil and gas industry, represent the second highest NO _X emitting source category in East Texas. The commission has previously required NO _X reductions from electric power generation facilities in East and Central Texas under Chapter 117 to assist nonattainment areas. Stationary gas-fired engines in East Texas have not been previously required to make such reductions under Chapter 117. Regarding the commenter's suggestions for modeling, while the commission has performed updated modeling based on the adopted rules, expected growth, and any new authorizations, it would be inappropriate for the commission to model increases or decreases that have not been made enforceable and more certain through the permitting process.

PVOG stated that detailed summaries of the photochemical modeling used to develop the East Texas Combustion rules were not available on the commission's Web site. PVOG recommended the commission's photochemical models be independently validated and that the commission publish complete or summarized versions of all photochemical modeling for public review.

The TCEQ has provided summarized versions of all photochemical modeling on its public Web site at http://www.tceq.state.tx.us/implementation/air/airmod/data/dfw1.html . In addition, modeling results were reviewed and discussed at the Dallas/Fort Worth Photochemical Modeling Technical Committee meetings. As described in the EPA-reviewed DFW Modeling Protocol, this committee "provides technical information where needed and oversees and reviews all work performed in this project." "Project" in this case refers to the work performed by the TCEQ contractor Environ, Inc. The modeling protocol can also be found at the above-referenced Web site.

APC, Devon, ExxonMobil, TIPRO, TPA, and XTO commented that stepping outside the boundaries of a nonattainment area to achieve compliance within that area should be an action of last resort and was not justified for the East Texas Combustion rule. APC, Devon, ExxonMobil, TIPRO, and TPA added that the commission relied upon air transport modeling to demonstrate the effectiveness of this rule. EPA authorized states to substitute controls from outside the nonattainment area within 100 kilometers for VOC and 200 kilometers for NO _X if the reductions outside the nonattainment area are shown to be beneficial toward reducing ozone in the nonattainment area and the reductions meet the standard tests of creditability (permanent, enforceable, surplus, and quantifiable). However, TPA asserted that the commission's ability to demonstrate that these emission reductions are beneficial toward reducing ozone in the nonattainment area is impaired due to the prevailing wind patterns and the inaccuracies in the engine data used in the photochemical modeling performed in support of the rule.

The commission disagrees with the commenter and believes the conclusions provided in Appendix G, DFW Conceptual Model, Chapter 3, Wind Meteorology and Ozone Levels, provide a thorough analysis of wind patterns that support the benefit of reductions realized for the East Texas Combustion rule.

APC, Devon, ExxonMobil, TIPRO, and TPA commented that the commission's justification for the East Texas Combustion rule based upon benefits to the Tyler-Longview area is arbitrary and capricious and not supported by any evidence in this rulemaking record. The commenters added that the Northeast Texas Early Action Compact (NETEAC) Area, which includes the Cities of Tyler and Longview, is mentioned in the preamble for this proposed rule as partial justification for the East Texas Combustion Rule. However, the Tyler-Longview area is not the area of concern for this rulemaking and many of the 39 counties designated as the East Texas affected counties are not anywhere near the geographic area of the NETEAC. The commenters stated that reliance on the Tyler-Longview area could not be used as justification for the East Texas Combustion rule, which is promulgated to aide the Dallas-Fort Worth eight-hour ozone nonattainment area to meet attainment. No modeling was performed to determine the impact of regional reductions from these sources on the formation of ground level ozone in the NETEAC area. If the goal of the East Texas Combustion rule is to keep the Tyler-Longview area in attainment, then the commenters suggested the controls should be voluntary.

The commission has not used the potential benefits to the Tyler-Longview area as a justification for the East Texas Combustion rulemaking. The commission only noted the potential benefits to that area in the proposal preamble as published in the December 29, 2006, issue of the Texas Register (31 TexReg 10544) as an anecdotal comment regarding potential additional benefits associated with the rule.

Inventory

APC, Devon, ExxonMobil, PVOG, TIPRO, TPA, TXOGA, and XTO commented the universe of impacted engines is likely much higher than the commission has estimated, and that the commission does not have a reliable inventory of engines impacted by the rule. APC, Devon, ExxonMobil, TIPRO, and TPA commented the commission staff used an out-dated emissions inventory from 1999 to estimate emissions from engines in the 39-county region, and that use of the 1999 emissions inventory would not generate an accurate count of engines in the region as only engines at major sources were required to file these emissions inventory reports. However, the proposed rule would apply to both point source and area source engines. PVOG commented that a more accurate representation of stationary gas fired engines needs to be determined so the actual economical impact this proposal will incur on industry will be known.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA commented that, based on a TPA survey of only 11 companies, 1,055 engines were identified that would be subject to the rulemaking; 729 of which would require controls or replacement. In addition, the commenters indicated the 37 tpd NO _X reductions the commission is seeking is low. TPA estimated that reductions from just the engines surveyed will generate 53 tpd of NO _X reductions. An additional 17 tpd of NO _X reductions that were not included in the commission's modeling would bring the total to 70 tpd, 33 tpd above the level of reductions the commission indicates is needed to demonstrate attainment in the Dallas-Fort Worth eight-hour ozone nonattainment area. TPA states this rule imposes overly broad and strict emission specifications that will generate reductions far beyond what is considered reasonable for the Dallas-Fort Worth eight-hour ozone nonattainment area to reach attainment.

The commission did not indicate that the 37 tpd of NO _X reductions from the stationary gas-fired engines in East Texas Combustion counties was a specific target of reductions. Original estimates of the rule as proposed indicate that 37 tpd were the possible reductions that might be realized by implementation of the rule. The commission also acknowledges that some of the engines impacted by this rule are not included in the point source inventory and agrees that additional reductions would be realized under the proposed rulemaking than were originally estimated because of the uncertainty of the population. For the point source inventory, the 1999 inventory year was used to perform the initial estimates of engines and potential reductions. HARC H40 was used to estimate the number of area source engines as well as the potential reductions from these engines. For the final modeling analysis, the commission used the 2000 point source inventory. This change has resulted in a better matching of point source inventory for the engines subject to the rule. Reductions from well-head compressors subject to the rule are estimated based on 2000 data from HARC Project H68, a follow-up project to H40. Project H68 provided better activity data for well-head compressors than H40 as well as included well-head compressors greater than 500 hp, allowing the commission to obtain a better estimate of the potential reductions from the East Texas Combustion rule. The data from H68 indicates that well-head compressors represent a greater portion of the area source NO _X emissions from stationary gas-fired engines than originally estimated, thereby increasing the potential reduction from regulating these engines. The changes discussed elsewhere in this preamble regarding lean-burn engines, county applicability, and engine size for exemption will significantly decrease the number of engines impacted by this rulemaking.

APC, Devon, ExxonMobil, TIPRO, and TPA commented that the 1999 emissions inventory does not represent emissions reductions achieved by owners and operators of engines in East Texas since 1999; therefore, the emissions levels represented by engines that were included in the emissions inventory were overestimated. The commenters added that the formerly grandfathered engines have seen reductions from engines under other programs, such as the PFPs or VERP. The commenters asserted that taking these reductions into account may render the East Texas Combustion rulemaking unnecessary. TIPRO expressed doubt that the actual reductions would be achievable under this proposal and did not justify the burden of implementation. Furthermore, TIPRO indicated that the reductions may already have been achieved by previously adopted measures during the compliance time period.

The commission does not disagree that some reductions have occurred from stationary gas-fired engines in the East Texas area. An analysis of the 2000 and 2003 emissions inventory indicates that overall NO _X emissions from stationary gas-fired engines in the 39 counties included in the proposal have decreased approximately 9 tpd or about 17%. While these potential reductions from some engines over this time might provide some benefit to the Dallas-Fort Worth eight-hour ozone nonattainment area, addition reductions are still necessary to help the nonattainment area reach the NAAQS. In addition, while there appears to have been an overall reduction, over 90% of this decrease occurred in just six counties and 13 of the counties actually increased NO_X emissions over the same time period. Therefore, the commission has no assurance that the overall trend will continue. The NO_X reductions under the adopted rule are achievable and reasonable and will benefit the Dallas-Fort Worth eight-hour ozone nonattainment area.

APC, Devon, ExxonMobil, TIPRO, and TPA questioned how the commission identified the location of each engine represented in the model and added that the location and proximity of an engine to the Dallas-Fort Worth eight-hour ozone nonattainment area are relevant factors in determining if the reductions actually benefit the Dallas-Fort Worth eight-hour ozone nonattainment area.

Engines in the commission's point source emissions inventory are located based on the information provided by the regulated entity associated with those engines. Reductions estimated from engines not in the point source inventory, i.e., area sources, were located based on information contained in HARC study report H40. H40 and the follow-up report, H68, evaluated activity and emissions from gas-fired well-head compressors in East Texas. While the commission recognizes that well-head compressors only represent a portion of the gas-fired engines in East Texas that are not included in the point source inventory, the estimates from H40 and H68 provide some documented basis for estimating reductions. As pointed out by a number of commenters to this rulemaking, the number of area source gas-fired engines may be more than estimated by the commission. Thus, the impact of gas-fired engines in the East Texas Combustion rule, as well as the benefit of reductions from these engines, is potentially underestimated and conservative. The commission agrees that location and proximity of reductions is important in evaluating the benefit to the nonattainment area; however, the commission disagrees that this evaluation should be on an engine-by-engine basis. The benefit of the East Texas Combustion rule is based on the overall reductions achieved through applying the rule to regions with many engines that impact the nonattainment area.

Lean-Burn Engine Technical Feasibility and Economic Impact

APC, Devon, ExxonMobil, TIPRO, and TPA commented that the cost of compliance with the East Texas Combustion Rule is exceedingly high and unreasonable. The commenters stated the commission staff cost estimates are much less than the TPA survey estimates, primarily because many engines would have to be replaced. Commenters estimated replacement engine costs of approximately $116 million and costs of controls of approximately $19 million and a combined cost of compliance of $135 million, without including testing costs. Assuming a 0.3 ppb reduction in ozone in the Dallas-Fort Worth eight-hour ozone nonattainment area, the cost of compliance based upon these numbers would be $45 million per 0.1 ppb. Based upon this data, the cost-effectiveness for lean-burn engines is in the range of $28,958/ton. As these companies represent only a subset of the total number of engines and operators in the 39-county region, if a 50% factor were applied to account for all engines in the area, the total cost of compliance would be over $200 million.

APC, Devon, Eastman, ExxonMobil, TIPRO, TPA, TXOGA and Westlake commented that the control technology necessary to meet the emission specifications for the East Texas Combustion Rules is not technically feasible for lean-burn engines. Commenters asserted that controlling lean-burn engines with NSCR in conjunction with an EGR kit was not viable or proven, especially on large bore, slow speed engines. Commenters cited multiple engine manufacturers that stated EGR could not be applied to the lean-burn engines located at their facilities. APC, Devon, ExxonMobil, TIPRO, and TPA commented that EGR is an untested and unproven technology in oil and gas applications as discussed in the Engine Manufacturer's Association position paper of August 2004 entitled "The Use of Exhaust Gas Recirculation (EGR) Systems in Stationary Natural Gas Engines." Westlake added that representatives from manufacturers have all communicated to Westlake that EGR technology is technically infeasible with Westlake's engines, and that EGR is only applicable for lean-burn diesel engines. Both Eastman and Westlake commented that a number of the lean-burn engines located at their facilities were GMX-type engines and that Low Emission Combustion (LEC) modifications on GMX-type engines would be unprecedented.

Eastman and Westlake suggested the commission reevaluate inclusion of lean-burn engines in the East Texas Combustion Rules because the actual cost of compliance far exceeds the cost estimates provided by the commission. Eastman and Westlake cited that multiple engine manufacturers have examined their two-cycle lean-burn engines and have quoted cost figures of approximately $1 million per engine for clean/lean-burn technology or replacement with electric motors. Westlake commented that this would result in a total cost of $17 million for just their 17 engines as compared to the commission's estimate of $20.5 million to $81.3 million for all 297 lean-burn engines in the Northeast Texas area. The commenters asserted that the actual cost to control NO _X emissions from two-cycle lean-burn engines is in the range of $10,000 per ton of NO_X reduced, far exceeding the commission's estimated cost per ton.

Westlake commented that due to the high cost of retrofitting and/or replacing existing engines, it is very likely that some of the eight reactor lines at their Polyethylene No. 1 facility at the Longview plant would be shut down if the East Texas Combustion Rule is implemented as proposed. Shutting down a portion of the eight reactor lines would result in the loss of jobs, both directly and indirectly. Westlake commented that the Polyethylene No. 1 facility employs approximately 100 people directly and the facility feeds product to two other operating areas on the Longview site that employ an additional 75 people. Westlake added that the majority of the emissions in this area result from operation of the four-cycle engines, which could be converted more economically.

Eastman and Westlake also commented that using SCR to control NO _X emissions from lean-burn, large-bore, slow-speed engines was impractical due to space constraints, marginal exhaust gas temperatures, short catalyst life on two-cycle engines, and the fact that no engine manufacturers will guarantee the performance of the SCR systems. In addition, the commenters added that in a June 11, 2003, Northeast Texas Air Care (NETAC) report it states that ". . .retrofit with SCR equipment is not recommended as the 2-cycle design results in much higher contaminant concentrations in the exhaust, which leads to rapid destruction of the catalyst." Eastman and Westlake commented that because EGR with NSCR as well as SCR are not viable options for Eastman's and Westlake's lean-burn engines, the only alternatives are clean/lean-burn units or replacement with electric motors. The commenters stated that this would be much more expensive than the estimates provided by the commission.

EMA commented that the only viable technology to reduce NO _X emissions from existing lean-burn engines is to add an SCR after-treatment system. EMA stated that such retrofit systems are expensive and significantly affect the capital and operating costs of the system, and in many cases, the addition of an after-treatment system will likely make operation of the engine uneconomical. EMA further stated that the commission should not require existing engines to retrofit with SCR and should provide an exemption for lean-burn engines placed in service before June 2007.

J-W Gathering expressed concern about the cost of complying with the East Texas Combustion emission specifications in §117.3310 since meeting these emission specifications would require all of their lean-burn engines to be replaced with rich-burn engines with catalysts or require the use of electric compressors. TIPRO stated that numerous operators who already use lean-burn engines would have no option but to fully replace them.

PVOG stated the commission did not give proper consideration in the proposal to the cost of or time necessary to retrofit all lean-burn engines affected by the East Texas Combustion Rules. PVOG recommends a grandfathered or tiered program to assist industry in meeting the 2.00 g/hp-hr for lean-burn engines placed into service before June 1, 2007, or that the commission consider revising the East Texas Combustion Rules such that the NO _X emission limit of 2.0 g/hp-hr would only apply to new engines.

APC, Devon, ExxonMobil, TIPRO, and TPA commented that electrification is not an option to replace many if not most of the engines in the 39-county region identified in this rule. These counties are, for the most part, relatively rural counties. It is not possible to consider electric driven engines in these areas because there is no nearby power supply that is large enough to support these engines. The power supply is simply not present in most of these areas and electrification is not an option.

APC, Devon, ExxonMobil, TIPRO, TPA, TXOGA, and XTO all commented that applying controls to small engines is unreliable and unproven. XTO commented that over 80 of their two-cycle lean-burn engines less than 100 hp would have to be replaced to meet the proposed rule because the engines could not be retrofitted to meet the standard. As noted elsewhere in this preamble, the commenters suggested engines less than 240 hp should be exempt from the rule.

TIPRO stated that many small engines are usually located in isolated unstaffed sites where electrification is not feasible. TIPRO stated that the staffing requirements for small operations would be infeasible. TIPRO stated that NSCR is unreliable on engines that do not have constant loads. For most of these engines, no reliable, let alone cost-effective method for compliance exists and producers will have to make a business decision whether to continue operating in the area. TIPRO states that many businesses will be forced to shut down or cut back production given that situation.

J-W Power expressed concern that the NO _X emission specifications in the East Texas Combustion rules are unattainable for some existing units and even some new units with the latest lean-burn technology. J-W Power commented that although some lean-burn engines can meet 0.5 g/hp-hr NO _X emission limit with the proper fuel specifications, such as the Caterpillar model 3600 line, which are greater than 1,700 hp engines. However, these engines cannot be used in rental compression fleets due to the engine size, portability issues, and the inability of the producers to assemble large quantities of gas that require this much horsepower. J-W Power noted that the new lean-burn engines that they expect to receive by June 2007 will only meet NO _X emission specifications of 1.5 g/hp-hr. J-W Power also stated that using SCR or ammonia urea systems for the after-treatment of lean-burn engine exhaust is only economical for large sites and estimated that the cost of using SCR on a 500-1675 hp lean-burn engine is $100,000 for the SCR system and $5,000-$7,000 per month in supplies and maintenance costs.

In addition, J-W Power commented that an internal audit revealed 119 lean-burn engines within the 39-county area, most above 200 hp. While many of these engines meet the 2.0 g/hp-hr standard, J-W Power commented that it would not meet the 1.5 g/hp-hr standard if the engines were moved and it would not be cost-effective to control these engines further. J-W Power indicated that SCR was not a solution for well-head and natural gas gathering compressors and that lean-burn conversion kits will only reduce NO _X emissions to 5.0 g/hp-hr. Furthermore, the manufacturer could take up to 2 to 2.5 years to develop and provide kits. J-W Power suggested the commission consider the consequences of forcing industries to replace the lean-burn technology with rich-burn units because the potential to emit is ten times greater for an out-of-compliance rich-burn engine than for an out-of-compliance lean-burn engine.

J-W Power recommended that all four-cycle four-stroke lean-burn engines manufactured before June 1, 2007, meet NO _X emission specifications of 2.0 g/hp-hr, and that all four-cycle four-stroke lean-burn engines installed after January 1, 2008, meet NO _X emission specifications of 1.5 g/hp-hr. Two-cycle two-stroke lean-burn engines manufactured before June 1, 2007, should be required to meet 5 g/hp-hr, and two-cycle two-stroke lean-burn engines manufactured after that date should be required to meet 2.0 g/hp-hr. The commenter further recommended that engines manufactured and installed after July 1, 2010, should be required to meet 1.0 g/hp-hr NO_X , consistent with the proposed NSPS regulations. J-W Power also recommended these changes for the rules applicable to the Dallas-Fort Worth eight-hour ozone nonattainment area.

TIPRO stated the cost of compliance presents an undue burden and economic hardship on small businesses covered by the proposal. The estimated costs of replacing small engines range from a few hundred thousand dollars to the tens of millions, an extraordinary burden in proportion to budgets for their small operators. The commenter stated the compliance costs will likely force many operators to shut-in production across the region, resulting in a loss of severance tax collections at the state and loss of ad valorem taxes at the local level. TIPRO added that some estimates placed the total cost of the proposed rule at $67,000,000 per one-tenth of a ppb reduction. EOG and XTO commented that the cost of the proposed regulations has been greatly under-estimated by the commission.

EMA and ExxonMobil recommended that the commission adopt the emissions standards for stationary-ignited engines proposed by the EPA in the NSPS regulation. EMA recommended the commission harmonize emissions standards for new engines with the NSPS standards and that this change would provide the most efficient and economical means of assuring emissions reductions from stationary engines. The NO _X limit for both new rich- and lean-burn engines in the NSPS initially is expected to be 2.0 g/hp-hr beginning with new engines in July 2007 with a step down to 1.0 g/hp-hr by July 2010. EMA recommended that the commission consider establishing different emission standards for existing and new rich-burn engines and the new rich-burn engines standards should be set at the same level as the federal NSPS standards.

Based on the numerous adverse comments received regarding gas-fired lean-burn engines, the commission has decided not to include lean-burn engines in the adopted East Texas Combustion rule. The commission estimates that exemption of lean-burn engines will greatly reduce the cost of the East Texas Combustion rule and address commenters' concerns regarding economic impact. The commission may consider including lean-burn engines in the rule at a later date, if necessary.

Rich-Burn Engine Technical Feasibility

J-W Power commented that an internal audit revealed 295 rich-burn engines less than 500 hp producing 5,885 tpy of NO _X , representing approximately 77% of all emissions from their fleet within the 39-county area. If required to meet the 1.0 g/hp-hr standard, J-W Power added that 5,045 tpy reductions in NO _X would be achieved, or approximately an 86% reduction. Based on their estimated cost of $400 per ton, J-W Power concluded that it is reasonable to regulate the small rich-burn engines because these engines represent the majority of emissions from engines, emission reduction systems for these engines are cost-effective, and controlling these engines will have the least impact on natural gas and electricity pricing to the consumer. J-W Power recommended that all four-cycle four-stroke rich-burn engines installed after January 1, 2008, meet NO _X emission specifications of 0.5 g/hp-hr by March 1, 2009.

The commission agrees with the commenter that proposed controls on small rich-burn engines are reasonable and cost-effective. Regarding J-W Power's suggested change, the commission disagrees that all rich-burn engines installed after January 1, 2008, should be required to meet 0.5 g/hp-hr. As discussed elsewhere in this preamble, the commission has exempted rich-burn engines less than 240 hp. While some additional reductions would be possible by requiring rich-burn engines from 240 hp to 499 hp to meet the more stringent 0.5 g/hp-hr standard, the commission has determined that the 1.0 g/hp-hr NO _X emission specification is more appropriate for this smaller size category considering the NO _X emission rate from these engines and the additional costs associated with meeting and maintaining the more stringent specification. No change has been made to the rule based on this comment.

EOG indicated that most or all of their engines in the 50 to 500 hp range affected by the commission's proposal would have to be replaced with electric engines to meet the proposed standard. EOG and XTO stated that the conversion of small rich-burn engines to electricity would place an excessive load on rural electric systems that could not be supported. Operations will incur additional costs for purchase of electricity for these engines. APC commented there are engine and compressor packages that do not support the current technology for air-fuel ratio controllers and/or catalytic converters therefore both the engine and compressor would have to be replaced in order for the facility to continue operating and meet the requirements of the proposed rule. Faulconer commented that adding catalytic converters and gas/air controllers to the compressors running in the affected counties would be uneconomical and resources would be prematurely abandoned because of the economic impact of the proposed rules. XTO commented that most rich-burn engines less than 500 hp are uncontrolled. XTO added that engines 240 - 500 hp could be retrofitted to meet the rules and that XTO's rich-burn engines over 500 hp already meet the requirements in the proposed rule. However, XTO asserted that there is little historical data indicating the practical feasibility and reliability of NSCR on rich-burn engines less than 300 hp. XTO also asserted that NSCR has collateral ammonia emissions and that ammonia is also a precursor to ozone formation.

The commission has decided to exempt rich-burn engines less than 240 hp from the East Texas Combustion rule. As discussed elsewhere, the commission is exempting these smaller rich-burn engines due to the large number of engines that fall under this size range. In addition, based on information provided by HARC Project H68, the commission estimates that more reductions from rich-burn well-head compressor engines will be realized than originally estimated using HARC Project H40. Therefore, the adopted rule will still result in substantial reductions from rich-burn engines 240 hp and larger. The commission may include rich-burn engines less than 240 hp in the East Texas Combustion rule at a later time.

The commission disagrees with the commenters' assertions that rich-burn engines less than 300 hp cannot be retrofitted with NSCR and that there is little data regarding the application of NSCR to small rich-burn engines. Test results from a December 2005 Environ presentation on NO _X emission controls for gas compressor engines demonstrated effective NO _X reductions to 0.5 g/hp-hr and less on rich-burn natural gas-fired engines from 145 to 265 hp. A September 2000 EPA report, Stationary Reciprocating Internal Combustion Engines- Updated Information on NO_X Emissions and Control Techniques , cited demonstrated emissions test data for NSCR-equipped engines down to 25 hp from three California local air pollution agencies. EPA's 1993 Alternative Control Techniques Document- NO _X Emissions from Stationary Reciprocating Internal Combustion Engines provided NSCR-equipped rich-burn engine data down to 80 hp.

Regarding XTO's comment about ammonia emissions from NSCR, NSCR does not require ammonia or urea injection to reduce NO _X emissions; therefore, there would be no risk of increased ammonia emissions from the application of NSCR to rich-burn engines. In addition, while ammonia can result in increased particulate emissions, ammonia is not classified as an ozone precursor.

Monitoring, Testing, Recordkeeping, and Reporting Requirements

EPA suggested adding the word "calibrated" to §117.3335(d)(5), revising the provision to read ". . .the CEMS or PEMS must be installed, calibrated, and operational before conducting testing under this subsection."

The commission does not consider the suggested change necessary. The second sentence of §117.3335(d)(5) makes clear that verification of operational status includes, at a minimum, completion of initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device. No change has been made to the rule based on this comment.

APC, Devon, ExxonMobil, TIPRO, and TPA commented that the proposed rulemaking also imposes significant testing requirements. The commenters expected the cost of testing to be in the range of $3,600 per engine, far higher than the commission's estimates.

The commission does not consider the testing requirements to be a financial burden. The testing requirements in the rule are necessary to ensure that sources are in compliance with the emission limitations and that planned reductions have actually been achieved. Initial testing costs for engines subject to the East Texas Combustion rule were estimated at $3,000 per engine. The commission does not consider the difference between $3,000 and $3,600 to be significant; however, the commission's estimate takes into consideration that the rule allows owners or operators of natural gas-fire engines to use ASTM Method D6522-00 as an alternative to the EPA methods. Because the ASTM method allows the use of portable analyzers, the commission estimated that use of this method would result in some savings due to potentially decreased manpower, equipment setup time, and other testing costs as a result of the using portable analyzers. Based on commission estimates and discussions with testing contractors, the use of ASTM D6522-00 might result in 20 - 30% savings in testing costs as compared to EPA reference method testing.

APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that the averaging time requirements in §117.3310(b) and testing requirements in §117.8000 for three one-hour runs were unnecessary and could potentially interfere with the ability to perform testing within 60 days. The commenters suggested removing the requirements or modifying the provision to mirror §116.512 to specify that the averaging time for initial and biennial compliance must be according to EPA Method 7E or 20. Commenters also expressed concern that the provision in §117.3310(b) might be interpreted to apply to quarterly testing with a portable analyzer.

The commission disagrees with the commenter's assertion that three one-hour test runs are not necessary and could interfere with performing testing within 60 days. Testing over an extended period of time is necessary to ensure a proper average emission is determined. Extremely short testing periods could result in over or under-estimated emissions and potentially represent inaccurate compliance status. EPA Methods 7E and 20 do not specify an averaging time; therefore, the commenter's suggested change would only create uncertainty in the averaging time for compliance with the emission limitations and potentially result in inequitable enforcement of standards. The provision in §117.3310(b), which specifies the averaging time for compliance with the emission specifications in §117.3310(a) are on a block one-hour average basis, does not apply to the quarterly testing required under §117.3330(b)(3) and §117.8140(b) because the quarterly testing is not a demonstration of compliance with the emission specification. The quarterly checks for proper operation under §117.8140(b) are qualitative checks not designed to demonstrate compliance or noncompliance with the emission specifications. Data from quarterly checks that indicates potential noncompliance should be investigated by the owner or operator and, if necessary, followed up by retesting using compliance methods as specified in §117.3335(d)(7).

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA suggested that the monitoring and testing requirements for the East Texas Combustion rule should be located in that subchapter and not referenced in rules applicable to sources within the nonattainment counties.

The commission disagrees with the commenters. The testing, monitoring, and reporting requirements in Subchapter G were taken from rule sections of the previous format that were frequently cross-referenced by other parts rather than repeating the same requirements in different divisions and subchapters. While the reformatting has increased clarity and readability of the rule by creating regionally based divisions, this has also resulted in some duplication of rule language. The commission decided to move the testing, monitoring, and reporting requirements that were most commonly cross-referenced to a general location, Subchapter G, and reference the requirement when necessary to help minimize rule language duplication. No change has been made to the rule based on this comment.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA commented that CEMS and PEMS are not required by the East Texas Combustion rule, yet the testing provisions refer to CEMS and PEMS. The commenters suggested that the rule language in §117.3335 needed clarification so that it is clear that these rules do not require CEMS or PEMS, but if CEMS or PEMS are used, certain conditions must be met.

The commenters have correctly interpreted that the rules do not require CEMS or PEMS, and the rules already specify that if the owner or operator elects to install CEMS or PEMS, the CEMS or PEMS must meet certain requirements. Therefore, no change to the rule is necessary.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA commented that engines currently on a New Source Review (NSR) test schedule should be allowed to remain on the existing schedule rather than adjust to meet a new uniform schedule imposed by these rules. The commenters suggested that monitoring of these engines should only be required during the second and third calendar quarters as this time of the year reflects the ozone formation season. APC, Devon, ExxonMobil, TIPRO, and TXOGA also added that engines less than 500 hp should not be subject to the quarterly testing requirement. APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that engines less than 500 hp should only have to be tested with a portable analyzer because many of these engines are located at remote locations that may not be accessible to normal testing trailers equipped for performing EPA Method 7E. The commenters suggested that either the East Texas Combustion rule be modified or the testing provisions in §117.8000 be modified to reflect these changes specific to the East Texas Combustion rule.

The commission disagrees with the commenters' suggested change regarding NSR test schedules. There is significant variability in NSR test schedules and some of the schedules may not be suitable for the purposes of this rulemaking. Therefore, the commission declines to make the suggested change. Regarding the commenters' suggested changes to quarterly testing, the commission disagrees that quarterly checks are not necessary on engines less than 500 hp. While not a demonstration of compliance, the requirement for quarterly testing is necessary to ensure proper operation for engines that are subject to the emission limitations of the rule. The quarterly testing will indicate potential problems with engine operation or NO _X control system that might not otherwise be detected until the next biennial test. Because the emission specifications apply all year and not just in ozone season, the commenters' suggestion to only perform quarterly checks during the second and third quarters would not satisfy the intent for the quarterly checks. Regarding the comments about using portable analyzers for engines less than 500 hp, the commission already provided this as an option under the rule. Owners or operators are allowed to use ASTM D6522-00 as an alternative for testing natural-gas fired engines under §117.3335(d)(3). No change has been made to the rule based on these comments.

APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that the title reference to §117.3310 in §117.3335 was a misnomer because the 39-county area represents attainment areas and should simply be compliance demonstration.

The commission disagrees with the commenter that the section title for §117.3310 should be changed. The section title reflects the overall purpose of the rule, which is to assist the Dallas-Fort Worth eight-hour ozone nonattainment area achieve the NAAQS. No change has been made to the rule based on this comment.

APC, Devon, ExxonMobil, TIPRO, and TXOGA requested clarification whether the testing in §117.3335(d)(1) refers to initial, biennial, or quarterly testing.

The testing requirement under §117.3335(d)(1) only applies to initial and biennial testing. The quarterly testing requirement is under §117.3330(b)(3) and by reference §117.8140(b).

APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that the retesting requirement §117.3335(d)(7)(A) is inconsistent with §106.512 which requires retesting within seven days of maintenance or modification that may increase emissions. The commenter also indicated that the rule was inconsistent with §106.512 and §117.8140(b), which state that a portable analyzer or stain tube is sufficient to demonstrate compliance. TXOGA requested that §117.3335(d)(7)(A) be modified to be consistent with §106.512 and §117.8140 because it was not cost-effective or practical to require Method 7E or 20 testing for these types of situations.

Although the commenters expressed interest in imposing a seven-day retesting requirement to be consistent with §106.512, the commission does not consider it appropriate to impose this short time frame on other regulated entities that may have considered the sixty days to be more appropriate.

Recordkeeping

Eastman, PVOG, and Westlake commented that the East Texas Combustion Rules impose additional recordkeeping, monitoring, and reporting requirements that will result in additional manpower and administrative costs and create an economic hardship to industry. PVOG stated that all affected engines in the affected counties, whether they are required to limit emission controls or not, would be subject to testing, which is estimated to cost $10.5 million within the five years. PVOG further commented that a monetary value has not been calculated for the proposed additional recordkeeping requirements, it can be assumed that the additional cost to industry will be high based on all of the certifications and maintenance proposed for a previously unregulated area.

The commission disagrees with the commenters that the recordkeeping costs are an economic hardship. The rules do not specify the format in which records must be maintained. Therefore, regulated entities can maintain records in electronic or paper format. Additionally, costs associated with maintaining minimal recordkeeping to satisfy the rule requirements are inconsequential compared to all other costs associated with this rule. No change has been made to the rule based on this comment.

APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that engines subject to the East Texas Combustion rule should not have to meet the report content requirements of §117.8010, and suggested adding a provision to §117.8010 that exempted engines subject to §117.3310 from those requirements.

The report content requirements of §117.8010 are necessary for commission investigators and emission evaluators to ensure that proper procedures have been followed during compliance testing. Therefore, the commission declines to make the suggested change.

APC, Devon, ExxonMobil, TIPRO, TPA, and TXOGA commented that the recordkeeping and reporting requirements are onerous and should be modified. The commenters suggested the record retention should be for two years and that it would be sufficient to keep the results on the periodic test and quarterly monitoring on site rather than filing them with the commission. APC, Devon, ExxonMobil, TIPRO, and TXOGA commented that the regional offices would be inundated with over 1,000 test reports per quarter.

The commission disagrees with the commenters. The five-year record retention requirement is consistent with similar Chapter 117 rules and is necessary for investigators to assess compliance with the rule, especially considering the biennial periodic testing requirements. Regarding the commenters' assertion that regional offices would be inundated with over 1,000 test reports per quarter, the commenters have misinterpreted the reporting requirements of §117.3345(c). The results of the quarterly testing must be kept on site to satisfy the recordkeeping requirements of §117.3345(a). However, as specified in §117.3345(c), test reports are only required to be submitted for testing conducted under §117.3335, excluding the ammonia testing. The quarterly testing requirement for engines is cited under §117.3330(b)(3). Therefore, the quarterly tests are not subject to the reporting requirements of §117.3345(c). However, the commission has revised §117.3345(c) to specify that testing conducted under §117.3330(b)(3) is subject to the reporting requirements of §117.3345(c) to clarify this intent and avoid potential confusion with the reporting requirements. The commission disagrees with the commenters' suggestion to not require reports for periodic testing. The periodic testing under §117.3335(d)(7) and §117.8140(a) is performed on a biennial basis or every 15,000 hours of operation. Review of these periodic test reports is necessary to ensure on-going compliance with the rule and does not place an undue burden on commission staff or the regulated community.

COMPLIANCE SCHEDULES

Major Sources

Acme and AMT requested that, if the commission determines not to modify the proposed regulations for major source brick and ceramic kilns as requested by the commenters, the compliance date be delayed from March 1, 2009. The commenters asserted that further research and development was necessary before controls could be applied to brick and ceramic kilns. Due to the possibility that the EPA could delay the Dallas-Fort Worth eight-hour ozone nonattainment area deadline to 2013, Acme and AMT suggested a compliance date of the latter of March 1, 2012, or the date EPA formally approves the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP.

The commission agrees that some additional time will be necessary for some sources to comply with the requirements of the adopted rule. However, the current attainment date for the Dallas-Fort Worth eight-hour ozone nonattainment area is June 15, 2010. Controls must be implemented prior to the attainment date to benefit the area in reaching the NAAQS. As discussed elsewhere in this preamble, the compliance schedule for major sources in §117.9030 has been revised to provide some sources additional time by extending the compliance date to March 1, 2010. Brick and ceramic kilns are included in those source categories that will have until March 1, 2010.

Cement Kilns

Holcim stated that the March 1, 2009, compliance date is unachievable unless the source cap is modified or other compliance options, such as SNCR, are provided. PCA and TXI asserted that the proposed compliance date of March 1, 2009, is infeasible, unless the source cap is changed to enable SNCR and exceptions are made in the case of a contested case hearing, technical infeasibility, or severe economic hardship.

While a contested case hearing is unlikely in the case of the cement kilns subject to this rulemaking due to the nature of the controls likely to be used, the commission agrees that the possibility of a contested case hearing exists. The commission has revised the compliance schedule in §117.9320(c) to include a provision that extends the compliance date until March 1, 2010. This provision can only be triggered if a contested case hearing is granted as a direct result of a permit application necessary for compliance with the source cap in §117.3123 and only extends the compliance date for the site affected by the contested case hearing. In addition, the compliance date is not extended if the contested case hearing is granted at the request of the owner or operator of the affected portland cement kiln or any third party affiliated with the owner or operator. The commission disagrees with the suggestion that exceptions should be provided based on technical feasibility or economic hardship. As discussed elsewhere in this preamble, the level of control for the adopted source cap approach has been determined to be technically and economically feasible. Furthermore, providing such compliance exceptions would endanger EPA approvability of the Dallas-Fort Worth eight-hour ozone attainment demonstration SIP.

Downwinders stated that March 2009 is an arbitrary deadline and that EPA would probably allow more time if SCR pilot testing results looked promising.

Regarding the March 2009 compliance deadline, while the commission agrees that EPA may have some flexibility regarding the requirement to have controls installed at the beginning of the ozone season immediately prior to the attainment date, controls must still be implemented in time to help advance attainment by the attainment date of June 15, 2010. The goal of this is rulemaking to achieve NO _X reductions necessary for the Dallas-Fort Worth eight-hour ozone nonattainment area to demonstrate attainment with the NAAQS. The commission does not agree that it would be appropriate to delay reductions that could be achieved by the attainment date based on the possibility of more reductions after the attainment date.

East Texas Combustion

APC, Eastman, EOG, J-W Gathering, PVOG, TIPRO, TPA, TXOGA, Westlake, and XTO commented that the proposed East Texas Combustion rule has an unrealistic compliance deadline. Commenters indicated that much of the regulated community would not be able to comply with the March 1, 2009, compliance deadline because it does not provide sufficient time for companies to engineer, budget, order, install control technology, and perform testing. Possible permitting requirements may be necessary that could cause further time delays. Commenters also indicated that although the installation timeline is not generally very lengthy, with the increase in demand driven by this rule, manufacturers of this equipment will be stretched to meet orders in time for industry-wide compliance. In addition to the time needed for implementing controls on existing engines, the commenters indicated that the current backlog for new engines and increased demand resulting from this rule would delay replacement of affected engines that could not be retrofitted to meet the emission standards.

APC and PVOG suggested allowing staggered compliance dates which could possibly be more feasible to obtain compliance. In addition, TPA members are finding that not only the engine, but the compressor may also have to be replaced as an engine may not be available that will fit the existing compressor, thus further complicating the ability to meet the compliance deadline. TPA further commented that the availability of controls for smaller rich-burn engines is unknown, particularly for engines of less than 240 hp.

The commission agrees that additional time will be necessary for sources to comply with the East Texas Combustion rule. Therefore, the compliance schedule in §117.9340 is revised to specify that owners or operators must comply with the requirement of the rule as soon as practicable but no later than March 1, 2010. Because the adopted East Texas Combustion rule only applies to rich-burn engines 240 hp and greater, the additional year is sufficient to allow owners and operators time to install controls as necessary and comply with all other requirements of the rule.

Eastman, TPA, and Westlake commented that it may be unreasonable to require emission testing within 60 days of the compliance date, after controls are installed, or replacement of engines since there are a limited number of testing companies available to perform these tests. TPA added that the increase in the number of tests that must be performed to meet this rule in a collapsed time frame will create a dramatic strain on the existing companies. TPA stated it may be virtually impossible to complete all the tests required in this region by the regulatory deadline for these tests.

Regarding the commenters' concerns with completing all testing by the proposed compliance date, as discussed elsewhere in this preamble, the commission has revised the compliance schedule in §117.9340 to be March 1, 2010. In addition, regarding the comment about testing engines within 60 days of installing controls or replacement engines, the 60 day requirement in §117.9340(b) only applies to engines that become subject to the rule after March 1, 2010. Owners or operators should be able to adequately identify these events prior to actually triggering the provision. Therefore, the 60 days allowed in §117.9340(b) after triggering the provision should be adequate. On newly installed engines, the owner or operator should identify those controls necessary prior to installing the engine.

TXOGA suggested changes to §117.3310(a) or §117.9340(a) to address a potential contradiction between the June 1, 2007, date used in §117.3310(a) and the compliance date in §117.9340. The commenter also requested that a provision be added to §117.9340 that allowed the executive director to approve an alternative compliance date for an engine that could not meet the specified compliance date. The provision would require the owner or operator to submit a petition to the executive director that included a justification for an alternative compliance date.

The commission disagrees that there is a contradiction between §117.3310(a) and §117.9340(a); however, because the adopted rule does not apply to lean-burn engines, the date reference to June 1, 2007, has been removed from the rule. In addition, the suggested change of including a provision allowing owners or operators to petition the executive director for an extended compliance date would erode enforceability of the rule and could endanger EPA approvability. No change has been made to the rule based on this comment.

TXOGA requested clarification that the provision in §117.9340(b) only applies to new engines placed into service on or after March 1, 2009.

The commission disagrees with the commenter's interpretation of §117.9340(b). Section 117.9340(b) would apply to new engines placed into service on or after March 1, 2010; however, this provision would also apply to existing engines that lost exemption status or otherwise became subject to the rule. As discussed elsewhere in this preamble, the commission has revised the compliance date in §117.9340 to March 1, 2010.

Subchapter A. DEFINITIONS

30 TAC §117.10

STATUTORY AUTHORITY

The repeal is adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the repeal is adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382.

The repeal implements Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702038

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter B. COMBUSTION AT MAJOR SOURCES

1. UTILITY ELECTRIC GENERATION IN OZONE NONATTAINMENT AREAS

30 TAC §§117.101, 117.103, 117.105 - 117.111, 117.113 - 117.117, 117.119, 117.121

STATUTORY AUTHORITY

The repeals are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the repeals are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382.

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702039

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. UTILITY ELECTRIC GENERATION IN EAST AND CENTRAL TEXAS

30 TAC §§117.131, 117.133 - 117.135, 117.138, 117.139, 117.141, 117.143, 117.145, 117.147, 117.149, 117.151

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702040

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL COMBUSTION SOURCES IN OZONE NONATTAINMENT AREAS

30 TAC §§117.201, 117.203, 117.205 - 117.211, 117.213 - 117.217, 117.219, 117.221, 117.223

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702041

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

4. CEMENT KILNS

30 TAC §§117.260, 117.261, 117.265, 117.273, 117.279, 117.283

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702042

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter C. ACID MANUFACTURING

1. ADIPIC ACID MANUFACTURING

30 TAC §§117.301, 117.305, 117.309, 117.311, 117.313, 117.319, 117.321

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702043

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. NITRIC ACID MANUFACTURING--OZONE NONATTAINMENT AREAS

30 TAC §§117.401, 117.405, 117.409, 117.411, 117.413, 117.419, 117.421

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702044

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. NITRIC ACID MANUFACTURING--GENERAL

30 TAC §§117.451, 117.455, 117.458

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702045

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter D. SMALL COMBUSTION SOURCES

1. WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

30 TAC §§117.460, 117.461, 117.463, 117.465, 117.467, 117.469

STATUTORY AUTHORITY

The repeals are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, that authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the repeals are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. The repeals are adopted to implement the legislative mandate under House Bill (HB) 965, 79th Legislature, 2005, which adds Texas Health and Safety Code, §382.0275, concerning Commission Action Relating to Residential Water Heaters, which requires certain actions of the commission regarding residential water heaters.

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, and 382.0275.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702046

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. BOILERS, PROCESS HEATERS, AND STATIONARY ENGINES AND GAS TURBINES AT MINOR SOURCES

30 TAC §§117.471, 117.473, 117.475, 117.478, 117.479, 117.481

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702047

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter E. ADMINISTRATIVE PROVISIONS

30 TAC §§117.510, 117.512, 117.520, 117.524, 117.530, 117.534, 117.570, 117.571

STATUTORY AUTHORITY

The repeals implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702048

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter A. DEFINITIONS

30 TAC §117.10

STATUTORY AUTHORITY

The new section is adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the section is adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new section is adopted under federal mandates contained in 42 United States Code, §§7401 et seq ., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted section implements Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.10.Definitions.

Unless specifically defined in the Texas Clean Air Act or Chapter 101 of this title (relating to General Air Quality Rules), the terms in this chapter have the meanings commonly used in the field of air pollution control. Additionally, the following meanings apply, unless the context clearly indicates otherwise. Additional definitions for terms used in this chapter are found in §3.2 and §101.1 of this title (relating to Definitions).

(1) Annual capacity factor--The total annual fuel consumed by a unit divided by the fuel that could be consumed by the unit if operated at its maximum rated capacity for 8,760 hours per year.

(2) Applicable ozone nonattainment area--The following areas, as designated under the 1990 Federal Clean Air Act Amendments.

(A) Beaumont-Port Arthur ozone nonattainment area--An area consisting of Hardin, Jefferson, and Orange Counties.

(B) Dallas-Fort Worth ozone nonattainment area--An area consisting of Collin, Dallas, Denton, and Tarrant Counties.

(C) Dallas-Fort Worth eight-hour ozone nonattainment area--An area consisting of Collin, Dallas, Denton, Ellis, Johnson, Kaufman, Parker, Rockwall, and Tarrant Counties.

(D) Houston-Galveston-Brazoria ozone nonattainment area--An area consisting of Brazoria, Chambers, Fort Bend, Galveston, Harris, Liberty, Montgomery, and Waller Counties.

(3) Auxiliary steam boiler--Any combustion equipment within an electric power generating system, as defined in this section, that is used to produce steam for purposes other than generating electricity. An auxiliary steam boiler produces steam as a replacement for steam produced by another piece of equipment that is not operating due to planned or unplanned maintenance.

(4) Average activity level for fuel oil firing--The product of an electric utility unit's maximum rated capacity for fuel oil firing and the average annual capacity factor for fuel oil firing for the period from January 1, 1990, to December 31, 1993.

(5) Block one-hour average--An hourly average of data, collected starting at the beginning of each clock hour of the day and continuing until the start of the next clock hour.

(6) Boiler--Any combustion equipment fired with solid, liquid, and/or gaseous fuel used to produce steam or to heat water.

(7) Btu--British thermal unit.

(8) Chemical processing gas turbine--A gas turbine that vents its exhaust gases into the operating stream of a chemical process.

(9) Continuous emissions monitoring system (CEMS)--The total equipment necessary for the continuous determination and recordkeeping of process gas concentrations and emission rates in units of the applicable emission limitation.

(10) Daily--A calendar day starting at midnight and continuing until midnight the following day.

(11) Diesel engine--A compression-ignited two- or four-stroke engine that liquid fuel injected into the combustion chamber ignites when the air charge has been compressed to a temperature sufficiently high for auto-ignition.

(12) Duct burner--A unit that combusts fuel and that is placed in the exhaust duct from another unit (such as a stationary gas turbine, stationary internal combustion engine, kiln, etc.) to allow the firing of additional fuel to heat the exhaust gases.

(13) Electric generating facility (EGF)--A unit that generates electric energy for compensation and is owned or operated by a person doing business in this state, including a municipal corporation, electric cooperative, or river authority.

(14) Electric power generating system--One electric power generating system consists of either:

(A) for the purposes of Subchapter C of this chapter (relating to Combustion Control at Major Utility Electric Generation Sources in Ozone Nonattainment Areas), all boilers, auxiliary steam boilers, and stationary gas turbines (including duct burners used in turbine exhaust ducts) at electric generating facility (EGF) accounts that generate electric energy for compensation; are owned or operated by an electric cooperative, municipality, river authority, public utility, or a Public Utility Commission of Texas regulated utility, or any of its successors; and are entirely located in one of the following ozone nonattainment areas:

(i) Beaumont-Port Arthur;

(ii) Dallas-Fort Worth;

(iii) Dallas-Fort Worth eight-hour; or

(iv) Houston-Galveston-Brazoria;

(B) for the purposes of Subchapter E, Division 1 of this chapter (relating to Utility Electric Generation in East and Central Texas), all boilers, auxiliary steam boilers, and stationary gas turbines at EGF accounts that generate electric energy for compensation; are owned or operated by an electric cooperative, independent power producer, municipality, river authority, or public utility, or any of its successors; and are located in Atascosa, Bastrop, Bexar, Brazos, Calhoun, Cherokee, Fannin, Fayette, Freestone, Goliad, Gregg, Grimes, Harrison, Henderson, Hood, Hunt, Lamar, Limestone, Marion, McLennan, Milam, Morris, Nueces, Parker, Red River, Robertson, Rusk, Titus, Travis, Victoria, or Wharton County; or

(C) for the purposes of Subchapter B of this chapter (relating to Combustion Control at Major Industrial, Commercial, and Institutional Sources in Ozone Nonattainment Areas), all units in the Houston-Galveston-Brazoria ozone nonattainment area that generate electricity but do not meet the conditions specified in subparagraph (A) of this paragraph, including, but not limited to, cogeneration units and units owned by independent power producers.

(15) Emergency situation--As follows.

(A) An emergency situation is any of the following:

(i) an unforeseen electrical power failure from the serving electric power generating system;

(ii) the period of time that an emergency notice, as defined in ERCOT Protocols, Section 2: Definitions and Acronyms (April 25, 2006), issued by the Electric Reliability Council of Texas, Inc. (ERCOT) as specified in ERCOT Protocols, Section 5: Dispatch (April 26, 2006), is applicable to the serving electric power generating system. The emergency situation is considered to end upon expiration of the emergency notice issued by ERCOT;

(iii) an unforeseen failure of on-site electrical transmission equipment (e.g., a transformer);

(iv) an unforeseen failure of natural gas service;

(v) an unforeseen flood or fire, or a life-threatening situation; or

(vi) operation of emergency generators for Federal Aviation Administration licensed airports, military airports, or manned space flight control centers for the purposes of providing power in anticipation of a power failure due to severe storm activity.

(B) An emergency situation does not include operation for purposes of supplying power for distribution to the electric grid, operation for training purposes, or other foreseeable events.

(16) Functionally identical replacement--A unit that performs the same function as the existing unit that it replaces, with the condition that the unit replaced must be physically removed or rendered permanently inoperable before the unit replacing it is placed into service.

(17) Heat input--The chemical heat released due to fuel combustion in a unit, using the higher heating value of the fuel. This does not include the sensible heat of the incoming combustion air. In the case of carbon monoxide (CO) boilers, the heat input includes the enthalpy of all regenerator off-gases and the heat of combustion of the incoming CO and of the auxiliary fuel. The enthalpy change of the fluid catalytic cracking unit regenerator off-gases refers to the total heat content of the gas at the temperature it enters the CO boiler, referring to the heat content at 60 degrees Fahrenheit, as being zero.

(18) Heat treat furnace--A furnace that is used in the manufacturing, casting, or forging of metal to heat the metal so as to produce specific physical properties in that metal.

(19) High heat release rate--A ratio of boiler design heat input to firebox volume (as bounded by the front firebox wall where the burner is located, the firebox side waterwall, and extending to the level just below or in front of the first row of convection pass tubes) greater than or equal to 70,000 British thermal units per hour per cubic foot.

(20) Horsepower rating--The engine manufacturer's maximum continuous load rating at the lesser of the engine or driven equipment's maximum published continuous speed.

(21) Incinerator--As follows.

(A) For the purposes of this chapter, the term "incinerator" includes both of the following:

(i) a control device that combusts or oxidizes gases or vapors (e.g., thermal oxidizer, catalytic oxidizer, vapor combustor); and

(ii) an incinerator as defined in §101.1 of this title (relating to Definitions).

(B) The term "incinerator" does not apply to boilers or process heaters as defined in this section, or to flares as defined in §101.1 of this title.

(22) Industrial boiler--Any combustion equipment, not including utility or auxiliary steam boilers as defined in this section, fired with liquid, solid, or gaseous fuel, that is used to produce steam or to heat water.

(23) International Standards Organization (ISO) conditions--ISO standard conditions of 59 degrees Fahrenheit, 1.0 atmosphere, and 60% relative humidity.

(24) Large utility system--All boilers, auxiliary steam boilers, and stationary gas turbines that are located in the Dallas-Fort Worth or the Dallas-Fort Worth eight-hour ozone nonattainment area, and were part of one electric power generating system on January 1, 2000, that had a combined electric generating capacity equal to or greater than 500 megawatts.

(25) Lean-burn engine--A spark-ignited or compression-ignited, Otto cycle, diesel cycle, or two-stroke engine that is not capable of being operated with an exhaust stream oxygen concentration equal to or less than 0.5% by volume, as originally designed by the manufacturer.

(26) Low annual capacity factor boiler, process heater, or gas turbine supplemental waste heat recovery unit--An industrial, commercial, or institutional boiler; process heater; or gas turbine supplemental waste heat recovery unit with maximum rated capacity:

(A) greater than or equal to 40 million British thermal units per hour (MMBtu/hr), but less than 100 MMBtu/hr and an annual heat input less than or equal to 2.8 (10 ¹¹ ) British thermal units per year (Btu/yr), based on a rolling 12-month average; or

(B) greater than or equal to 100 MMBtu/hr and an annual heat input less than or equal to 2.2 (10 ¹¹ ) Btu/yr, based on a rolling 12-month average.

(27) Low annual capacity factor stationary gas turbine or stationary internal combustion engine--A stationary gas turbine or stationary internal combustion engine that is demonstrated to operate less than 850 hours per year, based on a rolling 12-month average.

(28) Low heat release rate--A ratio of boiler design heat input to firebox volume less than 70,000 British thermal units per hour per cubic foot.

(29) Major source--Any stationary source or group of sources located within a contiguous area and under common control that emits or has the potential to emit:

(A) at least 50 tons per year (tpy) of nitrogen oxides (NO_X ) and is located in the Beaumont-Port Arthur ozone nonattainment area;

(B) at least 50 tpy of NO _X and is located in the Dallas-Fort Worth or Dallas-Fort Worth eight-hour ozone nonattainment area;

(D) the amount specified in the major source definition contained in the Prevention of Significant Deterioration of Air Quality regulations promulgated by the United States Environmental Protection Agency in 40 Code of Federal Regulations §52.21 as amended June 3, 1993 (effective June 3, 1994), and is located in Atascosa, Bastrop, Bexar, Brazos, Calhoun, Cherokee, Comal, Fannin, Fayette, Freestone, Goliad, Gregg, Grimes, Harrison, Hays, Henderson, Hood, Hunt, Lamar, Limestone, Marion, McLennan, Milam, Morris, Nueces, Red River, Robertson, Rusk, Titus, Travis, Victoria, or Wharton County.

(30) Maximum rated capacity--The maximum design heat input, expressed in million British thermal units per hour, unless:

(A) the unit is a boiler, utility boiler, or process heater operated above the maximum design heat input (as averaged over any one-hour period), in which case the maximum operated hourly rate must be used as the maximum rated capacity; or

(B) the unit is limited by operating restriction or permit condition to a lesser heat input, in which case the limiting condition must be used as the maximum rated capacity; or

(C) the unit is a stationary gas turbine, in which case the manufacturer's rated heat consumption at the International Standards Organization (ISO) conditions must be used as the maximum rated capacity, unless limited by permit condition to a lesser heat input, in which case the limiting condition must be used as the maximum rated capacity; or

(D) the unit is a stationary, internal combustion engine, in which case the manufacturer's rated heat consumption at Diesel Equipment Manufacturer's Association or ISO conditions must be used as the maximum rated capacity, unless limited by permit condition to a lesser heat input, in which case the limiting condition must be used as the maximum rated capacity.

(31) Megawatt (MW) rating--The continuous MW output rating or mechanical equivalent by a gas turbine manufacturer at International Standards Organization conditions, without consideration to the increase in gas turbine shaft output and/or the decrease in gas turbine fuel consumption by the addition of energy recovered from exhaust heat.

(32) Nitric acid--Nitric acid that is 30% to 100% in strength.

(33) Nitric acid production unit--Any source producing nitric acid by either the pressure or atmospheric pressure process.

(34) Nitrogen oxides (NO _X )--The sum of the nitric oxide and nitrogen dioxide in the flue gas or emission point, collectively expressed as nitrogen dioxide.

(35) Parts per million by volume (ppmv)--All ppmv emission specifications specified in this chapter are referenced on a dry basis. When required to adjust pollutant concentrations to a specified oxygen (O₂ ) correction basis, the following equation must be used.

Figure: 30 TAC §117.10(35)

(36) Peaking gas turbine or engine--A stationary gas turbine or engine used intermittently to produce energy on a demand basis.

(37) Plant-wide emission rate--The ratio of the total actual nitrogen oxides mass emissions rate discharged into the atmosphere from affected units at a major source when firing at their maximum rated capacity to the total maximum rated capacities for those units.

(38) Plant-wide emission specification--The ratio of the total allowable nitrogen oxides mass emissions rate dischargeable into the atmosphere from affected units at a major source when firing at their maximum rated capacity to the total maximum rated capacities for those units.

(39) Predictive emissions monitoring system (PEMS)--The total equipment necessary for the continuous determination and recordkeeping of process gas concentrations and emission rates using process or control device operating parameter measurements and a conversion equation or computer program to produce results in units of the applicable emission limitation.

(40) Process heater--Any combustion equipment fired with liquid and/or gaseous fuel that is used to transfer heat from combustion gases to a process fluid, superheated steam, or water for the purpose of heating the process fluid or causing a chemical reaction. The term "process heater" does not apply to any unfired waste heat recovery heater that is used to recover sensible heat from the exhaust of any combustion equipment, or to boilers as defined in this section.

(41) Pyrolysis reactor--A unit that produces hydrocarbon products from the endothermic cracking of feedstocks such as ethane, propane, butane, and naphtha using combustion to provide indirect heating for the cracking process.

(42) Reheat furnace--A furnace that is used in the manufacturing, casting, or forging of metal to raise the temperature of that metal in the course of processing to a temperature suitable for hot working or shaping.

(43) Rich-burn engine--A spark-ignited, Otto cycle, four-stroke, naturally aspirated or turbocharged engine that is capable of being operated with an exhaust stream oxygen concentration equal to or less than 0.5% by volume, as originally designed by the manufacturer.

(44) Small utility system--All boilers, auxiliary steam boilers, and stationary gas turbines that are located in the Dallas-Fort Worth or the Dallas-Fort Worth eight-hour ozone nonattainment area, and were part of one electric power generating system on January 1, 2000, that had a combined electric generating capacity less than 500 megawatts.

(45) Stationary gas turbine--Any gas turbine system that is gas and/or liquid fuel fired with or without power augmentation. This unit is either attached to a foundation or is portable equipment operated at a specific minor or major source for more than 90 days in any 12-month period. Two or more gas turbines powering one shaft must be treated as one unit.

(46) Stationary internal combustion engine--A reciprocating engine that remains or will remain at a location (a single site at a building, structure, facility, or installation) for more than 12 consecutive months. Included in this definition is any engine that, by itself or in or on a piece of equipment, is portable, meaning designed to be and capable of being carried or moved from one location to another. Indicia of portability include, but are not limited to, wheels, skids, carrying handles, dolly, trailer, or platform. Any engine (or engines) that replaces an engine at a location and that is intended to perform the same or similar function as the engine being replaced is included in calculating the consecutive residence time period. An engine is considered stationary if it is removed from one location for a period and then returned to the same location in an attempt to circumvent the consecutive residence time requirement. Nonroad engines, as defined in 40 Code of Federal Regulations §89.2, are not considered stationary for the purposes of this chapter.

(47) System-wide emission rate--The ratio of the total actual nitrogen oxides mass emissions rate discharged into the atmosphere from affected units in an electric power generating system or portion thereof located within a single ozone nonattainment area when firing at their maximum rated capacity to the total maximum rated capacities for those units. For fuel oil firing, average activity levels must be used in lieu of maximum rated capacities for the purpose of calculating the system-wide emission rate.

(48) System-wide emission specification--The ratio of the total allowable nitrogen oxides mass emissions rate dischargeable into the atmosphere from affected units in an electric power generating system or portion thereof located within a single ozone nonattainment area when firing at their maximum rated capacity to the total maximum rated capacities for those units. For fuel oil firing, average activity levels must be used in lieu of maximum rated capacities for the purpose of calculating the system-wide emission specification.

(49) Thirty-day rolling average--An average, calculated for each day that fuel is combusted in a unit, of all the hourly emissions data for the preceding 30 days that fuel was combusted in the unit.

(50) Twenty-four hour rolling average--An average, calculated for each hour that fuel is combusted (or acid is produced, for a nitric or adipic acid production unit), of all the hourly emissions data for the preceding 24 hours that fuel was combusted in the unit.

(51) Unit--A unit consists of either:

(A) for the purposes of §§117.105, 117.205, 117.305, 117.1005, 117.1105, and 117.1205 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)) and each requirement of this chapter associated with §§117.105, 117.205, 117.305, 117.1005, 117.1105, and 117.1205 of this title, any boiler, process heater, stationary gas turbine, or stationary internal combustion engine, as defined in this section;

(B) for the purposes of §§117.110, 117.210, 117.310, 117.1010, 117.1110, and 117.1210 of this title (relating to Emission Specifications for Attainment Demonstration) and each requirement of this chapter associated with §§117.110, 117.210, 117.310, 117.1010, 117.1110, and 117.1210 of this title, any boiler, process heater, stationary gas turbine, or stationary internal combustion engine, as defined in this section, or any other stationary source of nitrogen oxides (NO _X ) at a major source, as defined in this section;

(C) for the purposes of §117.2010 of this title (relating to Emission Specifications) and each requirement of this chapter associated with §117.2010 of this title, any boiler, process heater, stationary gas turbine (including any duct burner in the turbine exhaust duct), or stationary internal combustion engine, as defined in this section;

(D) for the purposes of §117.2110 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) and each requirement of this chapter associated with §117.2110 of this title, any stationary internal combustion engine, as defined in this section;

(E) for the purposes of §117.3310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) and each requirement of this chapter associated with §117.3310 of this title, any stationary internal combustion engine, as defined in this section; or

(F) for the purposes of §117.410 and §117.1310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) and each requirement of this chapter associated with §117.410 and §117.1310 of this title, any boiler, process heater, stationary gas turbine, or stationary internal combustion engine, as defined in this section, or any other stationary source of NO _X at a major source, as defined in this section.

(52) Utility boiler--Any combustion equipment owned or operated by an electric cooperative, municipality, river authority, public utility, or Public Utility Commission of Texas regulated utility, fired with solid, liquid, and/or gaseous fuel, used to produce steam for the purpose of generating electricity. Stationary gas turbines, including any associated duct burners and unfired waste heat boilers, are not considered to be utility boilers.

(53) Wood--Wood, wood residue, bark, or any derivative fuel or residue thereof in any form, including, but not limited to, sawdust, sander dust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702049

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter B. COMBUSTION CONTROL AT MAJOR INDUSTRIAL, COMMERCIAL, AND INSTITUTIONAL SOURCES IN OZONE NONATTAINMENT AREAS

1. BEAUMONT-PORT ARTHUR OZONE NONATTAINMENT AREA MAJOR SOURCES

30 TAC §§117.100, 117.103, 117.105, 117.110, 117.115, 117.123, 117.125, 117.130, 117.135, 117.140, 117.145, 117.150, 117.152, 117.154, 117.156

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq ., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.123.Source Cap.

(a) An owner or operator may achieve compliance with the nitrogen oxides (NO _X ) emission specifications of §117.105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)) or §117.110 of this title (relating to Emission Specifications for Attainment Demonstration), by achieving equivalent NO_X emission reductions obtained by compliance with a source cap emission limitation in accordance with the requirements of this section. Each equipment category at a source whose individual emission units would otherwise be subject to the NO _X emission specifications of §117.105 or §117.110 of this title may be included in the source cap. Any equipment category included in the source cap must include all emission units belonging to that category. Equipment categories include, but are not limited to, the following: steam generation, electrical generation, and units with the same product outputs, such as ethylene cracking furnaces. All emission units not included in the source cap must comply with the requirements of §117.105 or §117.110 of this title, or §117.115 of this title (relating to Alternative Plant-Wide Emission Specifications).

(b) The source cap allowable mass emission rate must be calculated as follows.

(1) A rolling 30-day average emission cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.123(b)(1)

(2) A maximum daily cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.123(b)(2)

(3) Each emission unit included in the source cap is subject to the requirements of both paragraphs (1) and (2) of this subsection at all times.

(4) The owner or operator at its option may include any of the entire classes of exempted units listed in §117.115(f) of this title in a source cap. For compliance with §117.105(a)- (d) of this title, such units are required to reduce emissions available for use in the cap by an additional amount calculated in accordance with the United States Environmental Protection Agency's proposed Economic Incentive Program rules for offset ratios for trades between RACT and non-RACT sources, as published in the February 23, 1993, Federal Register (58 FR 11110).

(5) For stationary internal combustion engines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.115(g)(2) of this title.

(6) For stationary gas turbines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.115(g)(3) of this title.

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous exhaust NO _X monitor, carbon monoxide (CO) monitor, an oxygen (O ₂ ) (or carbon dioxide (CO ₂ )) diluent monitor, and a totalizing fuel flow meter in accordance with the requirements of §117.140 of this title (relating to Continuous Demonstration of Compliance). The required continuous emissions monitoring systems (CEMS) and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel use for each affected unit and must be used to demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive emissions monitoring system (PEMS) and a totalizing fuel flow meter in accordance with the requirements of §117.140 of this title. The required PEMS and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel flow for each affected unit and must be used to demonstrate continuous compliance with the source cap; or

(C) for units not subject to continuous monitoring requirements and units belonging to the equipment classes listed in §117.115(f) of this title, the owner or operator may use the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.135(e) of this title (relating to Initial Demonstration of Compliance) in lieu of CEMS or PEMS. Emission rates for these units are limited to the maximum emission rates obtained from testing conducted under §117.135(e) of this title; and

(2) for each operating unit equipped with CEMS, either use a PEMS in accordance with §117.140 of this title, or the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.135(e) of this title, to provide emissions compliance data during periods when the CEMS is off-line. The methods specified in 40 Code of Federal Regulations §75.46 must be used to provide emissions substitution data for units equipped with PEMS.

(d) The owner or operator of any units subject to a source cap shall maintain daily records indicating the NO _X emissions from each source and the total fuel usage for each unit and include a total NO _X emissions summation and total fuel usage for all units under the source cap on a daily basis. Records must also be retained in accordance with §117.145 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

(e) The owner or operator of any units operating under this provision shall report any exceedance of the source cap emission limit within 48 hours to the appropriate regional office. The owner or operator shall then follow up within 21 days of the exceedance with a written report that includes an analysis of the cause for the exceedance with appropriate data to demonstrate the amount of emissions in excess of the applicable limit and the necessary corrective actions taken by the company to assure future compliance. Additionally, the owner or operator shall submit semiannual reports for the monitoring systems in accordance with §117.145 of this title.

(f) The owner or operator shall demonstrate initial compliance with the source cap in accordance with the schedule specified in §117.9000 of this title (relating to Compliance Schedule for Beaumont-Port Arthur Ozone Nonattainment Area Major Sources).

(g) For compliance with §117.105(a)- (d) of this title by November 15, 1999, a unit that has operated since November 15, 1990, and has since been permanently retired or decommissioned and rendered inoperable prior to June 9, 1993, may be included in the source cap emission limit under the following conditions.

(1) The unit must have actually operated since November 15, 1990.

(2) For purposes of calculating the source cap emission limit, the applicable emission limit for retired units must be calculated in accordance with subsection (b) of this section.

(3) The actual heat input must be calculated according to subsection (b)(1) of this section. If the unit was not in service 24 consecutive months between January 1, 1990, and June 9, 1993, the actual heat input must be the average daily heat input for the continuous time period that the unit was in service, plus one standard deviation of the average daily heat input for that period. The maximum heat input must be the maximum heat input, as certified to the executive director, allowed or possible (whichever is lower) in a 24-hour period.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(5) Emission reductions from shutdowns or curtailments that have not been used for netting or offset purposes under the requirements of Chapter 116 of this title or have not resulted from any other state or federal requirement may be included in the baseline for establishing the cap.

(h) For compliance with §117.105(e) or §117.110 of this title, a unit that has been permanently retired or decommissioned and rendered inoperable may be included in the source cap under the following conditions.

(1) Shutdowns must have occurred after September 10, 1993.

(2) The source cap emission limit for retired units is calculated in accordance with subsection (b) of this section.

(3) The actual heat input must be calculated according to subsection (b)(1) of this section. If the unit was not in service 24 consecutive months between January 1, 1997, and December 31, 1999, the actual heat input must be the average daily heat input for the continuous time period that the unit was in service, consistent with the heat input used to represent the unit's emissions in the attainment demonstration modeling inventory. The maximum heat input must be the maximum heat input, as certified to the executive director, allowed or possible (whichever is lower) in a 24-hour period.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(5) Emission reductions from shutdowns or curtailments that have been used for netting or offset purposes under the requirements of Chapter 116 of this title may not be included in the baseline for establishing the cap.

(i) A unit that has been shut down and rendered inoperable after June 9, 1993, but not permanently retired, should be identified in the initial control plan and may be included in the source cap to comply with the NO _X emission specifications of this division required by November 15, 1999.

(j) An owner or operator who chooses to use the source cap option shall include in the initial control plan, if required to be filed under §117.150 of this title (relating to Initial Control Plan Procedures), a plan for initial compliance. The owner or operator shall include in the initial control plan the identification of the election to use the source cap procedure as specified in this section to achieve compliance with this section and shall specifically identify all sources that will be included in the source cap. The owner or operator shall also include in the initial control plan the method of calculating the actual heat input for each unit included in the source cap, as specified in subsection (b)(1) of this section. An owner or operator who chooses to use the source cap option shall include in the final control plan procedures of §117.152 of this title (relating to Final Control Plan Procedures for Reasonably Available Control Technology) the information necessary under this section to demonstrate initial compliance with the source cap.

(k) For the purposes of determining compliance with the source cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or emissions event, as defined in §101.1 of this title (relating to Definitions), must be calculated from the NO_X emission rate, as measured by the initial demonstration of compliance, for that unit, unless the owner or operator provides data demonstrating to the satisfaction of the executive director that actual emissions were less than maximum emissions during such periods.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702050

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. DALLAS-FORT WORTH OZONE NONATTAINMENT AREA MAJOR SOURCES

30 TAC §§117.200, 117.203, 117.205, 117.210, 117.215, 117.223, 117.225, 1117.230, 117.235, 117.240, 117.245, 117.252, 117.254, 117.256

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.223.Source Cap.

(a) An owner or operator may achieve compliance with the nitrogen oxides (NO _X ) emission limits of §117.205 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)) or §117.210 of this title (relating to Emission Specifications for Attainment Demonstration), by achieving equivalent NO_X emission reductions obtained by compliance with a source cap emission limitation in accordance with the requirements of this section. Each equipment category at a source whose individual emission units would otherwise be subject to the NO _X emission limits of §117.205 or §117.210 of this title may be included in the source cap. Any equipment category included in the source cap must include all emission units belonging to that category. Equipment categories include, but are not limited to, the following: steam generation, electrical generation, and units with the same product outputs, such as ethylene cracking furnaces. All emission units not included in the source cap must comply with the requirements of §§117.205, 117.210, or 117.215 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT); Emission Specifications for Attainment Demonstration; and Alternative Plant-Wide Emission Specifications).

(b) The source cap allowable mass emission rate must be calculated as follows.

(1) A rolling 30-day average emission cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.223(b)(1)

(2) A maximum daily cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.223(b)(2)

(3) Each emission unit included in the source cap is subject to the requirements of both paragraphs (1) and (2) of this subsection at all times.

(4) The owner or operator at its option may include any of the entire classes of exempted units listed in §117.215(f) of this title in a source cap. For compliance with §117.205(a) - (d) of this title, such units are required to reduce emissions available for use in the cap by an additional amount calculated in accordance with the United States Environmental Protection Agency's proposed Economic Incentive Program rules for offset ratios for trades between RACT and non-RACT sources, as published in the February 23, 1993, Federal Register (58 FR 11110).

(5) For stationary internal combustion engines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.215(g)(2) of this title.

(6) For stationary gas turbines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.215(g)(3) of this title.

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous exhaust NO _X monitor, carbon monoxide (CO) monitor, an oxygen (O ₂ ) (or carbon dioxide (CO ₂ )) diluent monitor, and a totalizing fuel flow meter in accordance with the requirements of §117.240 of this title (relating to Continuous Demonstration of Compliance). The required continuous emissions monitoring systems (CEMS) and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel use for each affected unit and must be used to demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive emissions monitoring system (PEMS) and a totalizing fuel flow meter in accordance with the requirements of §117.240 of this title. The required PEMS and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel flow for each affected unit and must be used to demonstrate continuous compliance with the source cap; or

(C) for units not subject to continuous monitoring requirements and units belonging to the equipment classes listed in §117.215(f) of this title, the owner or operator may use the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.235(e) of this title (relating to Initial Demonstration of Compliance) in lieu of CEMS or PEMS. Emission rates for these units are limited to the maximum emission rates obtained from testing conducted under §117.235(e) of this title; and

(2) for each operating unit equipped with CEMS, either use a PEMS in accordance with §117.240 of this title, or the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.235(e) of this title, to provide emissions compliance data during periods when the CEMS is off-line. The methods specified in 40 CFR §75.46 must be used to provide emissions substitution data for units equipped with PEMS.

(d) The owner or operator of any units subject to a source cap shall maintain daily records indicating the NO _X emissions from each source and the total fuel usage for each unit and include a total NO _X emissions summation and total fuel usage for all units under the source cap on a daily basis. Records must also be retained in accordance with §117.245 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

(f) The owner or operator shall demonstrate initial compliance with the source cap in accordance with the schedule specified in §117.9010 of this title (relating to Compliance Schedule for Dallas-Fort Worth Ozone Nonattainment Area Major Sources).

(g) For compliance with §117.205(a) - (d) of this title by November 15, 1999, a unit that has operated since November 15, 1990, and has since been permanently retired or decommissioned and rendered inoperable prior to June 9, 1993, may be included in the source cap emission limit under the following conditions.

(1) The unit must have actually operated since November 15, 1990.

(2) For purposes of calculating the source cap emission limit, the applicable emission limit for retired units must be calculated in accordance with subsection (b) of this section.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(h) For compliance with §117.210 of this title, a unit that has been permanently retired or decommissioned and rendered inoperable may be included in the source cap under the following conditions.

(1) Shutdowns must have occurred after September 1, 1997.

(2) The source cap emission limit for retired units is calculated in accordance with subsection (b) of this section.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(i) A unit that has been shut down and rendered inoperable after June 9, 1993, but not permanently retired, should be identified in the final control plan and may be included in the source cap to comply with the NO _X emission specifications of this division applicable in the Dallas-Fort Worth ozone nonattainment area, required by March 31, 2001.

(j) An owner or operator who chooses to use the source cap option shall include in the final control plan, if required to be filed under §117.252 of this title (relating to Final Control Plan Procedures for Reasonably Available Control Technology), a plan for initial compliance. The owner or operator shall include in the final control plan the identification of the election to use the source cap procedure as specified in this section to achieve compliance with this section and shall specifically identify all sources that will be included in the source cap. The owner or operator shall also include in the final control plan the method of calculating the actual heat input for each unit included in the source cap, as specified in subsection (b)(1) of this section. An owner or operator who chooses to use the source cap option shall include in the final control plan procedures of §117.252 of this title the information necessary under this section to demonstrate initial compliance with the source cap.

(k) For the purposes of determining compliance with the source cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or emission events, as defined in §101.1 of this title (relating to Definitions), must be calculated from the NO_X emission rate, as measured by the initial demonstration of compliance, for that unit, unless the owner or operator provides data demonstrating to the satisfaction of the executive director that actual emissions were less than maximum emissions during such periods.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702051

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA MAJOR SOURCES

30 TAC §§117.300, 117.303, 117.305, 117.310, 117.315, 117.320, 117.323, 117.325, 117.330, 117.335, 117.340, 117.345, 117.350, 117.352, 117.354, 117.356

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.323.Source Cap.

(a) An owner or operator may achieve compliance with the nitrogen oxides (NO _X ) emission limits of §117.305 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)) by achieving equivalent NO _X emission reductions obtained by compliance with a source cap emission limitation in accordance with the requirements of this section. Each equipment category at a source whose individual emission units would otherwise be subject to the NO _X emission limits of §117.305 of this title may be included in the source cap. Any equipment category included in the source cap must include all emission units belonging to that category. Equipment categories include, but are not limited to, the following: steam generation, electrical generation, and units with the same product outputs, such as ethylene cracking furnaces. All emission units not included in the source cap must comply with the requirements of §117.305 or §117.315 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT) and Alternative Plant-Wide Emission Specifications).

(b) The source cap allowable mass emission rate must be calculated as follows.

(1) A rolling 30-day average emission cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.323(b)(1)

(2) A maximum daily cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.323(b)(2)

(3) Each emission unit included in the source cap must be subject to the requirements of both paragraphs (1) and (2) of this subsection at all times.

(4) The owner or operator at its option may include any of the entire classes of exempted units listed in §117.315(f) of this title in a source cap. For compliance with §117.305(a)- (d) of this title, such units are required to reduce emissions available for use in the cap by an additional amount calculated in accordance with the United States Environmental Protection Agency's proposed Economic Incentive Program rules for offset ratios for trades between RACT and non-RACT sources, as published in the February 23, 1993, Federal Register (58 FR 11110).

(5) For stationary internal combustion engines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.315(g)(2) of this title.

(6) For stationary gas turbines, the source cap allowable emission rate must be calculated in pounds per hour using the procedures specified in §117.315(g)(3) of this title.

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous exhaust NO _X monitor, carbon monoxide (CO) monitor, an oxygen (O ₂ ) (or carbon dioxide (CO ₂ )) diluent monitor, and a totalizing fuel flow meter in accordance with the requirements of §117.340 of this title (relating to Continuous Demonstration of Compliance). The required continuous emissions monitoring systems (CEMS) and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel use for each affected unit and must be used to demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive emissions monitoring system (PEMS) and a totalizing fuel flow meter in accordance with the requirements of §117.340 of this title. The required PEMS and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel flow for each affected unit and must be used to demonstrate continuous compliance with the source cap; or

(C) for units not subject to continuous monitoring requirements and units belonging to the equipment classes listed in §117.315(f) of this title, the owner or operator may use the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.335(e) of this title (relating to Initial Demonstration of Compliance) in lieu of CEMS or PEMS. Emission rates for these units are limited to the maximum emission rates obtained from testing conducted under §117.335(e) of this title; and

(2) for each operating unit equipped with CEMS, the owner or operator shall either use a PEMS in accordance with §117.340 of this title, or the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.335(e) of this title, to provide emissions compliance data during periods when the CEMS is off-line. The methods specified in 40 CFR §75.46 must be used to provide emissions substitution data for units equipped with PEMS.

(d) The owner or operator of any units subject to a source cap shall maintain daily records indicating the NO _X emissions from each source and the total fuel usage for each unit and include a total NO _X emissions summation and total fuel usage for all units under the source cap on a daily basis. Records must also be retained in accordance with §117.345 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

(f) The owner or operator shall demonstrate initial compliance with the source cap in accordance with the schedule specified in §117.9020(1) of this title (relating to Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Major Sources).

(g) For compliance with §117.305(a)- (d) of this title by November 15, 1999, a unit that has operated since November 15, 1990, and has since been permanently retired or decommissioned and rendered inoperable prior to June 9, 1993, may be included in the source cap emission limit under the following conditions.

(1) The unit must have actually operated since November 15, 1990.

(2) For purposes of calculating the source cap emission limit, the applicable emission limit for retired units must be calculated in accordance with subsection (b) of this section.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(h) A unit that has been shut down and rendered inoperable after June 9, 1993, but not permanently retired, should be identified in the initial control plan and may be included in the source cap to comply with the NO _X emission specifications of this division (relating to Houston-Galveston-Brazoria Ozone Nonattainment Area Major Sources) required by November 15, 1999.

(i) An owner or operator who chooses to use the source cap option shall include in the initial control plan, if required to be filed under §117.350 of this title (relating to Initial Control Plan Procedures), a plan for initial compliance. The owner or operator shall include in the initial control plan the identification of the election to use the source cap procedure as specified in this section to achieve compliance with this section and shall specifically identify all sources that will be included in the source cap. The owner or operator shall also include in the initial control plan the method of calculating the actual heat input for each unit included in the source cap, as specified in subsection (b)(1) of this section. An owner or operator who chooses to use the source cap option shall include in the final control plan procedures of §117.352 of this title (relating to Final Control Plan Procedures for Reasonably Available Control Technology) the information necessary under this section to demonstrate initial compliance with the source cap.

(j) For the purposes of determining compliance with the source cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or emissions event as defined in §101.1 of this title (relating to Definitions) must be calculated from the NO _X emission rate, as measured by the initial demonstration of compliance, for that unit, unless the owner or operator provides data demonstrating to the satisfaction of the executive director that actual emissions were less than maximum emissions during such periods.

(k) This section no longer applies after the appropriate compliance date(s) for emission specifications for attainment demonstration given in §117.9020(2) of this title. For purposes of this paragraph, this means that the source cap of this section remains in effect until the emissions allocation for units under the Houston-Galveston-Brazoria mass emissions cap are equal to or less than the allocation that would be calculated using the source cap of this section.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702052

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

4. DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MAJOR SOURCES

30 TAC §§117.400, 117.403, 117.410, 117.423, 117.425, 117.430, 117.435, 117.440, 117.445, 117.450, 117.454, 117.456

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.400.Applicability.

The provisions of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources), apply to the following units located at any major stationary source of nitrogen oxides located within the Dallas-Fort Worth eight-hour ozone nonattainment area:

(1) industrial, commercial, or institutional boilers and process heaters;

(2) stationary gas turbines;

(3) stationary internal combustion engines;

(4) duct burners used in turbine exhaust ducts;

(5) lime kilns;

(6) metallurgical heat treating furnaces and reheat furnaces;

(7) incinerators;

(8) glass, fiberglass, and mineral wool melting furnaces;

(9) fiberglass and mineral wool curing ovens;

(10) natural gas-fired ovens and heaters;

(11) natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic tile, calcining, and vitrifying processes;

(12) brick and ceramic kilns; and

(13) lead smelting reverberatory and blast (cupola) furnaces.

§117.403.Exemptions.

(a) Units exempted from the provisions of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources), except as specified in §§117.440(i), 117.445(f)(4) and (9), 117.450, and 117.454 of this title (relating to Continuous Demonstration of Compliance; Notification, Recordkeeping, and Reporting Requirements; Initial Control Plan Procedures; and Final Control Plan Procedures for Attainment Demonstration Emission Specifications), include the following:

(1) industrial, commercial, or institutional boilers or process heaters with a maximum rated capacity equal to or less than:

(A) 2.0 million British thermal units per hour (MMBtu/hr) for boilers; and

(B) 5.0 MMBtu/hr for process heaters;

(2) heat treating furnaces and reheat furnaces with a maximum rated capacity less than 20 MMBtu/hr;

(3) flares, incinerators with a maximum rated capacity less than 40 MMBtu/hr, pulping liquor recovery furnaces, sulfur recovery units, sulfuric acid regeneration units, molten sulfur oxidation furnaces, and sulfur plant reaction boilers;

(4) dryers, heaters, or ovens with a maximum capacity of 5.0 MMBtu/hr or less;

(5) any dryers, heaters, or ovens fired on fuels other than natural gas. This exemption does not apply to gas-fired curing ovens used for the production of mineral wool-type or textile-type fiberglass;

(6) any glass, fiberglass, and mineral wool melting furnaces with a maximum rated capacity of 2.0 MMBtu/hr or less;

(7) stationary gas turbines and stationary internal combustion engines, that are used as follows:

(A) in research and testing;

(B) for purposes of performance verification and testing;

(D) exclusively in emergency situations, except that operation for testing or maintenance purposes is allowed for up to 100 hours per year, based on a rolling 12-month average. Any new, modified, reconstructed, or relocated stationary diesel engine placed into service on or after June 1, 2007, is ineligible for this exemption. For the purposes of this subparagraph, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title (relating to General Definitions) and 40 Code of Federal Regulations (CFR) §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title (relating to Definitions), a used engine from anywhere outside that account;

(E) in response to and during the existence of any officially declared disaster or state of emergency;

(F) directly and exclusively by the owner or operator for agricultural operations necessary for the growing of crops or raising of fowl or animals; or

(G) as chemical processing gas turbines;

(8) any stationary diesel engine placed into service before June 1, 2007, that:

(A) operates less than 100 hours per year, based on a rolling 12-month average; and

(B) has not been modified, reconstructed, or relocated on or after June 1, 2007. For the purposes of this subparagraph, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title and 40 CFR §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title, a used engine from anywhere outside that account;

(9) any new, modified, reconstructed, or relocated stationary diesel engine placed into service on or after June 1, 2007, that:

(A) operates less than 100 hours per year, based on a rolling 12-month average, in other than emergency situations; and

(B) meets the corresponding emission standard for non-road engines listed in 40 CFR §89.112(a), Table 1 (October 23, 1998), and in effect at the time of installation, modification, reconstruction, or relocation. For the purposes of this paragraph, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title and 40 CFR §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title, a used engine from anywhere outside that account;

(10) boilers and industrial furnaces that were regulated as existing facilities by 40 CFR Part 266, Subpart H, as was in effect on June 9, 1993;

(11) brick or ceramic kilns with a maximum rated capacity less than 5.0 MMBtu/hr;

(12) curing ovens used in mineral wool-type fiberglass manufacturing in which nitrogen-bound chemical additives are used;

(13) stationary, gas-fired, reciprocating internal combustion engines with a horsepower (hp) rating less than 50 hp;

(14) electric arc melting furnaces used in steel production;

(15) forming ovens and forming processes used in mineral wool-type fiberglass manufacturing; and

(16) natural gas-fired heaters used exclusively for providing comfort heat to areas designed for human occupancy.

(b) Increment of progress exemptions.

(1) Stationary, reciprocating internal combustion engines with a maximum rated capacity less than 300 horsepower are exempt from the emission specifications in §117.410(a) of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration).

(2) The emission specifications in §117.410(a) of this title no longer apply to any stationary, reciprocating internal combustion engine subject to the emission specifications of §117.410(b) of this title after the compliance date specified in §117.9030(b) of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources).

(3) Stationary engines that are demonstrated to operate less than 850 hours per year, based on a rolling 12-month average are exempt from the emission specifications in §117.410(a) of this title.

(c) Emergency fuel oil firing exemption for gas-fired boilers. The emission specifications in §117.410(b)(1) and (d) of this title do not apply to gas-fired boilers during periods that the owner or operator is required to fire fuel oil on an emergency basis due to natural gas curtailment or other emergency, provided:

(1) the fuel oil firing occurs during the months of November, December, January, or February; and

(2) the fuel oil firing does not exceed a total of 72 hours in any calendar month specified in paragraph (1) of this subsection.

§117.410.Emission Specifications for Eight-Hour Attainment Demonstration.

(a) Emission specifications for increment of progress. The owner or operator of any gas-fired stationary, reciprocating internal combustion engine with a maximum rated horsepower (hp) of 300 hp or greater shall comply with the following emission specifications, in accordance with the applicable schedule in §117.9030(a) of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources), except as provided in subsection (e) of this section:

(1) nitrogen oxides (NO _X ), as follows:

(A) lean-burn engines, 2.0 grams per horsepower-hour (g/hp-hr); and

(B) rich-burn engines:

(i) placed into service before January 1, 2000, that have not been modified, reconstructed, or relocated on or after January 1, 2000, 2.0 g/hp-hr. For the purposes of this clause, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title (relating to General Definitions) and 40 Code of Federal Regulations (CFR) §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title (relating to Definitions), a used engine from anywhere outside that account; and

(ii) installed, modified, reconstructed, or relocated on or after January 1, 2000, 0.50 g/hp-hr; and

(2) carbon monoxide (CO), 3.0 g/hp-hr.

(b) Emission specifications for eight-hour ozone attainment demonstration. No person shall allow the discharge into the atmosphere NO_X emissions in excess of the following emission specifications, in accordance with the applicable schedule in §117.9030(b) of this title, except as provided in subsection (e) of this section:

(1) gas-fired boilers:

(A) with a maximum rated capacity equal to or greater than 100 million British thermal units per hour (MMBtu/hr), 0.020 pounds per million British thermal units (lb/MMBtu);

(B) with a maximum rated capacity equal to or greater than 40 MMBtu/hr, but less than 100 MMBtu/hr, 0.030 lb/MMBtu; and

(C) with a maximum rated capacity less than 40 MMBtu/hr, 0.036 lb/MMBtu (or alternatively, 30 parts per million by volume (ppmv) NO_X , at 3.0% oxygen (O ₂ ), dry basis);

(2) liquid-fired boilers, 2.0 pounds per 1,000 gallons of liquid burned;

(3) process heaters:

(A) with a maximum rated capacity equal to or greater than 40 MMBtu/hr, 0.025 lb/MMBtu; and

(B) with a maximum rated capacity less than 40 MMBtu/hr, 0.036 lb/MMBtu (or alternatively, 30 ppmv, at 3.0% O ₂ , dry basis);

(4) stationary, reciprocating internal combustion engines:

(A) gas-fired rich-burn engines:

(i) fired on landfill gas, 0.60 g/hp-hr; and

(ii) all others, 0.50 g/hp-hr;

(B) gas-fired lean-burn engines:

(i) placed into service before June 1, 2007, that have not been modified, reconstructed, or relocated on or after June 1, 2007, 0.70 g/hp-hr; and

(ii) placed into service, modified, reconstructed, or relocated on or after June 1, 2007:

(I) fired on landfill gas, 0.60 g/hp-hr; and

(II) all others, 0.50 g/hp-hr;

(D) diesel engines, excluding dual-fuel engines, placed into service before March 1, 2009, that have not been modified, reconstructed, or relocated on or after March 1, 2009, the lower of 11.0 g/hp-hr or the emission rate established by testing, monitoring, manufacturer's guarantee, or manufacturer's other data;

(E) for diesel engines, excluding dual-fuel engines, not subject to subparagraph (D) of this paragraph:

(i) with a hp rating of less than 50 hp that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 5.0 g/hp-hr;

(ii) with a hp rating of 50 hp or greater, but less than 100 hp, that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 3.3 g/hp-hr;

(iii) with a hp rating of 100 hp or greater, but less than 750 hp, that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 2.8 g/hp-hr; and

(iv) with a hp rating of 750 hp or greater that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 4.5 g/hp-hr; and

(F) for the purposes of this paragraph, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title (relating to General Definitions) and 40 CFR §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title (relating to Definitions), a used engine from anywhere outside that account;

(5) stationary gas turbines:

(A) rated at 10 megawatts (MW) or greater, 0.032 lb/MMBtu;

(B) rated at 1.0 MW or greater, but less than 10 MW, 0.15 lb/MMBtu; and

(6) duct burners used in turbine exhaust ducts, the corresponding gas turbine emission specification of paragraph (5) of this subsection;

(7) kilns:

(A) lime kilns, 3.7 pounds per ton (lb/ton) of calcium oxide, demonstrated either:

(i) on an individual kiln basis; or

(ii) on a site-wide production rate weighted average basis, using the following equation:

Figure: 30 TAC §117.410(b)(7)(A)(ii)

(B) brick and ceramic kilns, one of the following:

(i) a 40% reduction from the daily NO_X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 Emission Inventory. To ensure that this emission specification will result in a real 40% reduction in actual emissions, a consistent methodology must be used to calculate the 40% reduction;

(ii) 0.175 lb/ton of product for brick kilns; or

(iii) 0.27 lb/ton of product for ceramic kilns;

(8) metallurgical furnaces:

(A) heat treating furnaces, 0.087 lb/MMBtu. For heat treating furnaces equipped with NO _X CEMS or PEMS that comply with §117.440 of this title (relating to Continuous Demonstration of Compliance), this emission specification only applies from March 1 to October 31 of any calendar year;

(B) reheat furnaces, 0.10 lb/MMBtu. For reheat furnaces equipped with NO _X CEMS or PEMS that comply with §117.440 of this title, this emission specification only applies from March 1 to October 31 of any calendar year; and

(C) lead smelting blast (cupola) and reverberatory furnaces used in conjunction, the combined rate of 0.45 lb/ton product;

(9) incinerators, either of the following:

(A) an 80% reduction from the daily NO _X emissions reported to the Industrial Emissions Assessment Section for the calendar year 2000 Emission Inventory. To ensure that this emission specification will result in a real 80% reduction in actual emissions, a consistent methodology must be used to calculate the 80% reduction; or

(B) 0.030 lb/MMBtu;

(10) glass and fiberglass melting furnaces:

(A) container glass melting furnaces:

(i) 4.0 lb/ton of glass pulled during furnace operation equal to or greater than 25% of the permitted glass production capacity; and

(ii) the applicable maximum allowable pound per hour NO_X permit limit in a permit issued before June 1, 2007, during furnace operation less than 25% of the permitted glass production capacity;

(B) mineral wool-type cold-top electric fiberglass melting furnaces, 4.0 lb/ton of product pulled;

(D) mineral wool-type fiberglass non-regenerative gas-fired furnaces, 3.1 lb/ton product pulled;

(11) gas-fired curing ovens used for the production of mineral wool-type or textile-type fiberglass, 0.036 lb/MMBtu;

(12) natural gas-fired ovens and heaters, 0.036 lb/MMBtu;

(13) natural gas-fired dryers:

(A) dryers used in organic solvent, printing ink, clay, brick, ceramic tile, calcining, and vitrifying processes , 0.036 lb/MMBtu;

(B) spray dryers used in ceramic tile manufacturing processes, 0.15 lb/MMBtu; and

(14) as an alternative to the emission specifications in paragraphs (1) - (13) of this subsection for units with an annual capacity factor of 0.0383 or less, 0.060 lb/MMBtu. The capacity factor as of December 31, 2000, must be used to determine whether the unit is eligible for the emission specification of this paragraph. A 12-month rolling average must be used to determine the annual capacity factor for units placed into service after December 31, 2000.

(1) if the unit is operated with a NO _X continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) under §117.440 of this title (relating to Continuous Demonstration of Compliance), either as:

(A) a rolling 30-day average period, in the units of the applicable standard;

(B) a block one-hour average, in the units of the applicable standard, or alternatively;

(C) a block one-hour average, in pounds per hour, for boilers and process heaters, calculated as the product of the boiler's or process heater's maximum rated capacity and its applicable specification in lb/MMBtu; and

(2) if the unit is not operated with a NO _X CEMS or PEMS under §117.440 of this title, a block one-hour average, in the units of the applicable standard. Alternatively for boilers and process heaters, the emission specification may be applied in pounds per hour, as specified in paragraph (1)(C) of this subsection.

(d) Related emissions. No person shall allow the discharge into the atmosphere from any unit subject to NO _X emission specifications in subsection (a) or (b) of this section, emissions in excess of the following, except as provided in §117.425 of this title (relating to Alternative Case Specific Specifications) or paragraph (3) or (4) of this subsection.

(1) CO emissions must not exceed 400 ppmv at 3.0% O ₂ , dry basis (or alternatively, 3.0 g/hp-hr for stationary internal combustion engines; or 775 ppmv at 7.0% O ₂ , dry basis for wood fuel-fired boilers or process heaters):

(A) on a rolling 24-hour averaging period, for units equipped with CEMS or PEMS for CO; and

(B) on a one-hour average, for units not equipped with CEMS or PEMS for CO.

(2) For units that inject urea or ammonia into the exhaust stream for NO _X control, ammonia emissions must not exceed 10 ppmv at 3.0% O ₂ , dry, for boilers and process heaters; 15% O ₂ , dry, for stationary gas turbines (including duct burners used in turbine exhaust ducts) and gas-fired lean-burn engines; 7.0% O ₂ , dry, for incinerators; and 3.0% O ₂ , dry, for all other units, based on:

(A) a block one-hour averaging period for units not equipped with a CEMS or PEMS for ammonia; or

(B) a rolling 24-hour averaging period for units equipped with CEMS or PEMS for ammonia.

(3) The correction of CO emissions to 3.0% O ₂ , dry basis, in paragraph (1) of this subsection does not apply to boilers and process heaters operating at less than 10% of maximum load and with stack O ₂ in excess of 15% (i.e., hot-standby mode).

(4) The CO specifications in paragraph (1) of this subsection do not apply to:

(A) stationary internal combustion engines subject to subsection (a) of this section; or

(B) incinerators subject to the CO limits of one of the following:

(i) §111.121 of this title (relating to Single-, Dual-, and Multiple-Chamber Incinerators);

(ii) §113.2072 of this title (relating to Emission Limits) for hospital/medical/infectious waste incinerators; or

(iii) 40 CFR Part 264 or 265, Subpart O, for hazardous waste incinerators.

(e) Compliance flexibility.

(1) An owner or operator may use any of the following alternative methods to comply with the NO _X emission specifications of this section:

(A) §117.423 of this title (relating to Source Cap); or

(B) §117.9800 of this title (relating to Use of Emission Credits for Compliance).

(2) Section 117.425 of this title is not an applicable method of compliance with the NO _X emission specifications of this section.

(3) An owner or operator may petition the executive director for an alternative to the CO or ammonia specifications of this section in accordance with §117.425 of this title.

(f) Prohibition of circumvention.

(1) The maximum rated capacity used to determine the applicability of the emission specifications in this section and the initial compliance demonstration, monitoring, testing requirements, and final control plan in §§117.435, 117.440, and 117.454 of this title (relating to Initial Demonstration of Compliance; Continuous Demonstration of Compliance; and Final Control Plan Procedures for Attainment Demonstration Emission Specifications) must be the greater of the following:

(A) the maximum rated capacity as of December 31, 2000;

(B) the maximum rated capacity after December 31, 2000; or

(C) the maximum rated capacity authorized by a permit issued under Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) after December 31, 2000.

(2) A unit's classification is determined by the most specific classification applicable to the unit as of December 31, 2000. For example, a unit that is classified as a stationary gas-fired engine as of December 31, 2000, but subsequently is authorized to operate as a dual-fuel engine, is classified as a stationary gas-fired engine for the purposes of this chapter.

(3) Changes after December 31, 2000, to a unit subject to an emission specification in this section that result in increased NO _X emissions from a unit not subject to an emission specification of this section, such as redirecting one or more fuel or waste streams containing chemical-bound nitrogen to an incinerator with a maximum rated capacity of less than 40 MMBtu/hr, or a flare, is only allowed if:

(A) the increase in NO _X emissions at the unit not subject to this section is determined using a CEMS or PEMS that meets the requirements of §117.440 of this title, or through stack testing that meets the requirements of §117.435 of this title; and

(B) emission credits equal to the increase in NO _X emissions at the unit not subject to this section are obtained and used in accordance with §117.9800 of this title (relating to Use of Emission Credits for Compliance).

(4) A source that met the definition of major source on December 31, 2000, is always classified as a major source for purposes of this chapter. A source that did not meet the definition of major source (i.e., was a minor source, or did not yet exist) on December 31, 2000, but becomes a major source at any time after December 31, 2000, is from that time forward always classified as a major source for purposes of this chapter.

(5) The availability under subsection (b)(14) of this section of an emission specification for units with an annual capacity factor of 0.0383 or less is based on the unit's status on December 31, 2000. Reduced operation after December 31, 2000, cannot be used to qualify for a more lenient emission specification under subsection (b)(14) of this section than would otherwise apply to the unit.

(6) This subsection does not apply to stationary, reciprocating internal combustion engines subject to subsection (a) of this section until the compliance date specified in §117.9030(b) of this title.

(g) Operating restrictions. No person may start or operate any stationary diesel or dual-fuel engine for testing or maintenance between the hours of 6:00 a.m. and noon, except:

(1) for specific manufacturer's recommended testing requiring a run of over 18 consecutive hours;

(2) to verify reliability of emergency equipment (e.g., emergency generators or pumps) immediately after unforeseen repairs. Routine maintenance such as an oil change is not considered to be an unforeseen repair; or

(3) firewater pumps for emergency response training conducted from April 1 through October 31.

§117.423.Source Cap.

(a) An owner or operator may achieve compliance with the nitrogen oxides (NO _X ) emission specifications of §117.410 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration), by achieving equivalent NO _X emission reductions obtained by compliance with a source cap emission limitation in accordance with the requirements of this section. Each equipment category at a source whose individual emission units would otherwise be subject to the NO _X emission specifications of §117.410 of this title may be included in the source cap. Any equipment category included in the source cap must include all emission units belonging to that category. Equipment categories include, but are not limited to, the following: steam generation, electrical generation, and units with the same product outputs, such as ethylene cracking furnaces. All emission units not included in the source cap must comply with the requirements of §117.410 of this title.

(b) The source cap allowable mass emission rate must be calculated as follows.

(1) A rolling 30-day average emission cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.423(b)(1)

(2) A maximum daily cap must be calculated for all emission units included in the source cap using the following equation.

Figure: 30 TAC §117.423(b)(2)

(3) Each emission unit included in the source cap is subject to the requirements of both paragraphs (1) and (2) of this subsection at all times.

(4) For stationary internal combustion engines, the source cap allowable emission rate must be calculated in pounds per hour using the following equation.

Figure: 30 TAC §117.423(b)(4)

(5) For stationary gas turbines, the source cap allowable emission rate must be calculated in pounds per hour using the following equations.

Figure: 30 TAC §117.423(b)(5)

(1) for each unit included in the source cap, either:

(A) install, calibrate, maintain, and operate a continuous exhaust NO_X monitor, carbon monoxide (CO) monitor, an oxygen (O ₂ ) (or carbon dioxide (CO ₂ )) diluent monitor, and a totalizing fuel flow meter in accordance with the requirements of §117.440 of this title (relating to Continuous Demonstration of Compliance). The required continuous emissions monitoring systems (CEMS) and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel use for each affected unit and must be used to demonstrate continuous compliance with the source cap;

(B) install, calibrate, maintain, and operate a predictive emissions monitoring system (PEMS) and a totalizing fuel flow meter in accordance with the requirements of §117.440 of this title. The required PEMS and fuel flow meters must be used to measure NO _X , CO, and O ₂ (or CO ₂ ) emissions and fuel flow for each affected unit and must be used to demonstrate continuous compliance with the source cap; or

(C) for units not subject to continuous monitoring requirements, use the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.435(d) of this title (relating to Initial Demonstration of Compliance) in lieu of CEMS or PEMS. Emission rates for these units are limited to the maximum emission rates obtained from testing conducted under §117.435(d) of this title; and

(2) for each operating unit equipped with CEMS, either use a PEMS in accordance with §117.440 of this title, or the maximum emission rate as measured by hourly emission rate testing conducted in accordance with §117.435(d) of this title, to provide emissions compliance data during periods when the CEMS is off-line. The methods specified in 40 Code of Federal Regulations §75.46 must be used to provide emissions substitution data for units equipped with PEMS.

(d) The owner or operator of any units subject to a source cap shall maintain daily records indicating the NO _X emissions from each source and the total fuel usage for each unit and include a total NO _X emissions summation and total fuel usage for all units under the source cap on a daily basis. Records must also be retained in accordance with §117.445 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

(f) The owner or operator shall demonstrate initial compliance with the source cap in accordance with the schedule specified in §117.9030 of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources)

(g) For compliance with §117.410 of this title, a unit that has been permanently retired or decommissioned and rendered inoperable may be included in the source cap under the following conditions.

(1) Permanent shutdowns must have occurred after December 31, 2000.

(2) The source cap emission limit for retired units is calculated in accordance with subsection (b) of this section.

(3) The actual heat input must be calculated according to subsection (b)(1) of this section. If the unit was not in service 24 consecutive months between January 1, 2000, and December 31, 2001, the actual heat input must be the average daily heat input for the continuous time period that the unit was in service, consistent with the heat input used to represent the unit's emissions in the attainment demonstration modeling inventory. The maximum heat input must be the maximum heat input, as certified to the executive director, allowed or possible (whichever is lower) in a 24-hour period.

(4) The owner or operator shall certify the unit's operational level and maximum rated capacity.

(5) Emission reductions from permanent shutdowns or curtailments that have been used for netting or offset purposes under the requirements of Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) may not be included in the baseline for establishing the cap.

(h) An owner or operator who chooses to use the source cap option shall include in the initial control plan, if required to be filed under §117.450 of this title (relating to Initial Control Plan Procedures), a plan for initial compliance. The owner or operator shall include in the initial control plan the identification of the election to use the source cap procedure as specified in this section to achieve compliance with this section and shall specifically identify all sources that will be included in the source cap. The owner or operator shall also include in the initial control plan the method of calculating the actual heat input for each unit included in the source cap, as specified in subsection (b)(1) of this section.

(i) For the purposes of determining compliance with the source cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or emissions event as defined in §101.1 of this title (relating to Definitions) must be calculated from the NO _X emission rate, as measured by the initial demonstration of compliance, for that unit, unless the owner or operator provides data demonstrating to the satisfaction of the executive director that actual emissions were less than maximum emissions during such periods.

§117.440.Continuous Demonstration of Compliance.

(a) Totalizing fuel flow meters. The owner or operator of units listed in this subsection shall install, calibrate, maintain, and operate a totalizing fuel flow meter, with an accuracy of ± 5%, to individually and continuously measure the gas and liquid fuel usage. A computer that collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. The owner or operator must continuously operate the totalizing fuel flow meter at least 95% of the time when the unit is operating, averaged over a calendar year. For the purpose of compliance with this subsection for units having pilot fuel supplied by a separate fuel system or from an unmonitored portion of the same fuel system, the fuel flow to pilots may be calculated using the manufacturer's design flow rates rather than measured with a fuel flow meter. The calculated pilot fuel flow rate must be added to the monitored fuel flow when fuel flow is totaled.

(1) The units are the following units subject to §117.410 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstrations):

(A) boilers;

(B) process heaters;

(D) stationary, reciprocating internal combustion engines;

(E) stationary gas turbines;

(F) lime kilns

(G) brick and ceramic kilns;

(H) heat treating furnaces;

(I) reheat furnaces;

(J) lead smelting blast (cupola) and reverberatory furnaces;

(K) glass and fiberglass/mineral wool melting furnaces;

(L) incinerators (excluding vapor streams resulting from vessel cleaning routed to an incinerator, provided that fuel usage is quantified using good engineering practices, including calculation methods in general use and accepted in new source review permitting in Texas. All other fuel and vapor streams must be monitored in accordance with this subsection);

(M) gas-fired glass, fiberglass, and mineral wool curing ovens;

(N) natural gas-fired ovens and heaters; and

(O) natural gas-fired dryers used in organic solvent, printing ink, clay, brick, ceramic, and calcining and vitrifying processes.

(2) The following are alternatives to the fuel flow monitoring requirements of paragraph (1) of this subsection.

(A) Units operating with a nitrogen oxides (NO _X ) and diluent continuous emissions monitoring system (CEMS) under subsection (f) of this section may monitor stack exhaust flow using the flow monitoring specifications of 40 Code of Federal Regulations (CFR) Part 60, Appendix B, Performance Specification 6 or 40 CFR Part 75, Appendix A.

(B) Units that vent to a common stack with a NO _X and diluent CEMS under subsection (f) of this section may use a single totalizing fuel flow meter.

(C) Diesel engines operating with run time meters may meet the fuel flow monitoring requirements of this subsection through monthly fuel use records maintained for each engine.

(D) Stationary reciprocating internal combustion engines and gas turbines equipped with a continuous monitoring system that continuously monitors horsepower and hours of operation are not required to install totalizing fuel flow meters. The continuous monitoring system must be installed, calibrated, maintained, and operated according to manufacturers' recommended procedures.

(b) Oxygen (O ₂ ) monitors.

(1) The owner or operator shall install, calibrate, maintain, and operate an O ₂ monitor to measure exhaust O ₂ concentration on the following units operated with an annual heat input greater than 2.2(10 ¹¹ ) British thermal units per year (Btu/yr):

(A) boilers with a rated heat input greater than or equal to 100 million British thermal units per hour (MMBtu/hr); and

(B) process heaters with a rated heat input greater than or equal to 100 MMBtu/hr, except:

(i) as provided in subsection (g) of this section; and

(ii) for process heaters operating with a carbon dioxide (CO₂ ) CEMS for diluent monitoring under subsection (f) of this section.

(2) The O ₂ monitors required by this subsection are for process monitoring (predictive monitoring inputs, boiler trim, or process control) and are only required to meet the location specifications and quality assurance procedures referenced in subsection (f) of this section if O ₂ is the monitored diluent under that subsection. However, if new O ₂ monitors are required as a result of this subsection, the criteria in subsection (f) of this section should be considered the appropriate guidance for the location and calibration of the monitors.

(1) The owner or operator of units listed in this paragraph shall install, calibrate, maintain, and operate a CEMS or predictive emissions monitoring system (PEMS) to monitor exhaust NO _X . The units are:

(A) units with a rated heat input greater than or equal to 100 MMBtu/hr that are subject to §117.410(b) of this title;

(B) stationary gas turbines with a megawatt (MW) rating greater than or equal to 30 MW operated more than 850 hours per year;

(D) units that the owner or operator elects to comply with the NO _X emission specifications of §117.410(b) of this title using a pound per MMBtu (lb/MMBtu) limit on a 30-day rolling average;

(E) lime kilns; and

(F) brick kilns and ceramic kilns.

(2) Units subject to the NO _X CEMS requirements of 40 CFR Part 75 are not required to install CEMS or PEMS under this subsection.

(3) The owner or operator shall use one of the following methods to provide substitute emissions compliance data during periods when the NO_X monitor is off-line:

(A) if the NO _X monitor is a CEMS:

(i) subject to 40 CFR Part 75, use the missing data procedures specified in 40 CFR Part 75, Subpart D (Missing Data Substitution Procedures); or

(ii) subject to 40 CFR Part 75, Appendix E, use the missing data procedures specified in 40 CFR Part 75, Appendix E, §2.5 (Missing Data Procedures);

(B) use 40 CFR Part 75, Appendix E monitoring in accordance with §117.1340(d) of this title (relating to Continuous Demonstration of Compliance);

(i) use the methods specified in 40 CFR Part 75, Subpart D; or

(ii) use calculations in accordance with §117.8110(b) of this title (relating to Emission Monitoring System Requirements for Utility Electric Generation Sources); or

(D) the maximum block one-hour emission rate as measured during the initial demonstration of compliance required in §117.435(e) of this title (relating to Initial Demonstration of Compliance).

(d) Ammonia monitoring requirements. The owner or operator of any unit subject to §117.410(b) of this title and the ammonia emission specification of §117.410(c)(2) of this title shall monitor ammonia emissions from the unit according to the requirements of §117.8130 of this title (relating to Ammonia Monitoring).

(e) Carbon monoxide (CO) monitoring. The owner or operator shall monitor CO exhaust emissions from each unit listed in subsection (c)(1) of this section using one or more of the methods specified in §117.8120 of this title (relating to Carbon Monoxide (CO) Monitoring).

(f) CEMS requirements. The owner or operator of any CEMS used to meet a pollutant monitoring requirement of this section shall comply with the requirements of §117.8100(a) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources).

(g) PEMS requirements. The owner or operator of any PEMS used to meet a pollutant monitoring requirement of this section shall comply with the following.

(1) The PEMS must predict the pollutant emissions in the units of the applicable emission limitations of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources).

(2) The PEMS must meet the requirements of §117.8100(b) of this title.

(h) Engine monitoring. The owner or operator of any stationary gas engine subject to the emission specifications of this division shall stack test engine NO _X and CO emissions as specified in §117.8140(a) of this title (relating to Emission Monitoring for Engines)

(i) Run time meters. The owner or operator of any stationary gas turbine or stationary internal combustion engine claimed exempt using the exemption of §117.403(a)(7)(D), (8), or (9) of this title (relating to Exemptions) shall record the operating time with a non-resettable elapsed run time meter.

(j) Data used for compliance. After the initial demonstration of compliance required by §117.435 of this title, the methods required in this section must be used to determine compliance with the emission specifications of §117.410(a) or (b) of this title. For enforcement purposes, the executive director may also use other commission compliance methods to determine whether the source is in compliance with applicable emission specifications.

(k) Testing requirements.

(1) The owner or operator of units that are subject to the emission specifications of §117.410(a) of this title shall test the units as specified in §117.435 of this title in accordance with the schedule specified in §117.9030(a) of this title.

(2) The owner or operator of units that are subject to the emission specifications of §117.410(b) of this title shall test the units as specified in §117.435 of this title in accordance with the schedule specified in §117.9030(b) of this title.

(3) The owner or operator of any unit not equipped with CEMS or PEMS that are subject to the emission specifications of §117.410(b) of this title shall retest the unit as specified in §117.435 of this title within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate.

§117.445.Notification, Recordkeeping, and Reporting Requirements.

(a) Startup and shutdown records. For units subject to the startup and/or shutdown provisions of §101.222 of this title (relating to Demonstrations), hourly records must be made of startup and/or shutdown events and maintained for a period of at least two years. Records must be available for inspection by the executive director, the United States Environmental Protection Agency, and any local air pollution control agency having jurisdiction upon request. These records must include, but are not limited to: type of fuel burned; quantity of each type of fuel burned; and the date, time, and duration of the procedure.

(b) Notification. The owner or operator of an affected source shall submit notification to the appropriate regional office and any local air pollution control agency having jurisdiction as follows:

(1) for units subject to the emission specifications of §117.410(a) of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration):

(A) verbal notification of the date of any testing conducted under §117.435 of this title (relating to Initial Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed; and

(B) verbal notification of the date of any continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) relative accuracy test audit (RATA) conducted under §117.440 of this title (relating to Continuous Demonstration of Compliance) at least 15 days prior to such date followed by written notification within 15 days after testing is completed; and

(2) for units subject to the emission specifications of §117.410(b) of this title, written notification of any CEMS or PEMS RATA conducted under §117.440 of this title or any testing conducted under §117.435 of this title at least 15 days in advance of the date of the RATA or testing.

(c) Reporting of test results. The owner or operator of an affected unit shall furnish the Office of Compliance and Enforcement, the appropriate regional office, and any local air pollution control agency having jurisdiction a copy of any testing conducted under §117.435 of this title and any CEMS or PEMS RATA conducted under §117.440 of this title:

(1) within 60 days after completion of such testing or evaluation; and

(2) not later than the compliance schedule specified in §117.9030 of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources).

(d) Semiannual reports. The owner or operator of a unit required to install a CEMS or PEMS under §117.440 of this title shall report in writing to the executive director on a semiannual basis any exceedance of the applicable emission specifications of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources) and the monitoring system performance. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. Written reports must include the following information:

(1) the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations §60.13(h), any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the unit operating time during the reporting period. For units complying with §117.423 of this title (relating to Source Cap), excess emissions are each daily period that the total nitrogen oxides (NO_X ) emissions exceed the rolling 30-day average or the maximum daily NO _X cap;

(2) specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected unit, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted;

(3) the date and time identifying each period when the continuous monitoring system was inoperative, except for zero and span checks and the nature of the system repairs or adjustments;

(4) when no excess emissions have occurred or the continuous monitoring system has not been inoperative, repaired, or adjusted, such information must be stated in the report; and

(5) if the total duration of excess emissions for the reporting period is less than 1.0% of the total unit operating time for the reporting period and the CEMS or PEMS downtime for the reporting period is less than 5.0% of the total unit operating time for the reporting period, only a summary report form (as outlined in the latest edition of the commission's Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports ) must be submitted, unless otherwise requested by the executive director. If the total duration of excess emissions for the reporting period is greater than or equal to 1.0% of the total operating time for the reporting period or the CEMS or PEMS downtime for the reporting period is greater than or equal to 5.0% of the total operating time for the reporting period, a summary report and an excess emission report must both be submitted.

(e) Reporting for engines. The owner or operator of any gas-fired engine subject to the emission specifications in §117.410 of this title shall report in writing to the executive director on a semiannual basis any excess emissions and the air-fuel ratio monitoring system performance. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. Written reports must include the following information:

(1) the magnitude of excess emissions (based on the quarterly emission checks of §117.430(b)(7) of this title (relating to Operating Requirements) and the biennial emission testing required for demonstration of emissions compliance in accordance with §117.440(h) of this title, computed in pounds per hour and grams per horsepower-hour, any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the engine operating time during the reporting period; and

(2) specific identification, to the extent feasible, of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the engine or emission control system, the nature and cause of any malfunction (if known), and the corrective action taken or preventative measures adopted.

(f) Recordkeeping. The owner or operator of a unit subject to the requirements of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources) shall maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction. The records must include:

(1) for each unit subject to §117.440(a) of this title, records of annual fuel usage;

(2) for each unit using a CEMS or PEMS in accordance with §117.440 of this title, monitoring records of:

(A) hourly emissions and fuel usage (or stack exhaust flow) for units complying with an emission specification enforced on a block one-hour average; or

(B) daily emissions and fuel usage (or stack exhaust flow) for units complying with an emission specification enforced on a daily or rolling 30-day average. Emissions must be recorded in units of:

(i) pounds per million British thermal units (lb/MMBtu) heat input; and

(ii) pounds or tons per day;

(3) for each stationary internal combustion engine subject to the emission specifications of this division, records of:

(A) emissions measurements required by:

(i) §117.430(b)(7) of this title; and

(ii) §117.440(h) of this title;

(B) catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken; and

(C) daily average horsepower and total daily hours of operation for each engine that the owner or operator elects to use the alternative monitoring system allowed under §117.440(a)(2)(D) of this title;

(4) for units claimed exempt from emission specifications using the exemption of §117.403(a)(7)(D), (8), or (9) of this title (relating to Exemptions), records of monthly hours of operation, for exemptions based on hours per year of operation. In addition, for each engine claimed exempt under §117.403(a)(7)(D) of this title, written records must be maintained of the purpose of engine operation and, if operation was for an emergency situation, identification of the type of emergency situation and the start and end times and date(s) of the emergency situation;

(5) records of ammonia measurements specified in §117.440(d) of this title;

(6) records of carbon monoxide measurements specified in §117.440(e) of this title;

(7) records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS or PEMS;

(8) records of the results of performance testing, including initial demonstration of compliance testing conducted in accordance with §117.435 of this title;

(9) for each stationary diesel or dual-fuel engine, records of each time the engine is operated for testing and maintenance, including:

(A) date(s) of operation;

(B) start and end times of operation;

(D) total hours of operation for each month and for the most recent 12 consecutive months; and

(10) for lime kilns that comply with the alternative site-wide production rate weighted average emission specification in §117.410(b)(7)(A)(ii) of this title, daily records of:

(A) average NO _X emission rates in pounds per ton (lb/ton) of calcium oxide (CaO) for each kiln;

(B) production rate of CaO for each kiln in tons per day; and

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702053

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter C. COMBUSTION CONTROL AT MAJOR UTILITY ELECTRIC GENERATION SOURCES IN OZONE NONATTAINMENT AREAS

1. BEAUMONT-PORT ARTHUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

30 TAC §§117.1000, 117.1003, 117.1005, 117.1010, 117.1015, 117.1020, 117.1025, 117.1035, 117.1040, 117.1045, 117.1052, 117.1054, 117.1056

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.1000.Applicability.

(a) The provisions of this division (relating to Beaumont-Port Arthur Ozone Nonattainment Area Utility Electric Generation Sources) apply to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners in turbine exhaust ducts used in an electric power generating system, as defined in §117.10 of this title (relating to Definitions), that is located within the Beaumont-Port Arthur ozone nonattainment area and is owned or operated by:

(1) a municipality or a Public Utility Commission of Texas (PUC) regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or

(2) an electric cooperative, municipality, river authority, or public utility.

(b) The provisions of this division are applicable for the life of each affected unit within an electric power generating system or until this division or sections of this title that are applicable to an affected unit are rescinded.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702054

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. DALLAS-FORT WORTH OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

30 TAC §§117.1100, 117.1103, 117.1105, 117.1110, 117.1115, 117.1120, 117.1125, 117.1135, 117.1140, 117.1145, 117.1152, 117.1154, 117.1156

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.1100.Applicability.

(a) The provisions of this division (relating to Dallas-Fort Worth Ozone Nonattainment Area Utility Electric Generation Sources apply to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners in turbine exhaust ducts used in an electric power generating system, as defined in §117.10 of this title (relating to Definitions), that is located within the Dallas-Fort Worth ozone nonattainment area and is owned or operated by:

(1) a municipality or a Public Utility Commission of Texas (PUC) regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or

(2) an electric cooperative, municipality, river authority, or public utility.

(c) This division no longer applies to any electric generating facility in Collin, Dallas, Denton, and Tarrant Counties that is subject to the emission specifications in §117.1310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) after the appropriate compliance date(s) specified in §117.9130 of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources).

§117.1125.Alternative Case Specific Specifications.

(a) Where a person can demonstrate that an affected unit cannot attain the applicable requirements of §117.1105 of this title (relating to Emission Specifications for Reasonably Available Control Technology (RACT)), or the carbon monoxide (CO) or ammonia specifications of §117.1110(b) of this title (relating to Emission Specifications for Attainment Demonstration), the executive director may approve emission specifications different from §117.1105 of this title or the CO or ammonia specifications in §117.1110(b) of this title for that unit. The executive director:

(1) shall consider on a case-by-case basis the technological and economic circumstances of the individual unit;

(2) shall determine that such specifications are the result of the lowest emission limitation the unit is capable of meeting after the application of controls to meet the nitrogen oxides emission specifications of §117.1105 or §117.1110 of this title, as applicable; and

(3) in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant where the unit is located to meet emission specifications through system-wide averaging at maximum capacity.

(b) Any owner or operator affected by the executive director's decision to deny an alternative case specific emission specification may file a motion to overturn the executive director's decision. The requirements of §50.139 of this title (relating to Motion to Overturn Executive Director's Decision) apply. Executive director approval does not necessarily constitute satisfaction of all federal requirements nor eliminate the need for approval by the United States Environmental Protection Agency in cases where specified criteria for determining equivalency have not been clearly identified in applicable sections of this division (relating to Dallas-Fort Worth Ozone Nonattainment Area Utility Electric Generation Sources).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702055

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

30 TAC §§117.1200, 117.1203, 117.1205, 117.1210, 117.1215, 117.1220, 117.1225, 117.1235, 117.1240, 117.1245, 117.1252, 117.1254, 117.1256

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers; §5.103, concerning Rules; and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq ., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.1200.Applicability.

(a) The provisions of this division (relating to Houston-Galveston-Brazoria Ozone Nonattainment Area Utility Electric Generation Sources) apply to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners in turbine exhaust ducts used in an electric power generating system, as defined in §117.10 of this title (relating to Definitions), that is located within the Houston-Galveston-Brazoria ozone nonattainment area and is owned or operated by:

(1) a municipality or a Public Utility Commission of Texas (PUC) regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or

(2) an electric cooperative, municipality, river authority, or public utility.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702056

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

4. DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA UTILITY ELECTRIC GENERATION SOURCES

30 TAC §§117.1300, 117.1303, 117.1310, 117.1325, 117.1335, 117.1340, 117.1345, 117.1350, 117.1354, 117.1356

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.1300.Applicability.

(a) The provisions of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources) apply to utility boilers, auxiliary steam boilers, stationary gas turbines, and duct burners used in turbine exhaust ducts used in an electric power generating system, as defined in §117.10 of this title (relating to Definitions) and that is located within the Dallas-Fort Worth eight-hour ozone nonattainment area and is owned or operated by:

(1) a municipality or a Public Utility Commission of Texas (PUC) regulated utility, or any of their successors, regardless of whether the successor is a municipality or is regulated by the PUC; or

(2) an electric cooperative, municipality, river authority, or public utility.

§117.1310.Emission Specifications for Eight-Hour Attainment Demonstration.

(a) Nitrogen oxides (NO _X ) emission specifications. The owner or operator of any utility boiler, auxiliary steam boiler, or stationary gas turbine subject to this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources) shall not allow the discharge into the atmosphere, emissions of NO _X in excess of the following:

(1) utility boilers:

(A) 0.06 pounds per million British thermal units (lb/MMBtu) heat input from utility boilers that are part of a small utility system, as defined in §117.10 of this title (relating to Definitions):

(i) on a rolling 24-hour average basis during the months of March through October of each calendar year; and

(ii) on a rolling 30-day average basis during the months of November, December, January, and February of each calendar year;

(B) 0.033 lb/MMBtu heat input from utility boilers that are part of a large utility system, as defined in §117.10 of this title:

(i) on a rolling 24-hour average basis during the months of March through October of each calendar year; and

(ii) on a rolling 30-day average basis during the months of November, December, January, and February of each calendar year;

(D) 0.033 lb/MMBtu heat input on a system-wide heat input weighted average basis for utility boilers that are part of a large utility system, as defined in §117.10 of this title:

(i) on a rolling 168-hour average basis for each hour during which fuel was combusted in any unit in the system; and

(ii) determined according to the following equation:

Figure: 30 TAC §117.1310(a)(1)(D)(ii)

(2) auxiliary steam boilers:

(A) 0.26 lb/MMBtu heat input on a rolling 24-hour average and 0.20 lb/MMBtu heat input on a 30-day rolling average while firing natural gas or a combination of natural gas and waste oil;

(B) 0.30 lb/MMBtu heat input on a rolling 24-hour averaging period while firing fuel oil only;

(C) the heat input weighted average of the applicable emission specifications specified in subparagraphs (A) and (B) of this paragraph on a rolling 24-hour averaging period while firing a mixture of natural gas and fuel oil, as follows:

Figure: 30 TAC §117.1310(a)(2)(C)

(D) for each auxiliary steam boiler that is an affected facility as defined by New Source Performance Standards (NSPS) 40 Code of Federal Regulations Part 60, Subparts D, Db, or Dc, the applicable NSPS NO _X emission limit, unless the boiler is also subject to a more stringent permit emission limit, in which case the more stringent emission limit applies. Each auxiliary steam boiler subject to an emission specification under this subparagraph is not subject to the emission specifications of subparagraphs (A), (B), or (C) of this paragraph.

(3) stationary gas turbines:

(A) with a megawatt (MW) rating greater than or equal to 30 MW and an annual electric output in megawatt-hr (MW-hr) of greater than or equal to the product of 2,500 hours and the MW rating of the unit, NO_X emissions in excess of a block one-hour average of:

(i) 42 parts per million by volume (ppmv) at 15% oxygen (O₂ ), dry basis, while firing natural gas; and

(ii) 65 ppmv at 15% O ₂ , dry basis, while firing fuel oil; and

(B) used for peaking service with an annual electric output in MW-hr of less than the product of 2,500 hours and the MW rating of the unit NO _X emissions in excess of a block one-hour average of:

(i) 0.20 lb/MMBtu heat input while firing natural gas; and

(ii) 0.30 lb/MMBtu heat input while firing fuel oil.

(b) Related emissions. The owner or operator of any unit subject to the emission specifications of subsection (a) of this section shall not allow emission in excess of the following, except as provided in §117.1325 of this title (relating to Alternative Case Specific Specifications):

(1) carbon monoxide (CO):

(A) for utility boilers or auxiliary steam boilers, 400 ppmv at 3.0% O ₂ , dry (or alternatively, 0.30 lb/MMBtu heat input for gas-fired units and 0.31 lb/MMBtu heat input for oil-fired units), based on:

(i) a one-hour average for units not equipped with a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) for CO; or

(ii) a rolling 24-hour averaging period for units equipped with CEMS or PEMS for CO; and

(B) for any stationary gas turbine with a MW rating greater than or equal to 10 MW, CO emissions in excess of a block one-hour average of 132 ppmv at 15% O ₂ , dry basis; and

(2) ammonia:

(A) for units that inject urea or ammonia into the exhaust stream for NO _X control, 10 ppmv, at 3.0% O₂ , dry, for boilers and 15% O ₂ , dry, for stationary gas turbines (including duct burners used in turbine exhaust ducts), based on:

(i) a block one-hour averaging period for units not equipped with a CEMS or PEMS for ammonia; or

(ii) a rolling 24-hour averaging period for units equipped with CEMS or PEMS for ammonia; and

(B) for all other units, 20 ppmv based on a block one-hour averaging period.

(1) An owner or operator may use §117.9800 of this title (relating to Use of Emission Credits for Compliance) to comply with the NO_X emission specifications of this section.

(2) Section 117.1325 of this title is not an applicable method of compliance with the NO _X emission specifications of this section.

(3) An owner or operator may petition the executive director for an alternative to the CO or ammonia specifications of this section in accordance with §117.1325 of this title.

§117.1345.Notification, Recordkeeping, and Reporting Requirements.

(a) Startup and shutdown records. For units subject to the startup and/or shutdown provisions of §101.222 of this title (relating to Demonstrations), hourly records must be made of startup and/or shutdown events and maintained for a period of at least two years. Records must be available for inspection by the executive director, United States Environmental Protection Agency, and any local air pollution control agency having jurisdiction upon request. These records must include, but are not limited to: type of fuel burned; quantity of each type fuel burned; gross and net energy production in megawatt-hours (MW-hr); and the date, time, and duration of the event.

(b) Notification. The owner or operator of a unit subject to the emission specifications of this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources) shall submit notification to the appropriate regional office and any local air pollution control agency having jurisdiction as follows:

(1) written notification of the date of any testing conducted under §117.1335 of this title (relating to Initial Demonstration of Compliance) at least 15 days prior to such date; and

(2) written notification of the date of any continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) performance evaluation conducted under §117.1340 of this title (relating to Continuous Demonstration of Compliance) at least 15 days prior to such date.

(c) Reporting of test results. The owner or operator of an affected unit shall furnish the Office of Compliance and Enforcement, the appropriate regional office, and any local air pollution control agency having jurisdiction a copy of any testing conducted under §117.1335 of this title or any CEMS or PEMS performance evaluation conducted under §117.1340 of this title:

(1) within 60 days after completion of such testing or evaluation; and

(2) not later than the appropriate compliance schedules specified in §117.9130 of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Utility Electric Generation Sources).

(d) Semiannual reports. The owner or operator of a unit required to install a CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring system under §117.1340 of this title shall report in writing to the executive director on a semiannual basis any exceedance of the applicable emission limitations in this division and the monitoring system performance. All reports must be postmarked or received by the 30th day following the end of each calendar semiannual period. Written reports must include the following information:

(1) the magnitude of excess emissions computed in accordance with 40 Code of Federal Regulations (CFR) §60.13(h), any conversion factors used, the date and time of commencement and completion of each time period of excess emissions, and the unit operating time during the reporting period. For stationary gas turbines using steam-to-fuel or water-to-fuel ratio monitoring to demonstrate compliance in accordance with §117.1340 of this title, excess emissions are computed as each one-hour period that the hourly steam-to-fuel or water-to-fuel ratio is less than the ratio determined to result in compliance during the initial demonstration of compliance test required by §117.1335 of this title;

(2) specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected unit. The nature and cause of any malfunction (if known) and the corrective action taken or preventative measures adopted;

(3) the date and time identifying each period that the continuous monitoring system was inoperative, except for zero and span checks and the nature of the system repairs or adjustments;

(4) when no excess emissions have occurred or the continuous monitoring system has not been inoperative, repaired, or adjusted, such information must be stated in the report; and

(5) if the total duration of excess emissions for the reporting period is less than 1.0% of the total unit operating time for the reporting period and the CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is less than 5.0% of the total unit operating time for the reporting period, only a summary report form (as outlined in the latest edition of the commission's Guidance for Preparation of Summary, Excess Emission, and Continuous Monitoring System Reports ) must be submitted, unless otherwise requested by the executive director. If the total duration of excess emissions for the reporting period is greater than or equal to 1.0% of the total operating time for the reporting period or the CEMS or steam-to-fuel or water-to-fuel ratio monitoring system downtime for the reporting period is greater than or equal to 5.0% of the total operating time for the reporting period, a summary report and an excess emission report must both be submitted.

(e) Recordkeeping. The owner or operator of a unit subject to the requirements of this division shall maintain records of the data specified in this subsection. Records must be kept for a period of at least five years and made available for inspection by the executive director, United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction upon request. Operating records for each unit must be recorded and maintained at a frequency equal to the applicable emission specification averaging period, or for units claimed exempt from the emission specifications based on low annual capacity factor, monthly. Records must include:

(1) emission rates in units of the applicable standards;

(2) gross energy production in MW-hr (not applicable to auxiliary steam boilers), except as specified in paragraph (8) of this subsection;

(3) quantity and type of fuel burned;

(4) the injection rate of reactant chemicals (if applicable); and

(5) emission monitoring data, in accordance with §117.1340 of this title, including:

(A) the date, time, and duration of any malfunction in the operation of the monitoring system, except for zero and span checks, if applicable, and a description of system repairs and adjustments undertaken during each period;

(B) the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or operating parameter monitoring systems; and

(6) the results of performance testing, including initial demonstration of compliance testing conducted in accordance with §117.1335 of this title;

(7) records of hours of operation;

(8) for any unit that the owner or operator elects to comply with the output-based emission specification in §117.1310(a)(1)(C) of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration):

(A) hourly records of the gross energy production in MW-hr;

(B) records of hourly and annual average NO _X emissions in pounds per megawatt-hour (lb/MW-hr); and

(C) the averaging period for the annual average NO _X emissions in lb/MW-hr, for demonstrating continuous compliance is from January 1 through December 31 of each calendar year, beginning on January 1, 2010; and

(9) for any unit that the owner or operator elects to comply with the system-wide heat input weighted average emission specification in §117.1310(a)(1)(D) of this title:

(A) hourly records of average NO _X emissions in pounds per million British thermal units (lb/MMBtu) for each utility boiler in the system;

(B) hourly records of average heat input in million British thermal units per hour (MMBtu/hr) for each utility boiler in the system;

(D) hourly records of the rolling 168-hour average of the system-wide heat input weighted average NO _X emissions in lb/MMBtu.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702057

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter D. COMBUSTION CONTROL AT MINOR SOURCES IN OZONE NONATTAINMENT AREAS

1. HOUSTON-GALVESTON-BRAZORIA OZONE NONATTAINMENT AREA MINOR SOURCES

30 TAC §§117.2000, 117.2003, 117.2010, 117.2025, 117.2030, 117.2035, 117.2045

STATUTORY AUTHORITY

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.2035.Monitoring and Testing Requirements.

(a) Totalizing fuel flow meters.

(1) The owner or operator of each unit subject to §117.2010 of this title (relating to Emission Specifications) and subject to Chapter 101, Subchapter H, Division 3 of this title (relating to Mass Emissions Cap and Trade Program), or of each unit claimed exempt under §117.2003(b) of this title (relating to Exemptions) shall install, calibrate, maintain, and operate totalizing fuel flow meters with an accuracy of ± 5%, to individually and continuously measure the gas and liquid fuel usage. A computer that collects, sums, and stores electronic data from continuous fuel flow meters is an acceptable totalizer. The owner or operator of units with totalizing fuel flow meters installed prior to March 31, 2005, that do not meet the accuracy requirements of this subsection shall either recertify or replace existing meters to meet the ± 5% accuracy required as soon as practicable, but no later than March 31, 2007. For the purpose of compliance with this subsection for units having pilot fuel supplied by a separate fuel system or from an unmonitored portion of the same fuel system, the fuel flow to pilots may be calculated using the manufacturer's design flow rates rather than measured with a fuel flow meter. The calculated pilot fuel flow rate must be added to the monitored fuel flow when fuel flow is totaled.

(2) The following are alternatives to the fuel flow monitoring requirements of this subsection.

(A) Units operating with a nitrogen oxides (NO _X ) and diluent continuous emissions monitoring system (CEMS) under subsection (c) of this section may monitor stack exhaust flow using the flow monitoring specifications of 40 Code of Federal Regulations (CFR) Part 60, Appendix B, Performance Specification 6 or 40 CFR Part 75, Appendix A.

(B) Units that vent to a common stack with a NO _X and diluent CEMS under subsection (c) of this section may use a single totalizing fuel flow meter.

(C) Diesel engines operating with run time meters may meet the fuel flow monitoring requirements of this subsection through monthly fuel use records.

(D) Units of the same category of equipment subject to Chapter 101, Subchapter H, Division 3 of this title may share a single totalizing fuel flow meter provided:

(i) the owner or operator performs a stack test in accordance with subsection (e) of this section for each unit sharing the totalizing fuel flow meter; and

(ii) the testing results from the unit with the highest emission rate (in pounds per million British thermal units or grams per horsepower-hour) are used for reporting purposes in §101.359 of this title (relating to Reporting) for all units sharing the totalizing fuel flow meter.

(E) The owner or operator of a unit or units claimed exempt under §117.2003(b) of this title, located at an independent school district may demonstrate compliance with the exemption by the following:

(i) in addition to the records required by §117.2045(a)(1) of this title (relating to Recordkeeping and Reporting Requirements), maintain the following monthly records in either electronic or written format. These records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction;

(I) total fuel usage for the entire site;

(II) the estimated hours of operation for each unit;

(III) the estimated average operating rate (e.g., a percentage of maximum rated capacity) for each unit; and

(IV) the estimated fuel usage for each unit; and

(ii) within 60 days of written request by the executive director, submit for review and approval all methods, engineering calculations, and process information used to estimate the hours of operation, operating rates, and fuel usage for each unit.

(F) The owner or operator of units claimed exempt under §117.2003(b) of this title may share a single totalizing fuel flow meter to demonstrate compliance with the exemption, provided that:

(i) all affected units at the site qualify for the exemption under §117.2003(b) of this title; and

(ii) the total fuel usage for all units at the site is less than:

(I) the annual fuel usage limitation in §117.2003(b)(1) of this title; or

(II) the annual fuel usage limitation in §117.2003(b)(2) of this title when all affected units at the site are equal to or greater than 5.0 million British thermal units per hour.

(b) Oxygen (O ₂ ) monitors. If the owner or operator installs an O ₂ monitor, the criteria in §117.8100(a) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources) should be considered the appropriate guidance for the location and calibration of the monitor.

(c) NO _X monitors. If the owner or operator installs a CEMS or predictive emissions monitoring system (PEMS), it must meet the requirements of §117.8100(a) or (b) of this title. If a PEMS is used, the PEMS must predict the pollutant emissions in the units of the applicable emission specifications of this division (relating to Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources).

(d) Monitor installation schedule. Installation of monitors must be performed in accordance with the schedule specified in §117.9200 of this title (relating to Compliance Schedule for Houston-Galveston-Brazoria Ozone Nonattainment Area Minor Sources).

(e) Testing requirements. The owner or operator of any unit subject to §117.2010 of this title shall comply with the following testing requirements.

(1) Each unit must be tested for NO _X , carbon monoxide (CO), and O ₂ emissions.

(2) One of the ammonia monitoring procedures specified in §117.8130 of this title (relating to Ammonia Monitoring) must be used to demonstrate compliance with the ammonia emission specification of §117.2010(i)(2) of this title for units that inject urea or ammonia into the exhaust stream for NO _X control.

(3) For units not equipped with CEMS or PEMS, all testing must be conducted according to §117.8000 of this title (relating to Stack Testing Requirements). In lieu of the test methods specified in §117.8000 of this title, the owner or operator may use American Society for Testing and Materials (ASTM) D6522-00 to perform the NO _X , CO, and O ₂ testing required by this subsection on natural gas-fired reciprocating engines, combustion turbines, boilers, and process heaters. If the owner or operator elects to use ASTM D6522-00 for the testing requirements, the report must contain the information specified in §117.8010 of this title (relating to Compliance Stack Test Reports).

(4) Test results must be reported in the units of the applicable emission specifications and averaging periods. If compliance testing is based on 40 CFR Part 60, Appendix A reference methods, the report must contain the information specified in §117.8010 of this title.

(5) For units equipped with CEMS or PEMS, the CEMS or PEMS must be installed and operational before testing under this subsection. Verification of operational status must, at a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

(6) Initial compliance with §117.2010 of this title for units operating with CEMS or PEMS must be demonstrated after monitor certification testing using the NO _X CEMS or PEMS.

(7) For units not operating with CEMS or PEMS, the following apply.

(A) Retesting as specified in paragraphs (1) - (4) of this subsection is required within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate.

(B) Retesting as specified in paragraphs (1) - (4) of this subsection may be conducted at the discretion of the owner or operator after any modification that could reasonably be expected to decrease the NO_X emission rate, including, but not limited to, installation of post-combustion controls, low-NO _X burners, low excess air operation, staged combustion (for example, overfire air), flue gas recirculation, and fuel-lean and conventional (fuel-rich) reburn.

(C) The NO _X emission rate determined by the retesting must establish a new emission factor to be used to calculate actual emissions from the date of the retesting forward. Until the date of the retesting, the previously determined emission factor must be used to calculate actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.

(8) Testing must be performed in accordance with the schedule specified in §117.9200 of this title.

(9) All test reports must be submitted to the executive director for review and approval within 60 days after completion of the testing.

(f) Emission allowances.

(1) For sources that are subject to Chapter 101, Subchapter H, Division 3 of this title, the NO _X testing and monitoring data of subsections (a) - (e) of this section, together with the level of activity, as defined in §101.350 of this title (relating to Definitions), must be used to establish the emission factor calculating actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.

(2) The emission factor in subsection (e)(7) of this section or paragraph (1) of this subsection is multiplied by the unit's level of activity to determine the unit's actual emissions for compliance with Chapter 101, Subchapter H, Division 3 of this title.

(g) Run time meters. The owner or operator of any stationary diesel engine claimed exempt using the exemption of §117.2003(a)(2)(E), (H), or (I) of this title shall record the operating time with an elapsed run time meter. Any run time meter installed on or after October 1, 2001, must be non-resettable.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702058

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. DALLAS-FORT WORTH EIGHT-HOUR OZONE NONATTAINMENT AREA MINOR SOURCES

30 TAC §§117.2100, 117.2103, 117.2110, 117.2125, 117.2130, 117.2135, 117.2145

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.2100.Applicability.

This division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources) applies in the Dallas-Fort Worth eight-hour ozone nonattainment area to stationary, reciprocating internal combustion engines at any stationary source of nitrogen oxides (NO _X ) that is not a major source of NO _X .

§117.2103.Exemptions.

This division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources) does not apply to the following stationary engines, except as specified in §§117.2130(c), 117.2135(e), and 117.2145(b) and (c) of this title (relating to Operating Requirements; Monitoring, Notification, and Testing Requirements; and Recordkeeping and Reporting Requirements):

(1) engines with a horsepower (hp) rating of less than 50 hp;

(2) engines used in research and testing;

(3) engines used for purposes of performance verification and testing;

(4) engines used solely to power other engines or gas turbines during startups;

(5) engines operated exclusively in emergency situations, except that operation for testing or maintenance purposes is allowed for up to 100 hours per year, based on a rolling 12-month average. Any new, modified, reconstructed, or relocated stationary diesel engine placed into service on or after June 1, 2007, is ineligible for this exemption. For the purposes of this subparagraph, the terms "modification'' and "reconstruction'' have the meanings defined in §116.10 of this title (relating to General Definitions) and 40 Code of Federal Regulations (CFR) §60.15 (December 16, 1975), respectively, and the term "relocated'' means to newly install at an account, as defined in §101.1 of this title (relating to Definitions), a used engine from anywhere outside that account;

(6) engines used in response to and during the existence of any officially declared disaster or state of emergency;

(7) engines used directly and exclusively by the owner or operator for agricultural operations necessary for the growing of crops or raising of fowl or animals;

(8) diesel engines placed into service before June 1, 2007, that:

(A) operate less than 100 hours per year, based on a rolling 12-month average; and

(B) have not been modified, reconstructed, or relocated on or after June 1, 2007. For the purposes of this clause, the terms "modification'' and "reconstruction'' have the meanings defined in §116.10 of this title and 40 CFR §60.15 (December 16, 1975), respectively, and the term "relocated'' means to newly install at an account, as defined in §101.1 of this title, a used engine from anywhere outside that account; and

(9) new, modified, reconstructed, or relocated stationary diesel engines placed into service on or after June 1, 2007, that:

(A) operate less than 100 hours per year, based on a rolling 12-month average, in other than emergency situations; and

(B) meet the corresponding emission standard for non-road engines listed in 40 CFR §89.112(a), Table 1 (October 23, 1998) and in effect at the time of installation, modification, reconstruction, or relocation. For the purposes of this subparagraph, the terms "modification'' and "reconstruction'' have the meanings defined in §116.10 of this title and 40 CFR §60.15 (December 16, 1975), respectively, and the term "relocated'' means to newly install at an account, as defined in §101.1 of this title, a used engine from anywhere outside that account.

§117.2110.Emission Specifications for Eight-Hour Attainment Demonstration.

(a) The owner or operator of any source subject to this division (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources) shall not allow the discharge into the atmosphere emissions of nitrogen oxides (NO _X ) in excess of the following emission specifications.

(1) Emission specifications for stationary, gas-fired, reciprocating internal combustion engines are as follows:

(A) rich-burn engines:

(i) fired on landfill gas, 0.60 grams per horsepower-hour (g/hp-hr); and

(ii) all other rich-burn engines, 0.50 g/hp-hr; and

(B) lean-burn engines:

(i) placed into service before June 1, 2007, that have not been modified, reconstructed, or relocated on or after June 1, 2007, 0.70 g/hp-hr; and

(ii) placed into service, modified, reconstructed, or relocated on or after June 1, 2007:

(I) fired on landfill gas, 0.60 g/hp-hr; and

(II) all other lean-burn engines, 0.50 g/hp-hr.

(2) The emission specification for stationary, dual-fuel, reciprocating internal combustion engines is 5.83 g/hp-hr.

(3) Emission specifications for stationary, diesel, reciprocating internal combustion engines are as follows:

(A) placed into service before March 1, 2009, that have not been modified, reconstructed, or relocated on or after March 1, 2009, the lower of 11.0 g/hp-hr or the emission rate established by testing, monitoring, manufacturer's guarantee, or manufacturer's other data; and

(B) for engines not subject to subparagraph (A) of this paragraph:

(i) with a horsepower (hp) rating of 50 hp or greater, but less than 100 hp, that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 3.3 g/hp-hr;

(ii) with a horsepower rating of 100 hp or greater, but less than or equal to 750 hp, that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 2.8 g/hp-hr; and

(iii) with a horsepower rating of 750 hp or greater that are installed, modified, reconstructed, or relocated on or after March 1, 2009, 4.5 g/hp-hr.

(4) As an alternative to the emission specifications in paragraphs (1) - (3) of this subsection for units with an annual capacity factor of 0.0383 or less, 0.060 lb/MMBtu heat input. For units placed into service on or before December 31, 2000, the annual capacity factor as of December 31, 2000, must be used to determine eligibility for the alternative emission specification of this paragraph. For units placed into service after December 31, 2000, a 12-month rolling average must be used to determine the annual capacity factor.

(5) For the purposes of this subsection, the terms "modification" and "reconstruction" have the meanings defined in §116.10 of this title (relating to General Definitions) and 40 Code of Federal Regulations §60.15 (December 16, 1975), respectively, and the term "relocated" means to newly install at an account, as defined in §101.1 of this title (relating to Definitions), a used engine from anywhere outside that account.

(b) The averaging time for the NO _X emission specifications of subsection (a) of this section is as follows:

(1) if the unit is operated with a NO _X continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) under §117.2135(c) of this title (relating to Monitoring, Notification, and Testing Requirements), either as:

(A) a rolling 30-day average period, in the units of the applicable standard;

(B) a block one-hour average, in the units of the applicable standard, or alternatively;

(C) a block one-hour average, in pounds per hour, for boilers, calculated as the product of the boiler's maximum rated capacity and its applicable limit in lb/MMBtu; or

(2) if the unit is not operated with a NO _X CEMS or PEMS under §117.2135(c) of this title, a block one-hour average, in the units of the applicable standard.

(c) The maximum rated capacity used to determine the applicability of the emission specifications in subsection (a) of this section must be the greater of the following:

(1) the maximum rated capacity as of December 31, 2000; or

(2) the maximum rated capacity after December 31, 2000.

(d) A unit's classification is determined by the most specific classification applicable to the unit as of December 31, 2000. For example, a unit that is classified as a stationary gas-fired engine as of December 31, 2000, but subsequently is authorized to operate as a dual-fuel engine, must be classified as a stationary gas-fired engine for the purposes of this chapter.

(e) Changes after December 31, 2000, to a unit subject to an emission specification in subsection (a) of this section (ESAD unit) that result in increased NO _X emissions from a unit not subject to an emission specification in subsection (a) of this section (non-ESAD unit), such as redirecting one or more fuel or waste streams containing chemical-bound nitrogen to an incinerator or a flare, is only allowed if:

(1) the increase in NO _X emissions at the non-ESAD unit is determined using a CEMS or PEMS that meets the requirements of §117.2135(c) of this title, or through stack testing that meets the requirements of §117.2135(f) of this title; and

(2) emission credits equal to the increase in NO _X emissions at the non-ESAD unit are obtained and used in accordance with §117.9800 of this title (relating to Use of Emission Credits for Compliance).

(f) A source that met the definition of major source on December 31, 2000, is always classified as a major source for purposes of this chapter. A source that did not meet the definition of major source (i.e., was a minor source, or did not yet exist) on December 31, 2000, but becomes a major source at any time after December 31, 2000, is from that time forward always classified as a major source for purposes of this chapter.

(g) The availability under subsection (a)(4) of this section of an emission specification for units with an annual capacity factor of 0.0383 or less is based on the unit's status on December 31, 2000. Reduced operation after December 31, 2000, cannot be used to qualify for a more lenient emission specification under subsection (a)(4) of this section than would otherwise apply to the unit.

(h) No person shall allow the discharge into the atmosphere from any unit subject to NO _X emission specifications in subsection (a) of this section, emissions in excess of the following, except as provided in §117.2125 of this title (relating to Alternative Case Specific Specifications):

(1) carbon monoxide (CO), 400 ppmv at 3.0% O ₂ , dry basis (or alternatively, 3.0 g/hp-hr for stationary internal combustion engines):

(A) on a rolling 24-hour averaging period, for units equipped with CEMS or PEMS for CO; and

(B) on a one-hour average, for units not equipped with CEMS or PEMS for CO; and

(2) for units that inject urea or ammonia into the exhaust stream for NO _X control, ammonia emissions of 10 ppmv at 15% O ₂ , dry, for gas-fired lean-burn engines; and 3.0% O ₂ , dry, for all other units, based on:

(A) a block one-hour averaging period for units not equipped with a CEMS or PEMS for ammonia; or

(B) a rolling 24-hour averaging period for units equipped with CEMS or PEMS for ammonia.

(i) An owner or operator may use emission reduction credits as specified in §117.9800 of this title to comply with the NO _X emission specifications of this section.

§117.2130.Operating Requirements.

(a) The owner or operator shall operate any unit subject to the emission specifications of §117.2110 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) in compliance with those specifications.

(b) All units subject to §117.2110 of this title must be operated so as to minimize nitrogen oxides (NO _X ) emissions, consistent with the emission control techniques selected, over the unit's operating or load range during normal operations. Such operational requirements include the following.

(1) Each unit controlled with post-combustion control techniques must be operated such that the reducing agent injection rate is maintained to limit NO _X concentrations to less than or equal to the NO _X concentrations achieved at maximum rated capacity.

(2) Each stationary internal combustion engine controlled with nonselective catalytic reduction must be equipped with an automatic air-fuel ratio (AFR) controller that operates on exhaust O ₂ or CO control and maintains AFR in the range required to meet the engine's applicable emission specifications.

(3) Each stationary internal combustion engine must be checked for proper operation according to §117.8140(b) of the title (relating to Emission Monitoring for Engines).

(c) No person shall start or operate any stationary diesel or dual-fuel engine for testing or maintenance between the hours of 6:00 a.m. and noon, except:

(1) for specific manufacturer's recommended testing requiring a run of over 18 consecutive hours;

(3) firewater pumps for emergency response training conducted in the months of April through October.

§117.2135.Monitoring, Notification, and Testing Requirements.

(a) Oxygen (O ₂ ) monitors. If the owner or operator installs an O ₂ monitor, the criteria in §117.8100(a) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources) should be considered the appropriate guidance for the location and calibration of the monitor.

(b) Nitrogen oxides (NO _X ) monitors. If the owner or operator installs a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS), the CEMS or PEMS must meet the requirements of §117.8100(a) or (b) of this title. If a PEMS is used, the PEMS must predict the pollution emissions in the units of the applicable emission limitations of this division.

(c) Monitor installation schedule. Installation of monitors must be performed in accordance with the schedule specified in §117.9210 of this title (relating to Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources).

(d) Testing requirements. The owner or operator of any unit subject to §117.2110 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) shall comply with the following testing requirements.

(1) Each unit must be tested for NO _X , carbon monoxide (CO), and O ₂ emissions.

(2) One of the ammonia monitoring procedures specified in §117.8130 of this title (relating to Ammonia Monitoring) must be used to demonstrate compliance with the ammonia emission specification of §117.2110(h)(2) of this title for units that inject urea or ammonia into the exhaust stream for NO _X control.

(3) For units not equipped with CEMS or PEMS, all testing must be conducted according to §117.8000 of this title (relating to Stack Testing Requirements). In lieu of the test methods specified in §117.8000 of this title, the owner or operator may use American Society for Testing and Materials (ASTM) D6522-00 to perform the NO _X , CO, and O ₂ testing required by this subsection on natural gas-fired reciprocating engines. If the owner or operator elects to use ASTM D6522-00 for the testing requirements, the report must contain the information specified in §117.8010 of this title (relating to Compliance Stack Test Reports).

(4) Test results must be reported in the units of the applicable emission specifications and averaging periods. If compliance testing is based on 40 Code of Federal Regulations Part 60, Appendix A reference methods, the report must contain the information specified in §117.8010 of this title.

(6) Initial compliance with the emission specifications of §117.2110 of this title for units operating with CEMS or PEMS must be demonstrated after monitor certification testing using the NO _X CEMS or PEMS.

(7) For units not operating with CEMS or PEMS, the following apply.

(A) Retesting as specified in paragraphs (1) - (4) of this subsection is required within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate.

(C) Stationary, reciprocating internal combustion engines not equipped with CEMS or PEMS must be periodically tested for NO _X and CO emissions as specified in §117.8140(a) of this title (relating to Emission Monitoring for Engines).

(8) Testing must be performed in accordance with the schedule specified in §117.9210 of this title.

(9) All test reports must be submitted to the executive director for review and approval within 60 days after completion of the testing.

(10) The owner or operator of an affected unit in the Dallas-Fort Worth eight-hour ozone nonattainment area must submit written notification of any CEMS or PEMS relative accuracy test audit (RATA) or testing required under this section to the appropriate regional office and any local air pollution control agency having jurisdiction at least 15 days in advance of the date of RATA or testing.

(e) Run time meters. The owner or operator of any stationary diesel engine claimed exempt using the exemption of §117.2103(5), (8), or (9) of this title shall record the operating time with a non-resettable elapsed run time meter.

§117.2145.Recordkeeping and Reporting Requirements.

(a) Recordkeeping. The owner or operator of a unit subject to §117.2110 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) shall maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction. The records must include:

(1) for each unit using a continuous emission monitoring system (CEMS) or predictive emission monitoring system (PEMS) in accordance with §117.2135(b) of this title (relating to Monitoring, Notification, and Testing Requirements) monitoring records of:

(A) hourly emissions for units complying with an emission specification enforced on a block one-hour average; and

(B) daily emissions for units complying with an emission specification enforced on a rolling 30-day average. Emissions must be recorded in units of:

(i) pounds per million British thermal units (MMBtu) heat input; and

(ii) pounds or tons per day;

(2) for each stationary internal combustion engine subject to §117.2110 of this title, records of:

(A) emissions measurements required by §117.2130(b)(3) of this title (relating to Operating Requirements); and

(B) catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken;

(3) records of carbon monoxide (CO) measurements specified in §117.2130(b)(3) of this title;

(4) records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring systems; and

(5) records of the results of performance testing, including the testing conducted in accordance with §117.2135(d) of this title.

(b) Records for exempt engines. Written records of the number of hours of operation for each day's operation must be made for each engine claimed exempt under §117.2103(5), (8), or (9) of this title or §117.2130(b)(3) of this title. In addition, for each engine claimed exempt under §117.2103(5) of this title, written records must be maintained of the purpose of engine operation and, if operation was for an emergency situation, identification of the type of emergency situation and the start and end times and date(s) of the emergency situation. The records must be maintained for at least five years and must be made available upon request to representatives of the executive director, the United States Environmental Protection Agency, or any local air pollution control agency having jurisdiction.

(c) Records of operation for testing and maintenance. The owner or operator of each stationary diesel or dual-fuel engine shall maintain the following records for at least five years and make them available upon request by authorized representatives of the executive director, the United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction:

(1) date(s) of operation;

(2) start and end times of operation;

(3) identification of the engine; and

(4) total hours of operation for each month and for the most recent 12 consecutive months.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702059

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter E. MULTI-REGION COMBUSTION CONTROL

1. UTILITY ELECTRIC GENERATION IN EAST AND CENTRAL TEXAS

30 TAC §§117.3000, 117.3003, 117.3005, 117.3010, 117.3020, 117.3025, 117.3035, 117.3040, 117.3045, 117.3054, 117.3056

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.3020.System Cap.

(a) An owner or operator may achieve compliance with the nitrogen oxides (NO _X ) emission specifications of §117.3010 of this title (relating to Emission Specifications) by achieving equivalent NO _X emission reductions obtained by compliance with a system cap emission limitation in accordance with the requirements of this section.

(b) Each unit within an electric power generating system, as defined in §117.10 of this title (relating to Definitions), that would otherwise be subject to the NO _X emission specifications of §117.3010 of this title must be included in the system cap.

Figure: 30 TAC §117.3020(c)

(d) The NO_X emissions monitoring required by §117.3040 of this title (relating to Continuous Demonstration of Compliance) for each unit in the system cap must be used to demonstrate continuous compliance with the system cap.

(e) For each operating unit, the owner or operator shall use one of the following methods to provide substitute emissions compliance data during periods when the NO_X monitor is off-line:

(1) if the NO _X monitor is a continuous emissions monitoring system (CEMS):

(A) subject to 40 Code of Federal Regulations (CFR) Part 75, use the missing data procedures specified in 40 CFR Part 75, Subpart D (Missing Data Substitution Procedures); or

(B) subject to 40 CFR Part 75, Appendix E, use the missing data procedures specified in 40 CFR Part 75, Appendix E, §2.5 (Missing Data Procedures);

(2) use Appendix E monitoring in accordance with §117.3040(e) of this title;

(3) if the NO _X monitor is a predictive emissions monitoring system (PEMS):

(A) use the methods specified in 40 CFR Part 75, Subpart D; or

(B) use calculations in accordance with §117.8110(b) of this title (relating to Emission Monitoring System Requirements for Utility Electric Generation Sources); or

(4) use the maximum emission rate as measured by the testing conducted in accordance with §117.3035(d) of this title (relating to Initial Demonstration of Compliance).

(f) The owner or operator of any unit subject to a system cap shall maintain daily records indicating the NO _X emissions and fuel usage from each unit and summations of total NO _X emissions and fuel usage for all units under the system cap on a daily basis. Records must also be retained in accordance with §117.3045 of this title (relating to Notification, Recordkeeping, and Reporting Requirements).

(g) The owner or operator of any unit subject to a system cap shall submit annual reports for the monitoring systems in accordance with §117.3045 of this title. The owner or operator shall also report any exceedance of the system cap emission limit in the annual report and shall include an analysis of the cause for the exceedance with appropriate data to demonstrate the amount of emissions in excess of the applicable limit and the necessary corrective actions taken by the company to assure future compliance.

(h) The owner or operator of any unit subject to a system cap shall demonstrate initial compliance with the system cap in accordance with the schedule specified in §117.9300 of this title (relating to Compliance Schedule for Utility Electric Generation in East and Central Texas).

(i) A unit that is permanently retired or decommissioned and rendered inoperable may be included in the system cap emission limit, provided that the permanent shutdown occurred on or after January 1, 1999. The system cap emission limit is calculated in accordance with subsection (b) of this section.

(j) Emission reductions from shutdowns or curtailments that have been used for netting or offset purposes under the requirements of Chapter 116 of this title (relating to Control of Air Pollution by Permits for New Construction or Modification) may not be included in the baseline for establishing the cap.

(k) For the purposes of determining compliance with the system cap emission limit, the contribution of each affected unit that is operating during a startup, shutdown, or emissions event as defined in §101.1 of this title (relating to Definitions) must be calculated from the NO _X emission rate measured by the NO _X monitor, if operating properly. If the NO _X monitor is not operating properly, the substitute data procedures identified in subsection (e) of this section must be used. If neither the NO _X monitor nor the substitute data procedure are operating properly, the owner or operator shall use the maximum daily rate measured during the initial demonstration of compliance, unless the owner or operator provides data demonstrating to the satisfaction of the executive director and United States Environmental Protection Agency that actual emissions were less than maximum emissions during such periods.

(l) An owner or operator of a source of NO _X in any of the east and central Texas attainment counties listed in §117.3000(a)(4) of this title (relating to Applicability) who is participating in the system cap under this section (relating to System Cap) may exceed their system cap provided that the owner or operator is complying with the requirements of Chapter 101, Subchapter H, Division 1, 4, or 5 of this title (relating to Emission Credit Banking and Trading; Discrete Emission Credit Banking and Trading; and System Cap Trading).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702060

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Division 2. CEMENT KILNS

30 TAC §§117.3100, 117.3101, 117.3103, 117.3110, 117.3120, 117.3123, 117.3125, 117.3140, 117.3142, 117.3145

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.3103.Exemptions.

(a) Portland cement kilns exempted from the provisions of this division (relating to Cement Kilns), include any portland cement kiln placed into service on or after December 31, 1999, except as specified in §§117.3110, 117.3120, and 117.3123 of this title (relating to Emission Specifications; Source Cap; and Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements).

(b) Any account in Ellis County with no portland cement kilns in operation prior to January 1, 2001, is exempt from §117.3123 of this title.

(c) After the compliance date specified in §117.9320(c) of this title (relating to Compliance Schedule for Cement Kilns), portland cement kilns that are subject to §117.3123 of this title are exempt from §117.3110 and §117.3120 of this title between March 1 and October 31 of each calendar year.

§117.3123.Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements.

(a) In accordance with the compliance schedule in §117.9320(c) of this title (relating to Compliance Schedule for Cement Kilns), the owner or operator of any portland cement kiln located in Ellis County shall not allow the total nitrogen oxides (NO _X ) emissions from all cement kilns located at the account to exceed the source cap limitation determined according to subsection (b) of this section. The source cap limitation of this section only applies from March 1 through October 31 of each calendar year. Compliance with the 30-day rolling average cap must be demonstrated beginning on March 31 of each calendar year.

(b) The NO_X source cap for an account subject to this section must be calculated according to the following equation.

Figure: 30 TAC §117.3123(b)

(c) The monitoring required by §117.3142 of this title (relating to Emission Testing and Monitoring for Eight-Hour Attainment Demonstration) for each cement kiln subject to this section must be used to demonstrate continuous compliance with the source cap requirements of this section. Compliance with the source cap must be demonstrated on a 30-day rolling average basis, calculated according to §117.3142 of this title.

(d) For any portland cement kiln not operational prior to calendar year 2006 and that is located at an account subject to this section, the following requirements apply.

(1) The cement kiln is subject to the source cap of this section but must not be included in the source cap calculation in subsection (b) of this section.

(2) The requirements of §117.3142 of this title and §117.3145 of this title (relating to Notification, Recordkeeping, and Reporting Requirements) apply.

(3) The NO _X emissions from the kiln must be included in the calculation of 30-day rolling average NO_X emissions according to §117.3142 of this title for compliance with the source cap in subsection (b) of this section.

(e) The owner or operator of each portland cement kiln located in Ellis County shall submit a control plan to the Office of Compliance and Enforcement, the appropriate regional office, and the Chief Engineer's Office, for compliance with the source cap in subsection (b) of this section. The plan must be submitted according to the compliance schedule in §117.9320(c) of this title.

(1) At a minimum, the control plan must include:

(A) the emission point number for each kiln at the account;

(B) the facility identification number for each kiln at the account;

(D) a description of the control measures that have been or will be implemented for each cement kiln for compliance with the source cap.

(2) A revised control plan may be submitted by the owner or operator, along with any required permit applications. Such a plan must adhere to the requirements of this division (relating to Cement Kilns).

(f) For any kiln that injects urea or ammonia for NO _X control, the owner or operator shall not allow ammonia emissions in excess of 10 parts per million by volume at 7.0% oxygen, dry basis, on a 24-hour rolling average basis.

(g) An owner or operator may use §117.9800 of this title (relating to Use of Emission Credits for Compliance) to meet the NO _X emission control requirements of this section, in whole or in part.

§117.3142.Emission Testing and Monitoring for Eight-Hour Attainment Demonstration.

(a) An owner or operator of any portland cement kiln that is subject to the source cap of §117.3123 of this title (relating to Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements) shall comply with the following monitoring requirements.

(1) The nitrogen oxides (NO _X ) monitoring requirements of §117.3140 of this title (relating to Continuous Demonstration of Compliance) apply. The following requirements also apply.

(A) For a single portland cement kiln with multiple exhaust stacks, each individual stack must be analyzed separately.

(B) One continuous emission monitoring system (CEMS) may be shared among portland cement kilns or among multiple exhaust stacks on a single portland cement kiln, provided:

(i) the exhaust stream of each stack is analyzed and reported separately; and

(ii) the CEMS meets the certification requirements of §117.3140(b) of this title for each exhaust stream while the CEMS is operating in the time-shared mode.

(C) All bypass stacks must be monitored continuously, in order to quantify emissions directed through the bypass stack. If the CEMS is located upstream of the bypass stack then:

(i) no effluent streams from other potential sources of NO_X emissions may be introduced between the CEMS and the bypass stack; and

(ii) the owner or operator shall install, operate, and maintain a continuous monitoring system to record automatically the date, time, and duration of each event when the bypass stack is open.

(2) Stack exhaust flow rate must be monitored with a flow meter using the monitoring specifications of 40 Code of Federal Regulations (CFR) Part 60, Appendix B, Performance Specification 6 or 40 CFR Part 75, Appendix A.

(3) For portland cement kilns that inject ammonia or urea for NO _X control, fuel type notwithstanding, ammonia emissions must be monitored according to one of the methods specified in §117.8130(1), (2), or (4) of this title (relating to Ammonia Monitoring) to demonstrate compliance with the ammonia emission specification in §117.3123(f) of this title. The ammonia monitoring requirements of this paragraph only apply from March 1 to October 31 of each calendar year, or any other time the owner or operator injects ammonia or urea for NO _X control.

(4) Installation of monitors must be performed in accordance with the schedule specified in §117.9320(c) of this title (relating to Compliance Schedule for Cement Kilns).

(b) The owner or operator of a portland cement kiln subject to the source cap requirements of §117.3123 of this title shall calculate NO _X emissions for determining compliance with the source cap as follows. The calculation requirements of this subsection only apply from March 1 to October 31 of each calendar year.

(1) Hourly NO _X emissions. Hourly NO _X emissions for each kiln must be calculated according to the following equation.

Figure: 30 TAC §117.3142(b)(1)

(2) Daily NO _X emissions. The daily total NO _X emission for each kiln must be calculated as the sum of the hourly NO _X emissions for each calendar day, reported in tons per day, and must be calculated according to the following equation.

Figure: 30 TAC §117.3142(b)(2)

(3) Thirty-day rolling average. The 30-day rolling average NO _X emissions for the account must be calculated according to the following equation.

Figure: 30 TAC §117.3142(b)(3)

§117.3145.Notification, Recordkeeping, and Reporting Requirements.

(a) Notification. The owner or operator of each portland cement kiln shall submit verbal notification to the executive director of the date of any continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) performance evaluation conducted under §117.3140 or §117.3142 of this title (relating to Continuous Demonstration of Compliance; and Emission Testing and Monitoring for Eight-Hour Attainment Demonstration) at least 15 days before such date followed by written notification within 15 days after testing is completed.

(b) Reporting of test results. The owner or operator of each portland cement kiln shall furnish the executive director and any local air pollution control agency having jurisdiction a copy of any CEMS or PEMS relative accuracy test audit conducted under §117.3140 or §117.3142 of this title:

(1) within 60 days after completion of such testing or evaluation; and

(2) not later than the appropriate compliance date in §117.9320 of this title (relating to Compliance Schedule for Cement Kilns).

(c) Recordkeeping. The owner or operator of a portland cement kiln subject to the requirements of this division (relating to Cement Kilns) shall maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction. The records must include:

(1) for each kiln subject to §117.3110 or 117.3120 of this title (relating to Emission Specifications; and Source Cap), monitoring records of:

(A) daily and rolling 30-day average (and, for each kiln subject to the source cap in §117.3120 of this title, rolling 90-day average) nitrogen oxides (NO _X ) emissions (in pounds);

(B) daily and rolling 30-day average (and, for each kiln subject to the source cap in §117.3120 of this title, rolling 90-day average) production of clinker (in United States short tons); and

(C) average NO _X emission rate (in pounds per ton (lb/ton) of clinker produced) on the basis of a rolling 30-day average (and, for each kiln subject to the source cap in §117.3120 of this title, a rolling 90-day average);

(2) records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS and PEMS;

(3) records of the results of any stack testing conducted; and

(4) for each kiln subject to the source cap in §117.3123 of this title (relating to Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements) and emission testing and monitoring requirements in §117.3142 of this title:

(A) records of the control plan required under §117.3123 of this title;

(B) hourly records of the average NO _X concentration in parts per million by volume;

(D) daily records of the NO _X emissions in tons per day;

(E) daily records of the NO _X emissions in tons per day expressed as a 30-day rolling average;

(F) hourly records of the average exhaust gas flow rate in dry standard cubic feet per minute; and

(G) records of ammonia monitoring required under §117.3142(a)(3) of this title.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702061

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. WATER HEATERS, SMALL BOILERS, AND PROCESS HEATERS

30 TAC §§117.3200, 117.3201, 117.3203, 117.3205, 117.3210, 117.3215

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, that authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. The new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et. seq., that require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state. In addition, the new sections are adopted to implement the legislative mandate under House Bill (HB) 965, 79th Legislature, 2005, which adds Texas Health and Safety Code, §382.0275, concerning Commission Action Relating to Residential Water Heaters, which requires certain actions of the commission regarding residential water heaters.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.016, 382.017, and 382.0275.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702062

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

4. EAST TEXAS COMBUSTION

30 TAC §§117.3300, 117.3303, 117.3310, 117.3325, 117.3330, 117.3335, 117.3345

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.3300.Applicability.

This division (relating to East Texas Combustion) applies to stationary, gas-fired reciprocating internal combustion engines at any stationary source of nitrogen oxides in the following affected counties: Anderson, Brazos, Burleson, Camp, Cass, Cherokee, Franklin, Freestone, Gregg, Grimes, Harrison, Henderson, Hill, Hopkins, Hunt, Lee, Leon, Limestone, Madison, Marion, Morris, Nacogdoches, Navarro, Panola, Rains, Robertson, Rusk, Shelby, Smith, Titus, Upshur, Van Zandt, and Wood Counties.

§117.3303.Exemptions.

The following stationary engines are exempt from this division (relating to East Texas Combustion), except as specified in §117.3345(b) of this title (relating to Recordkeeping and Reporting Requirements):

(1) engines with a maximum rated horsepower (hp) capacity of less than 240 hp;

(2) engines used in research and testing;

(3) engines used for purposes of performance verification and testing;

(4) engines used solely to power other engines or gas turbines during startups;

(5) engines operated exclusively in emergency situations, except that operation for testing or maintenance purposes is allowed for up to 100 hours per year, based on a rolling 12-month average;

(6) engines used in response to and during the existence of any officially declared disaster or state of emergency;

(7) engines used directly and exclusively by the owner or operator for agricultural operations necessary for the growing of crops or raising of fowl or animals;

(8) diesel engines;

(9) dual-fuel engines; and

(10) gas-fired lean-burn engines.

§117.3310.Emission Specifications for Eight-Hour Attainment Demonstration.

(a) The owner or operator of any stationary, gas-fired reciprocating internal combustion engine subject to this division (relating to East Texas Combustion) shall not allow the discharge into the atmosphere emissions of nitrogen oxides (NO _X ) in excess of the following emission specifications:

(1) gas-fired rich-burn engines with a maximum rated capacity less than 500 horsepower (hp), 1.00 grams per horsepower-hour (g/hp-hr); and

(2) gas-fired rich-burn engines with a maximum rated capacity equal to or greater than 500 hp:

(A) fired on landfill gas, 0.60 g/hp-hr; and

(B) all other rich-burn engines, 0.50 g/hp-hr.

(b) The averaging time for determining compliance with the emission specifications in subsection (a) of this section must be a block one-hour average, in the units of the applicable standard.

(c) The maximum rated capacity used to determine the applicability of the emission specifications of subsection (a) of this section or the exemption status of an engine under §117.3303(1) of this title (relating to Exemptions) must be the greater of the following:

(1) the maximum rated capacity as of December 31, 2000; or

(2) the maximum rated capacity after December 31, 2000.

(d) An engine's classification is determined by the most specific classification applicable to the unit as of December 31, 2000. For example, an engine that is classified as a stationary gas-fired engine as of December 31, 2000, but subsequently is authorized to operate as a dual-fuel engine, must be classified as a stationary gas-fired engine for the purposes of this chapter.

(e) The owner or operator of any engine subject to the NO_X emission specifications of subsection (a) of this section that injects urea or ammonia into the exhaust stream for NO _X control, shall not allow the discharge into the atmosphere ammonia emissions in excess of 10 parts per million by volume at 3.0% O ₂ , dry, except as provided in §117.3325 of this title (relating to Alternative Case Specific Specifications), based on:

(1) a block one-hour averaging period for units not equipped with a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS) for ammonia; or

(2) a rolling 24-hour averaging period for units equipped with CEMS or PEMS for ammonia.

(f) An owner or operator may use emission reduction credits as specified in §117.9800 of this title (relating to Use of Emission Credits for Compliance) to comply with the NO _X emission specifications of this section.

§117.3325.Alternative Case Specific Specifications.

(a) Where a person can demonstrate that an affected engine cannot attain the ammonia specification of §117.3310(e) of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration), the executive director may approve emission specifications different from the ammonia specification in §117.3310(e) of this title for that engine. The executive director:

(1) shall consider on a case-by-case basis the technological and economic circumstances of the individual engine;

(2) shall determine that such specifications are the result of the lowest emission limitation the engine is capable of meeting after the application of controls to meet the nitrogen oxides emission specifications of §117.3310 of this title; and

(3) in determining whether to approve alternative emission specifications, may take into consideration the ability of the plant where the engine is located to meet emission specifications through system-wide averaging at maximum capacity.

§117.3330.Operating Requirements.

(a) The owner or operator shall operate any stationary, reciprocating combustion engine subject to §117.3310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) in compliance with the emission specifications of §117.3310 of this title.

(b) Each stationary, reciprocating combustion engine subject to §117.3310 of this title must be operated so as to minimize nitrogen oxides (NO _X ) emissions, consistent with the emission control techniques selected, over the engine's operating or load range during normal operations. Such operational requirements include the following.

(1) Each engine controlled with post-combustion control techniques must be operated such that the reducing agent injection rate is maintained to limit NO _X concentrations to less than or equal to the NO _X concentrations achieved at maximum rated capacity.

(2) Each engine controlled with nonselective catalytic reduction must be equipped with an automatic air-fuel ratio (AFR) controller that operates on exhaust oxygen or carbon monoxide (CO) control basis and maintains the AFR in the range required to meet the engine's applicable emission specifications.

(3) Each engine must be checked for proper operation by recorded NO _X measurements according to §117.8140(b) of this title (relating to Emission Monitoring for Engines). The owner or operator of an engine subject to this paragraph is not required to perform the CO measurements under §117.8140(b) of this title. Engines equipped with a continuous emissions monitoring system or a predictive emissions monitoring system to monitor NO _X are exempt from the requirements of this paragraph.

§117.3335.Monitoring, Notification, and Testing Requirements.

(a) Oxygen (O ₂ ) monitors. If the owner or operator installs a continuous emissions monitoring system (CEMS) to monitor O ₂ , the CEMS must meet the requirements of §117.8100(a) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources).

(b) Nitrogen oxides (NO _X ) monitors. If the owner or operator installs a CEMS or predictive emissions monitoring system (PEMS) to monitor NO _X , the CEMS or PEMS must meet the requirements of §117.8100(a) or (b) of this title, as applicable.

(c) Monitor installation schedule. If the owner or operator elects to installs CEMS or PEMS to monitor NO _X or O ₂ as provided in subsections (a) and (b) of this section, installation and certification of monitoring systems must be performed in accordance with the schedule specified in §117.9340 of this title (relating to Compliance Schedule for East Texas Combustion).

(d) Testing requirements. The owner or operator of any stationary, reciprocating combustion engine subject to §117.3310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) shall comply with the following testing requirements.

(1) Each engine must be tested for NO _X and O ₂ emissions.

(2) Each engine that injects urea or ammonia into the exhaust stream for NO _X control must be tested for ammonia emissions.

(3) For engines not equipped with CEMS or PEMS, all testing must be conducted according to §117.8000 of this title (relating to Stack Testing Requirements). In lieu of the test methods specified in §117.8000 of this title, the owner or operator may use American Society for Testing and Materials (ASTM) D6522-00 to perform the NO _X and O ₂ testing required by this subsection on natural gas-fired reciprocating internal combustion engines. If the owner or operator elects to use ASTM D6522-00 for the testing requirements, the report must contain the information specified in §117.8010 of this title (relating to Compliance Stack Test Reports).

(4) Test results must be reported in the units of the applicable emission specifications and averaging periods.

(5) For engines equipped with CEMS or PEMS, the CEMS or PEMS must be installed and operational before conducting testing under this subsection. Verification of operational status must, at a minimum, include completion of the initial monitor certification and the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device.

(6) For engines operating with CEMS or PEMS, initial compliance with the emission specifications of §117.3310 of this title may be demonstrated by using the CEMS or PEMS, after monitor certification testing, in lieu of the methods specified in §117.3335(d)(3) of this title (relating to Monitoring, Notification, and Testing Requirements).

(7) For engines not operating with CEMS or PEMS, periodic testing for NO _X emissions must be conducted according to §117.8140(a) of this title (relating to Emission Monitoring for Engines).

(A) Retesting as specified in paragraphs (1) - (4) of this subsection is required within 60 days after any modification that could reasonably be expected to increase the NO _X emission rate.

(B) Retesting as specified in paragraphs (1) - (4) of this subsection may be conducted at the discretion of the owner or operator after any modification that could reasonably be expected to decrease the NO_X emission rate, including, but not limited to, installation of post-combustion controls or low-NO _X burners, low excess air operation, staged combustion (for example, overfire air), flue gas recirculation, and fuel-lean and conventional (fuel-rich) reburn.

(8) Testing must be performed in accordance with the schedule specified in §117.9340 of this title.

(e) Ammonia monitoring. Each stationary, reciprocating combustion engine that injects urea or ammonia into the exhaust stream for NO _X control must be monitored according to one of the ammonia monitoring procedures specified in §117.8130 of this title (relating to Ammonia Monitoring).

(f) Notification. The owner or operator of an affected stationary, reciprocating combustion engine must submit written notification of any CEMS or PEMS relative accuracy test audit (RATA) or testing required under this section, except for testing related to ammonia monitoring specified in subsection (e) of this section, to the appropriate regional office and any local air pollution control agency having jurisdiction at least 15 days in advance of the date of RATA or testing.

§117.3345.Recordkeeping and Reporting Requirements.

(a) Recordkeeping. The owner or operator of a stationary, reciprocating combustion engine subject to §117.3310 of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) shall maintain written or electronic records of the data specified in this subsection. Such records must be kept for a period of at least five years and must be made available upon request by authorized representatives of the executive director, the United States Environmental Protection Agency, or local air pollution control agencies having jurisdiction. The records must include:

(1) for each engine using a continuous emissions monitoring system (CEMS) or predictive emissions monitoring systems (PEMS) in accordance with §117.3335(a) or (b) of this title (relating to Monitoring, Notification, and Testing Requirements), monitoring records of hourly emissions for engines complying with an emission specification enforced on a block one-hour average;

(2) for each engine subject to §117.3310 of this title, records of:

(A) emissions measurements required by §117.3330(b)(3) of this title (relating to Operating Requirements); and

(B) catalytic converter, air-fuel ratio controller, or other emissions-related control system maintenance, including the date and nature of corrective actions taken;

(3) records of the results of initial certification testing, evaluations, calibrations, checks, adjustments, and maintenance of CEMS, PEMS, or steam-to-fuel or water-to-fuel ratio monitoring systems;

(4) records of the results of performance testing, including the testing conducted in accordance with §117.3335(d) of this title; and

(5) records of the ammonia monitoring required by §117.3335(e) of this title, if applicable.

(b) Records for exempt engines. Written records of the number of hours of operation for each day's operation must be made for each engine claimed exempt under §117.3303(5) of this title (relating to Exemptions) or §117.3330(b)(3) of this title. In addition, for each engine claimed exempt under §117.3303(5) of this title, written records must be maintained that document the purpose of the engine operation, and if operation was for an emergency situation, identify the type of emergency situation and the start and end times and date(s) of the emergency situation. The records must be maintained for at least five years and must be made available upon request to representatives of the executive director, the United States Environmental Protection Agency, or any local air pollution control agency having jurisdiction.

(c) Reporting. Except for the ammonia monitoring requirements of §117.3335(e) of this title, the owner or operator of an affected stationary, reciprocating combustion engine shall furnish the appropriate regional office and the Office of Compliance and Enforcement reports of all testing and monitor certifications required under §117.3335 of this title. Reports must be submitted for review and approval within 60 days after completion of the testing and must contain the information specified in §117.8010 of this title (relating to Compliance Stack Test Reports). Testing conducted under §117.3330(b)(3) of this title is not subject to the reporting requirements of this subsection.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702063

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter F. ACID MANUFACTURING

1. ADIPIC ACID MANUFACTURING

30 TAC §§117.4000, 117.4005, 117.4025, 117.4035, 117.4040, 117.4045, 117.4050

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702064

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. NITRIC ACID MANUFACTURING--OZONE NONATTAINMENT AREAS

30 TAC §§117.4100, 117.4105, 117.4125, 117.4135, 117.4140, 117.4145, 117.4150

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702065

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

3. NITRIC ACID MANUFACTURING--GENERAL

30 TAC §§117.4200, 117.4205, 117.4210

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702066

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter G. GENERAL MONITORING AND TESTING REQUIREMENTS

Division 1. COMPLIANCE STACK TESTING AND REPORT REQUIREMENTS

30 TAC §117.8000, §117.8010

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702067

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

2. EMISSION MONITORING

30 TAC §§117.8100, 117.8110, 117.8120, 117.8130, 117.8140

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702068

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Subchapter H. ADMINISTRATIVE PROVISIONS

Division 1. COMPLIANCE SCHEDULES

30 TAC §§117.9000, 117.9010, 117.9020, 117.9030, 117.9100, 117.9110, 117.9120, 117.9130, 117.9200, 117.9210, 117.9300, 117.9320, 117.9340, 117.9500

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

§117.9030.Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources.

(a) Increment of progress emission specifications. The owner or operator of any stationary, reciprocating internal combustion engine subject to §117.410(a) of this title (relating to Emission Specifications for Eight-Hour Attainment Demonstration) shall comply with the requirements of §117.410(a) of this title as soon as practicable, but no later than June 15, 2007 (the final compliance date). The owner or operator shall:

(1) install all nitrogen oxides (NO _X ) abatement equipment and implement all NO _X control techniques no later than June 15, 2007; and

(2) submit to the executive director:

(A) for units operating without a continuous emissions monitoring system (CEMS) or predictive emissions monitoring system (PEMS), the results of applicable tests for initial demonstration of compliance as specified in §117.435 of this title (relating to Initial Demonstration of Compliance) as early as practicable, but in no case later than June 15, 2007;

(B) for units operating with a CEMS or PEMS in accordance with §117.440 of this title (relating to Continuous Demonstration of Compliance), the results of:

(i) the applicable CEMS or PEMS performance evaluation and quality assurance procedures as specified in §117.8100(a)(1)(A) and (B) and (b)(2) - (4)(A) of this title (relating to Emission Monitoring System Requirements for Industrial, Commercial, and Institutional Sources);

(ii) the applicable tests for the initial demonstration of compliance as specified in §117.435 of this title; and

(iii) no later than:

(I) June 15, 2007, for units complying with the NO _X emission limit on an hourly average; and

(II) June 15, 2007, for units complying with the NO _X emission limit on a rolling 30-day average;

(C) a final control plan for compliance in accordance with §117.454 of this title (relating to Final Control Plan Procedures for Attainment Demonstration Emission Specifications), no later than January 1, 2008; and

(D) the first semiannual report required by §117.445(d) or (e) of this title (relating to Notification, Recordkeeping, and Reporting Requirements), covering the period June 15, 2007, through December 31, 2007, no later than January 31, 2008.

(b) Eight-hour ozone attainment demonstration emission specifications.

(1) The owner or operator of any stationary source of NO_X in the Dallas-Fort Worth eight-hour ozone nonattainment area that is a major source of NO _X and is subject to §117.410(b) of this title shall comply with the requirements of Subchapter B, Division 4 of this chapter (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Major Sources) as follows:

(A) submit the initial control plan required by §117.450 of this title (relating to Initial Control Plan Procedures) no later than June 1, 2008; and

(B) for units subject to the emission specifications of §117.410(b) of this title, comply with all other requirements of Subchapter B, Division 4 of this chapter as soon as practicable, but no later than:

(i) March 1, 2009, for units subject to §117.410(b)(1), (2), (4), (5), (6), (7)(A), (8), (10), and (14) of this title;

(ii) March 1, 2010, for units subject to §117.410(b)(3), (7)(B), (9), (11), (12), and (13) of this title;

(C) for diesel and dual-fuel engines, comply with the restriction on hours of operation for maintenance or testing in §117.410(g) of this title, and associated recordkeeping in §117.445(f)(9) of this title, as soon as practicable, but no later than March 1, 2009; and

(D) for any stationary gas turbine or stationary internal combustion engine claimed exempt using the exemption of §117.403(a)(7)(D), (8), or (9) of this title (relating to Exemptions), comply with the run time meter requirements of §117.440(i) of this title, and recordkeeping requirements of §117.445(f)(4) of this title, as soon as practicable, but no later than March 1, 2009.

(2) The owner or operator of any stationary source of NO_X that becomes subject to the requirements of Subchapter B, Division 4 of this chapter on or after the applicable compliance date specified in paragraph (1) of this subsection, shall comply with the requirements of Subchapter B, Division 4 of this chapter as soon as practicable, but no later than 60 days after becoming subject.

§117.9210.Compliance Schedule for Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources.

(a) The owner or operator of any stationary source of nitrogen oxides (NO _X ) in the Dallas-Fort Worth eight-hour ozone nonattainment area that is not a major source of NO _X and is subject to the requirements of Subchapter D, Division 2 of this chapter (relating to Dallas-Fort Worth Eight-Hour Ozone Nonattainment Area Minor Sources) shall comply with the requirements of Subchapter D, Division 2 of this chapter as soon as practicable, but no later than:

(1) March 1, 2009, for rich-burn stationary gas-fired reciprocating internal combustion engines;

(2) March 1, 2010, for lean-burn stationary gas-fired reciprocating internal combustion engines; and

(3) March 1, 2009, for diesel-fired and dual-fuel stationary, reciprocating internal combustion engines.

(b) The owner or operator of any stationary source of NO_X that becomes subject to the requirements of Subchapter D, Division 2 of this chapter on or after the applicable compliance date specified in subsection (a) of this section shall comply with the requirements of Subchapter D, Division 2 of this chapter as soon as practicable, but no later than 60 days after becoming subject.

§117.9320.Compliance Schedule for Cement Kilns.

(a) Except as specified in subsection (c) of this section, the owner or operator of each portland cement kiln placed into service before December 31, 1999, in Bexar, Comal, Ellis, Hays, and McLennan Counties shall be in compliance with the requirements of Subchapter E, Division 2 of this chapter (relating to Cement Kilns) as soon as practicable, but no later than the following dates:

(1) May 1, 2003, for cement kilns in Ellis County; and

(2) May 1, 2005, for cement kilns in Bexar, Comal, Hays, and McLennan Counties.

(b) Notwithstanding subsection (a)(1) of this section, for a cement kiln in Ellis County that the owner or operator has filed an application for modification of its facility to meet the requirements of Subchapter E, Division 2 of this chapter on or before May 30, 2003, the compliance schedule is extended until six months after the issuance of the permit for operation of a low-NO _X burner and 12 months after issuance of the permit for operation of a secondary combustion system. Such application(s) must relate only to those modifications required to comply with Subchapter E, Division 2 of this chapter, and any issues incident thereto.

(c) The owner or operator of each portland cement kiln in Ellis County shall comply with the requirements of §117.3123 and §117.3142 of this title (relating to Dallas-Fort Worth Eight-Hour Ozone Attainment Demonstration Control Requirements; and Emission Testing and Monitoring for Eight-Hour Attainment Demonstration), and the applicable requirements of §117.3145 of this title (relating to Notification, Recordkeeping, and Reporting Requirements) that are associated with §117.3123 and §117.3142 of this title, as soon as practicable, but no later than March 1, 2009.

(1) The provisions regarding extension of compliance schedules in subsection (b) of this section do not apply to this subsection or the requirements of §117.3123, §117.3142, or the applicable requirements of §117.3145 of this title.

(2) If a contested case hearing is granted as a direct result of a permit application necessary to comply with the requirements of §117.3123 of this title, the compliance date of this subsection for the site affected by the contested case hearing is extended until no later than March 1, 2010. The compliance date for the affected site remains March 1, 2009, if:

(A) a contested case hearing is granted as a result of a permit application that includes modifications necessary to comply with §117.3123 of this title, but the contested case hearing is the result of modifications included in the permit that are unrelated to compliance with §117.3123 of this title, then the compliance date for the affected site remains March 1, 2009; or

(B) a contested case hearing is granted at the request of the owner or operator of the affected portland cement kiln or any third party affiliated with the owner or operator.

§117.9340.Compliance Schedule for East Texas Combustion.

(a) The owner or operator of each stationary, reciprocating internal combustion engine subject to the requirements of Subchapter E, Division 4 of this chapter (relating to East Texas Combustion) shall comply with the requirements of Subchapter E, Division 4 of this chapter as soon as practicable, but no later than March 1, 2010.

(b) The owner or operator of a stationary, reciprocating internal combustion engine that becomes subject to the requirements of Subchapter E, Division 4 of this chapter on or after March 1, 2010, shall comply with the requirements of Subchapter E, Division 4 of this chapter as soon as practicable, but no later than 60 days after becoming subject.

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702069

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087

Division 2. COMPLIANCE FLEXIBILITY

30 TAC §117.9800, §117.9810

STATUTORY AUTHORITY

The new sections are adopted under Texas Water Code, §5.102, concerning General Powers, §5.103, concerning Rules, and §5.105, concerning General Policy, which authorize the commission to adopt rules necessary to carry out its powers and duties under the Texas Water Code. In addition, the sections are adopted under Texas Health and Safety Code, §382.002, concerning Policy and Purpose, which states the policy and purpose of the State of Texas and the Texas Clean Air Act; §382.011, concerning General Powers and Duties, which provides the commission with the authority to establish the level of quality to be maintained in the state's air and the authority to control the quality of the state's air; §382.012, concerning State Air Control Plan, which requires the commission to develop plans for protection of the state's air; §382.014, concerning Emission Inventory, which authorizes the commission to require submission information relating to emissions of air contaminants; §382.016, concerning Monitoring Requirements; Examination of Records, which authorizes the commission to prescribe requirements for owners or operators of sources to make and maintain records of emissions measurements; §382.017, concerning Rules, which provides the commission the authority to adopt rules consistent with the policy and purposes of the Texas Clean Air Act; §382.021, concerning Sampling Methods and Procedures, which authorizes the commission to prescribe the sampling methods and procedures; and §382.051(d), concerning Permitting Authority of Commission Rules, which authorizes the commission to adopt rules as necessary to comply with changes in federal law or regulations applicable to permits under Chapter 382. In addition, the new sections are adopted under federal mandates contained in 42 United States Code, §§7401 et seq., which require states to adopt pollution control measures in order to reach specific air quality standards in particular areas of the state.

The adopted sections implement Texas Health and Safety Code, §§382.002, 382.011, 382.012, 382.014, 382.016, 382.017, 382.021, and 382.051(d).

This agency hereby certifies that the adoption has been reviewed by legal counsel and found to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on May 25, 2007.

TRD-200702070

Robert Martinez

Director, Environmental Law Division

Texas Commission on Environmental Quality

Effective date: June 14, 2007

Proposal publication date: December 29, 2006

For further information, please call: (512) 239-6087