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Comments on the Proposed Revisions to the 1-Hour Ozone State Implementation Plan for

the Houston-Galveston Area

The Business Coalition for Clean Air

September 25, 2000

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TABLE OF CONTENTS

SECTION PAGE

Section 1 - Point Source Control Measures

Section 2 - Texas Clean Fuel Measures

Section 3 - On-Road and Non-Road Measures

Section 4 - Other Control Measures

Section 5 - Federally-Preempted Control Measures

Section 6 - Cap and Trade Program

Section 7 - SIP Implementation Issues

Section 8 - Market-Based Incentives

Section 9 - Mid-Course Evaluation

Section 10 - Cost of Controls and Implementation

Section 11 - Photochemical Modeling Considerations

Section 12 – Administrative Considerations

Section 13 - Index of Comments

Appendix I Houston-Galveston State Implementation Plan Resources Availability Study

Appendix II BCCA Technical Advisory Committee Presentations to TNRCC

Appendix III Impact and Assessment of Proposed Emission Reduction Regulations for the Houston-Galveston Are Stationary IC Engines

Appendix IV The Impact of Ammonia Emission on Particulate Matter Concentrations in HGA Non-Attainment Region

Appendix V The Economic Consequences of Rigid Clean Fuel Regulations in Texas

Appendix VI The California Conundrum: Causes of Gasoline Price Volatility

Appendix VII U.S. Petroleum Refining- Assuring the Adequacy and Affordability of Cleaner Fuels

Appendix VIII An Assessment of the Potential Impacts of Proposed Environmental Regulations on the U.S. Refinery Supply of Diesel

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Section 1: Proposed Point Source Controls

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1.0 Proposed Point Source Controls

1.1 Introduction

In order to achieve the targeted 90% reduction in NOx emissions from all point source categories, the TNRCC has proposed very stringent emission limitations. Most of the emission limitations have been developed with a less that complete analysis of the technical or economic feasibility of the resulting controls, or an analysis of the possible environmental or economic dis-benefit of the proposed controls.1 In fact, the TNRCC appears to have first established an arbitrary NOx reduction target for point sources (i.e., 90%) and, through an iterative process, back calculated emission rate limitations necessary to achieve the desired target. This is an arbitrary approach to establishing air pollution standards, and circumvents the intent established in the Texas Clean Air Act to establish standard based on a technological and economical review of available control measures.

Below is a more specific discussion of the source-specific control measures TNRCC has proposed and some of the technical and economic issues that must be considered and addressed as part of the SIP development process.

1.2 Overview of Proposed Point Source Control Measures

The TNRCC has outlined a number of emission control measures that aim to achieve the necessary reductions in NOx emissions to demonstrate ozone attainment via photochemical modeling. These measures incorporate NOx emission controls on all source categories including stationary point sources, on-road sources, and off-road sources. In order to achieve the targeted reduction in NOx emissions from all source categories, the TNRCC has made very stringent, and in some cases, technologically and economically infeasible, emissions control assumptions. These stringent assumptions are due, in part, to failure of the photochemical modeling to accurately replicate the HGA air shed in controlling regions of the domain, the failure of EPA to implement timely controls on federally preempted sources, and the regional emission inventory.

The NOx SIP point source proposed rule package preamble shows an absence of valid, current and adequate scientific and technical support for the proposed NOx reduction targets and implementation timing. There is no discussion indicating the use of actual industry or vendor retrofit experience which would otherwise precede a determination that the proposed NOx reduction target is broadly achievable for all point sources categories. There is no discussion or consideration of design and implementation timing issues, which will impact the technological and economic feasibility of the required technology applications.

1 All underlined comments within the text require a response and can be found indexed in Section 12—Index of Comments

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Below is a list of critical issues that must be addressed prior to final rulemaking to ensure that a technologically and economically feasible SIP is adopted by TNRCC.

In developing an ozone attainment SIP that includes a 90 percent reduction in NOx emissions by stationary sources, technological capability is a key consideration. Although technology has advanced in recent years, there is no one demonstrated, commercialized, retrofit technology application today to achieve the 90 percent NOx reduction target for the point source category. There are other steps that must be taken to achieve the 90% reduction target such as wholesale replacement of sources, consolidation of sources to reduce fuel firing, and shutdown of marginally economic equipment and plants. However, the Coalition does not believe such steps are technologically or economically based emission control standards, nor has the TNRCC considered the cost and regional economic impacts associated with such steps.

Both combustion control improvements and post combustion retrofit controls have technological limitations that reduce their potential effectiveness in achieving the desired emission reduction targets. Retrofit combustion controls (e.g., low NOx burners) will result in a decrease in combustion unit capacity (i.e., de-rate) in up to 15% of the technology applications. Post combustion NOx reduction retrofit controls (e.g., selective catalytic reduction) have not been demonstrated to achieve the desired low level of NOx emission envisioned by the TNRCC proposal and also has limitations which will cause a decrease in operational reliability and loss of production capacity in many applications. TNRCC has not considered or quantified the economic consequences, such as loss of fuel and petrochemical production capacity, as a result these technological limitations.

For all of the HGA point source categories, there is no experience with retrofit NOx control technology applications that have been demonstrated to perform at the levels proposed by the TNRCC. Time for technology development, testing, and prototyping before commercialization will be required to overcome the many technical limitations that are now being identified as the result of detailed engineering and design reviews. TNRCC has not allowed for sufficient time for the necessary technology developments with the proposed year-end 2004 implementation deadline.

A 90 percent NOx reduction target effectively eliminates the ability to create surplus point source emission reduction credits under the proposed Cap-and-Trade program to permit future business expansion in the region. The proposed level of control provides little or no opportunity for future growth of stationary sources in the eight-county non-attainment area. Such a "no future growth" plan will eventually put businesses in this region at an economic and competitive disadvantage in the global marketplace and make them non-competitive for further investment and expansion. TNRCC has not considered the regional economic consequences of this "no future growth" plan.

The proposed year-end 2004 implementation timing does not recognize the magnitude of

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manpower and material resources required to implement the proposed rule, and does not allow for the practical implementation of controls. In short, a year-end 2004 implementation deadline is not physically possible. The proposed implementation timing is too short and will cause significant manpower, material, and equipment shortages nationwide, will result in supply disruptions of fuels, petrochemical products and intermediates, and will unnecessarily increase the cost of products for consumers. TNRCC has not considered the cost and economic consequences associated with the year-end 2004 implementation deadline.

The 90% NOx reduction targeted for HGA point sources, as applied from a Texas NOx RACT I baseline, exceeds the most stringent NOx retrofit standards applied anywhere in the world. The proposed Chapter 117 NOx standards are technologically infeasible and have no proven performance experience upon which to base a reasonable and technically viable regulatory program. (See Table 1)

Table 1

Comparison of Selected Houston/Galveston Area, California SCAQMD,and Proposed TNRCC NOx Control Emission Limits

Source Category

CurrentLimits

CaliforniaLimits

TNRCCProposed

LimitsGas Utility Boilers, lb/MMBtu

0.26 0.02 0.01

Gas Industrial Boilers, lb/MMBtu

0.26 0.03 0.01

Gas Industrial Heaters, lb/MMBtu

0.12 0.03 0.01

Gas Turbines, ppm NOx

42 9 - 15 4

IC Engines, g/hp-hr N/A 2.0 Electrify - 0.5

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Some key points follow from reviewing this comparison of TNRCC proposed limits to demonstrated Southern California experience with NOx retrofit standards: TNRCC's proposed emission limits will be unachievable by combustion retrofits for many sources and will require extensive implementation of SCR on an unprecedented and untested scale. California standards have been largely achievable by combustion modifications and a few

SCR retrofit applications on carefully selected and designed optimized units. Most South Coast Air Quality Management District (SCAQMD) point sources have been able to meet the retrofit standards through extensive use of combustion controls and the selective retrofitting of SCR to less than 20 % of their large combustion sources.

A review of worldwide retrofit experience found no equipment designed for and meeting emission standards as stringent as the TNRCC's proposed rule. Source categories surveyed include gas turbines, industrial boilers, industrial process heaters and furnaces (general application and steam cracking furnaces), Internal Combustion (IC) engines and Fluidized Catalytic Cracking (FCC) units. California rules in general, and SCAQMD rules in particular, contain the world's most stringent retrofit NOx standards (currently 2-3 times less stringent than the proposed NOx SIP standards). Other countries such as Germany and Japan have been surveyed and found to have emission limits for point source NOx retrofit applications significantly higher than limits proposed by the TNRCC.

The EPA, in developing Maximum Achievable Control Technology (MACT) standards for air toxic emissions, was required to establish a level of emissions control equivalent to the average of the best performing 12% of existing sources. In a comprehensive review of combustion sources in the United States, less than two dozen SCR retrofit applications were identified compared to the almost 1,800 potential applications expected under the TNRCC proposed SIP rules alone. This very limited retrofit experience would not even qualify SCR as a MACT standard for air toxics and is therefore not sufficiently broad for industry to apply and extend confidently across all the regulated sources in the HGA under Reasonably Available Control Technology (RACT) standards.

Table 2 illustrates the worldwide experience with SCR retrofit applications found after extensive review with SCR catalyst and system providers, engineering companies that install SCR applications, original equipment providers, and worldwide experience of BCCA member companies. Based on this worldwide experience with SCR applications, BCCA member companies are very concerned about the supply and availability of system providers and engineering companies to provide the necessary human and material resources to retrofit almost 2000 individual combustion sources in the HGA.

Table 2

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Worldwide Experience with Post-Combustion Retrofit Technology

Source Category # of Units inH/G Area

WorldwideRetrofits

Utility Boilers 32 ?

Industrial Boilers 319 7

Industrial Heaters 641 21

Gas Turbines 185 182

IC Engines 461 ?

Miscellaneous 41 9

Total 1779 55

Two key points follow from Table 2: (1) there are few contractors with SCR retrofit experience available for industry to work with and learn from and, (2) there are very few actual retrofit experiences available from which to establish design and operating confidence.

1.3 On-Going Efforts to Define Technical and Economic Feasibility

BCCA and its member companies are sponsoring a number of technical and economic feasibility studies to help identify steps to achieve the region's air quality goals while maintaining a sound regional economy.

1.3.1 Resource Supply and Demand

Facts establishing that the proposed SIP implementation deadline of year-end 2004 as infeasible are presented in the attached NOx Implementation Resources Study completed by Fluor Daniel3 for the BCCA. (See Appendix I) Engineering, materials, & labor availability, as well as implementation timing issues were examined. Labor resources (engineering and construction) & materials (such as burners, SCR catalyst, NOx analyzers, electric motors, etc.) were included. Projected demand for manpower and material resources was compared to estimates of available supply with the following conclusions:2 The smallest gas turbine retrofit was a 4 megawatt gas turbine.3 Houston-Galveston Area State Implementation Plan Resource Availability Study, Fluor Daniel Company, August 2000.

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Demand for construction labor between 2002-2004 will consume 175% the available supply in the entire upper Gulf Coast (HGA to Baton Rouge, LA) area as forecasted by the 2000 Houston Business Roundtable - Gulf Coast Workforce Projection Survey.

Demand for front-end design engineering human resources between 2002-2004 will consume 145% of the available nationwide supply as forecasted by the 1999 Joint Industry Program Engineering, Procurement and Construction Survey.

Demand for detailed engineering design resources between 2002-2004 will consume 128% of the available nationwide supply as forecasted by the 1999 Joint Industry Program Engineering, Procurement and Construction Survey .

Highly specialized labor resources, such as furnace engineering evaluation specialists and flue-gas computational fluid dynamics modelers are expected to be in short in supply and a critical path limitation to timely completion of engineering design activities.

Demand for burner testing facilities to demonstrate, certify, and guarantee NOx emission performance of new burners will exceed current worldwide burner testing capability by 200%. This will be another critical path limitation to timely delivery of new burners to meet a year-end 2004 implementation deadline.

Demand for SCR catalyst for the Houston-Galveston area and the 22 State OTAG NOx SIP Call between 2002-2004 exceed available worldwide production capability by 500%.

1.3.2 Ethylene and Polyethylene Production Capability

A second study specifically examined the impact of the year-end 2004 implementation deadline on the ability of the Ethylene and Polyethylene industries to meet product demand during the SIP implementation period. This study was conducted for the BCCA by Pace Consultants of Houston and will be publicly available within the next few weeks.

A SIP implementation deadline of 2004 will effectively decrease the Ethylene industry capacity by 2.8% and cost the Houston-Galveston area ethylene plant operators $330 million dollars in lost sales during the implementation period of 2003-2004 when construction would take place. This is one example of the economic costs not considered by the TNRCC in understanding the economic impact of the point source rule. This product loss will add $1.65 million dollars, on average, to the cost of each Ethylene Plant furnace SCR retrofit. This would result in a more than doubling of the average cost TNRCC estimated for a furnace SCR retrofit ($1.4 million -25 Texas Register 8291).

1.3.3 Refinery Fuels Production Capability

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A third study is being commissioned to examine the impact of the year-end 2004 implementation deadline on the ability of refiners in Texas to meet fuel product demand during the proposed SIP implementation period. This study is being performed by Pace Consultants of Houston and will be available in late November.

1.3.4 Worldwide Technology Review and Assessment

A retrofit application experience review undertaken by the BCCA Technical Workgroups and presented to the TNRCC July 12, 2000, July 25, 2000, and August 15, 2000 (See Appendix II)4 highlights many of the technical issues leading to a conclusion of technical infeasibility. The BCCA will continue to review and report on technology development and application over the SIP implementation period.

1.3.5 HGA Regional Economic Study

A regional economic study commissioned by BCCA with RCF Consulting (University of Chicago) and Dr. Baton Smith (University of Houston) to assess the economic benefits and disbenefits in the Houston-Galveston area associated with the current TNRCC proposed SIP. This study will assess regional and county impacts on jobs, wages, growth, taxes, and other important economic indicators for the HGA. Results from this study will be available in November 2000.

1.4 Options for Reducing NOx

There are three broad options for reducing NOx emissions from point sources. Each option must be screened and evaluated through an intensive in-depth site specific case by case technical and economic analysis. Three key options for NOx controls are available:

(1) Application of Retrofit Control Technology on Existing Equipment(2) Replace or Consolidate Existing Equipment(3) Shutdown of Existing Equipment

There is no evidence in the proposed rule that the TNRCC has weighed and analyzed the costs and technical feasibility of these potential control options that operators will be required to use to reach NOx reduction targets. In fact, the TNRCC has assumed that Option (1) will work in all cases. 1.4.1 Application of Retrofit Control Technology on Existing Equipment

Technologies for reducing NOx emissions are available for a wide range of processes and combustion devices. However, these technologies alone will not produce a 90 percent reduction in NOx emissions. In retrofit applications, there are many engineering and design uncertainties that must be addressed including achieving the desired NOx performance, assuring 4 BCCA Technical Advisory Committee presentations to TNRCC on July 12 and 25, 2000 and August 15, 2000.

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manufacturing capacity is maintained, and assuring that operating productivity and reliability is maintained. Retrofit technologies for reducing NOx emissions include:

Combustion Control Technology

Combustion control technologies includes the application of low NOx burners. The NOx reduction potential and cost effectiveness of combustion control technologies are dependent on a number of factors including, but not limited to:

- Starting NOx emission level [e.g., pounds NOx per million Btu] which is assumed to be TNRCC RACT I levels

- Safe operations conditions such as flame stability- Process temperature requirements such a radiant heat release and total heat input- Physical burner and combustion device geometry and burner size- Fuel type quality and variability [e.g., Btu content, level of hydrogen and olefins ]- Construction issues such as material and equipment availability (e.g., burners, burner testing,

combustion modelers, etc.)

Post Combustion Control Technology Application

Many grassroots commercial applications of SCR technology are designed for and achieve a 90 percent NOx reduction. In retrofit applications, there are many factors that can reduce not only NOx performance, but also process unit capacity, equipment operating productivity and equipment reliability. All of these factors must be considered in the design and engineering of post-combustion retrofit technology applications.

The NOx reduction potential and cost effectiveness of SCR technology applications is dependent on a number of factors including, but not limited to:

- The starting NOx emission level [e.g., pounds NOx per million Btu]- Safe operations conditions [e.g., ammonia storage and handling]- Stack gas temperature, sulfur level, and dust loading, all of which affects

technology selection and performance - Fuel type quality and variability [e.g., presence of catalyst poisons and plugging agents]- Construction issues such as combustion equipment type, physical equipment geometry,

equipment availability and size.- Physical plant plot space limitations

1.4.2 Replace or Consolidate Existing Equipment

There will be many instances where the direct application of retrofit technology will not meet the desired NOx emission targets because of the uncertainties outlined above. In such instances, either the technology simply will not achieve the desired NOx reduction target, or the cost to design around the engineering challenges is prohibitive. In these cases, replacement or

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consolidation of existing equipment must be considered as a means to meet the NOx reduction target. Examples of equipment replacement and consolidation include:

- Replace multiple small, gas-fired process heaters with a steam system or hot oil belt.- Consolidate existing high NOx emission sources, such as a multiple boiler or turbine train,

with a new, state-of-the-art low NOx facility designed to meet the NOx reduction target. - Replacing equipment "in-kind", such as an inefficient gas turbine with a new gas turbine

specifically designed for low NOx emissions performance.- Replacing internal combustion engines with an electric motor driver. - Consolidate steam boilers and/or gas turbines with a single, state-of-the-art gas turbine co-

generation facility.

It should be noted that equipment replacement and consolidation would, in most cases, be more costly than if the NOx retrofit applications discussed in Option (1) had been technologically and/or economically feasible. TNRCC has not included the cost of equipment replacement and consolidation that will be necessary as a result of the infeasible emission limitations proposed in the SIP.

1.4.3 Shutdown Existing Equipment

There will be instances where the direct application of retrofit technology will not meet the desired NOx emission targets and where replacement and consolidation of existing equipment will not be economically feasible. In those instances, the shutdown of equipment must be considered as the last remaining viable measure to meet the NOx reduction target. In some cases, equipment shutdowns might simply mean that overall production capacity is reduced. In other cases, equipment shutdowns will mean that a particular product line is eliminated. In the more extreme case, entire plants will be shutdown if there is no chance to recover the SIP capital investments in the market place. If California is an example, the TNRCC can expect to see capacity reductions, product line shutdowns, and some plant shutdowns as a result of the proposed rule. TNRCC has not considered the economic impacts of the anticipated capacity reductions and shutdowns that are likely to occur over the next 7 years as a result of the infeasible emission limitations proposed in the SIP.

1.5 Developing a Technologically and Economically Feasible SIP

BCCA members have broadly surveyed engineering companies, SCR catalyst companies, engineering companies and implementation services, and other experts to assess the proposed standard and to develop an alternate proposal, which we believe to be technologically and economically feasible in broad application across the HGA.

BCCA proposes that TNRCC establish point source a NOx standard comparable to the

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technology forcing rules being deployed in the SCAQMD.

BCCA proposes that the SIP implementation t iming be more consistent with normal process unit turnaround cycles and the availability of manpower and material resources. This will dramatically improve the cost effectiveness of proposed rule and minimizing the potential for product disruption, supply shortages and consumer price increases.

BCCA proposes that TNRCC consider establishing a partnership with the regulated community to develop technologically feasible standards for point source types which have very few, of any, NOx retrofit applications in the United States. An example of these sources includes ethylene plant pyrolysis furnaces, lean-burn internal combustion engines, hydrogen generation reactor furnaces, BIF and other incinerators, and Fluidized Catalytic Cracking (FCC) units.

1.6 Utility Electric Generation

The Utility Electric Generation Source category includes gas and coal-fired steam generating units (boilers) and gas-fired turbines used for the generation of electricity. In addition, the category includes gas-fired auxiliary boilers to support the start-up of larger boilers. Combustion controls such as flue gas recirculation and low-NOx burners, and post-combustion controls, such as SCR, are technologies available to reduce emissions.

1.6.1 Emission Limitations

TNRCC has proposed emission reduction targets for utility boiler and turbine applications (see Table 3) that are technically infeasible, exceed levels commonly achieved in practice, or are economically infeasible in wide-scale retrofit applications. The proposed emission reduction targets for utility boilers go far beyond current Best Available Control Technology (BACT) and approach or meet the most stringent emission standards under the Clean Air Act envisioned for new sources, Lowest Achievable Emission Rates (LAER). Additionally, the proposed emission standards exceed the emission limitations in place in the California South Coast Air Quality Management District (SCAQMD), among the most stringent in the world.

1.6.2 Utility Boilers

The proposed emission reduction target of 0.01 lb/MMBtu for gas-fired boilers are well below the levels included in SCAQMD Rule 1135 of 0.015-0.02 lb/MMBtu. (See Table 3) Furthermore, the proposed NOx rate is well below the actual NOx emission rates of most large utility gas-fired boilers located in Southern California equipped with SCR systems. Although the proposed rate can be achieved in limited applications, the rate is technically infeasible and economically unreasonable for many gas-fired boilers.

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The proposed SIP emission limitation of 0.03 lb/MMBtu for coal-fired boilers is far below the 0.15lb/MMBtu standard for new coal-fired units adopted by the EPA in September, 1998. In addition, the proposed emission rate is well below the NOx emission rate currently achieved in practice by any coal-fired unit in the world. There is simply no experience at this level, or even approaching this level, to demonstrate that the proposed rate can be achieved or maintained by the affected units in the Houston-Galveston area on a continuous basis.

The proposed emission reduction target of 0.01 lb/MMBtu for auxiliary boilers is technically infeasible and economically unreasonable for this source category. These boilers typically operate for extended periods at minimum loads with infrequent operation at high loads. Consequently, for most of the operating schedule, flue gas temperatures will be well below conventional SCR operating temperature requirements, preventing effective NOx reduction. Furthermore, with typical capacity factors for these units below 10 percent, costs for SCR are not economically reasonable given the limited NOx reduction potential and low service factor.

1.6.3 Gas Turbines

The proposed emission reduction target of 0.015 lb/MMBtu (approximately 4 ppm) for gas turbines is well below the levels included in SCAQMD Rule 1134 of approximately 9-15ppm. This level, which is approaching LAER levels for new installations, cannot be reasonably achieved in retrofit applications where after-market water injection or dry, low-NOx firing systems are not available, where space constraints impact SCR design, or where flue gas temperatures preclude SCR altogether. Furthermore, the retrofit of combustion controls and SCR is not economically reasonable for certain low-capacity factor applications. For this reason, a number of local air districts in Southern California have regulations which allow for lesser NOx control requirements for gas turbines with limited operation TNRCC should consider the approach used in SCAQMD Rule 1134 which recognizes retrofit consideration issues associated with gas turbines of different sizes and applications. For instance, exemptions are provided for low capacity factor turbines, laboratory gas turbine units used in research and testing. Exemptions are also provided for gas turbine units operated exclusively for fire fighting and/or flood control, chemical processing gas turbine units, emergency standby and peaking gas turbine units demonstrated to operate less than 200 hours per calendar year, existing gas turbine units rated below 4 MW and operate less than 877 hours per year, etc. Tiered standards for gas turbines in the SCAQMD are provided in Table 4:

Table 3Utility Electric Generation

Source Category Proposed NOx Reduction

ESAD Rates

Utility Boilers Gas Wall-Fired 95%; 74.3 tpd

93%; 12.5 tpd0.01 lb/MMBtu0.01 lb/MMBtu

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Gas Tangential-Fired Coal Wall-Fired Coal Tangential-Fired Auxiliary Boilers

Total Utility Boilers

92%; 52.4 tpd92%; 44.1 tpd98%; 0.3 tpd

93%; 184 tpd NOx

0.03 lb/MMBtu0.03 lb/MMBtu0.01 lb/MMBtu

Turbines/Duct Burners Electric Generation Peaking/Intermittent Emergency

Total Turbines/Duct Burners

92%; 127.8 tpd 78%; 2.5 tpd 0%; 0 tpd

92%; 130 tpd NOx

0.015 lb/MMBtu0.015 lb/MMBtu

--

Table 4

Example of SCAQMC Tiered Gas Turbine Standards

Turbine Size NOx Standard (ppm)

0.3 to Less Than 2.9 M 25

2.9 to Less Than 10.0 MW 9

2.9 to Less Than 10.0 MW (No SCR) 15

10.0 MW and Over 9

10.0 MW and Over (No SCR) 12

>60 MW Combined Cycle (No SCR) 15

>60 MW and Over Combined Cycle 91.7 Industrial, Commercial, Institutional Combustion (ICI) Sources

This section discusses ICI process heaters & furnaces, boilers, gas turbines with duct burners / heat recovery steam generators (HRSG), internal combustion engines, and other sources such as refinery Cat Crackers.

1.7.1(a) Pre-Combustion Control Technology

Pre-combustion control technologies are applied to stationary combustion sources to prevent NOx formation in the combustion flame. Such controls include the application of Low NOx

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Burners (LNB) in boilers and heaters, Staged Combustion Controls in turbines, and Clean Combustion Controls for Internal Combustion (IC) Engines. Combustion controls prevent NOx formation at the source (within the combustion flame) and do not result in some of the negative environmental impacts associated with post-combustion controls, such as increased ammonia emissions associated with Selective Catalytic Reduction.

With properly designed and operated combustion units and new Ultra-LNB technology, NOx emission reductions in the range of 60-75% are achievable and are relatively cost effective. This level of NOx reduction can correspond to emission rates in the range of 0.04 pound per million Btu (lb/MMBtu) for industrial boilers and heaters, and can be achieved cost effectively provided sufficient lead-time is available. However, such combustion improvements alone not adequate to meet the proposed emission limitations established for most combustion sources in the HGA.

1.7.1(b) Post-Combustion Control Technology

Post-combustion control technologies are applied to stationary combustion sources to capture or remove NOx already formed in the combustion by-product flue-gases. These controls include technologies such as Selective Catalytic Reduction (SCR) that, in the presence of catalyst and a reducing agent such as ammonia, convert NOx to nitrogen and water. The TNRCC has proposed emission control standards so stringent as to require the application of post-combustion control technologies on almost 70% of the 2,650 combustion sources in the region. The remaining sources must be retrofitted with the best Ultra-Low NOx burners on the market today.

Selective catalytic reduction technologies have been successfully designed and applied in many new boiler, heater, and turbine applications, achieving up to a 90% reduction of NOx in the combustion flue-gas. The experience in application of selective catalytic reduction technology in retrofit applications of existing combustion units is very limited, and in come combustion applications has never been attempted. The level of NOx reduction achieved in retrofit applications can vary due to the non-optimum design and operating conditions of the combustion source. Such non-optimum operating conditions can include flue-gas temperature, fuel composition (e.g., sulfur content, ash, etc.) and furnace configuration. EPA places the NOx removal effectiveness of Selective Catalytic Reduction technologies in the range of 75-90%, depending on the application.5 TNRCC has assumed control efficiency in the 85-90% range. If SCR is applied in under less than optimum design and operation conditions, the NOx control efficiency will drop below TNRCC's assumed control efficiency range. TNRCC has not adequately addressed this issue.

Post-combustion control technologies have not been applied successfully in a number of combustion source applications. For example, there have been no successful application of these technologies on load-following, lean-burn internal combustion engines for a number of technical reasons, including difficulty in achieving and maintaining the required temperature window and residence time for the NOx reduction reactions to be effective. Additionally, there has been no

5 Alternative Control Techniques Document (Table 2-2) -- NOx Emission from Process Heaters (EPA-453/R- 93-015, February 1993.

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retrofit application these technologies on ethylene pyrolysis furnaces anywhere in the world. Similarly, two of the five major worldwide providers of gas turbines has never performed a retrofit application of this technology. Finally, there is only one commercial application of this technology in the United States on refinery fluidized catalytic cracking (FCC) unit that has just started up on the West Coast. The application of post-combustion control technology in retrofit applications must be carefully engineered on a cast-by-case bases and, in some cases, non-optimum equipment and operating conditions will limit the overall control device effectiveness. TNRCC failed to take this worldwide lack of experience into account when setting the emission limits in the proposed rule.


TNRCC has proposed emission reduction targets (see Table 4) for certain industrial, commercial, and institutional combustion sources that are not technically achievable or economically feasible in wide-scale retrofit applications. The proposed emission reductions for industrial boilers go well beyond current Best Available Control Technology (BACT) for new sources and approach or meet the most stringent emission standards envisioned under the Clean Air Act for new sources, Lowest Achievable Emission Rates (LAER).

Additionally, in most cases, these proposed emission standards for ICI facilities exceed the emission limitations in place in the California South Coast Air Quality Management District (SCAQMD), the most stringent in the world. (See Table 5)

Table 5Industrial, Commercial, and Institutional Sources

Source Category Proposed NOx Reduction

ESAD Rates

Industrial Boilers Gas-Fired =100 MMBtu Gas-Fired =40<100 MMBtu Gas-Fired <40 MMBtu Oil-Fired Petroleum Coke Fired RCRA BIF Wood-Fired

96%; 53.2 tpd87%; 3.0 tpd62%; 1.0 tpd90%; 0.1 tpd90%; 10.4 tpd

81%; 9.95 tpd90%; 0.9 tpd


2 lb/M gallons0.030 lb/MMBtu0.057 lb/MMBtu0.015 lb/MMBtu0.020 lb/MMBtu

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Rice Hull-Fired Total Industrial Boilers

90%; 0.5 tpd

92%; 79 tpd NOx

0.089 lb/MMBtu

Process Heaters/Furnaces Gas-Fired>=100 MMBtu Gas-Fired>=40<100 MMBtu Gas-Fired <40 MMBtu Oil Fired

Total Heaters/Furnaces

90%; 79.4 tpd86%; 12.8 tpd62%; 4.3 tpd90%; 0.04 tpd

88%; 96.6 tpd


2 lb/MM gal.

Turbines/Duct Burners Compressors <10 MW Compressors >10 MW Total Turbines/Duct Burners

90%; 6.2 tpd93%; 4.6 tpd

91%; 11 tpd NOx

0.015 lb/MMBtu0.015 lb/MMBtu

Internal Combustion Engines Gas-Fired at sites> = 3000 hp Gas-Fired at sites < 3000 hp Total Turbines/Duct Burners

98%; 71.5 tpd92%; 7.0 tpd

97%; 78 tpd NOx

0.17 g/hp-hr0.50 g/hp-hr

Other Sources Refinery Cat Crackers Incinerators = 40 MMBtu/hr Dryers - MgCl2

Pulping Recovery Furnaces Steel Furnaces = 20 Ht Treat Steel Furnaces = 20 Reheat Kilns - Lime Kilns - Lightweight Aggregate

Total Other Sources

90%; 13.4 tpd90%; 3.6 tpd90%; 1.0 tpd64%; 1.1 tpd35%; 0.1 tpd50%; 0.3 tpd64%; 0.2 tpd30%; 0.1 tpd

60%; 19.8 tpd NOx

10 ppmv@0% O2

10% of 1997 Rate10% of 1997 Rate

0.05 lb/MMBtu0.09 lb/MMBtu0.06 lb/MMBtu0.66 lb/ton CaO0.76 lb/ton LWA

1.7.3 ICI Boilers, Heaters and Furnaces

(a) Background

ICI boilers, heaters and furnaces are found in industrial plants, and each heater and furnace has its own unique design and operating conditions that needs to be considered when determining the feasibility and cost of a particular NOx reduction retrofit technology. Boilers, heaters and furnaces in the HGA vary by age, manufacturer and model and the retrofit technology must be developed for each specific application on a case-by-case basis.

There are potentially four types of NOx control technologies for ICI boilers, heaters and furnaces: (1) low NOx burners (LNB), staged fuel and /or staged air; (2) ultra low NOx burners (U-LNB) that incorporate internal or external flue gas recirculation; (3) Selective Catalytic Reduction system; and (4) a combination of SCR with new burner technology.

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Current RACT (November, 1999) for ICI boilers, heaters and furnaces in the HGA ranges from 0.10 – 0.30 lb. NOx per MMBtu fired and the limits are based on fuel type and air preheat or firebox temperature. The proposed ESAD limits are based on fired duty with the breakpoints at greater than 100 MMBtu/hr, 40 MMBtu/hr to 100 MMBtu/ hr and less than 40 MMBtu/hr. In several cases the reductions are greater than 90% from current RACT, which, if feasible, will require SCR technology, at a minimum. Mandating such stringent proposed ESADs may preclude the use of emerging burner technologies that may achieve SCR like NOx reduction performance levels without the adverse environmental impact of ammonia.

(b) Project Engineering Considerations

Meeting the ESAD emission limits, if feasible, will require the extensive use of SCR catalyst beds that must be located in the correct temperature zone of the flue-gas handling system to ensure proper operation. Process heaters, boilers, and furnaces designed specifically for the transfer of heat to process streams often have stack exit temperatures below 300°F. The lower temperature limit in the design of the low temperature SCR systems is 300°F. Unless space is available in the proper temperature zone of the heat recovery system, major system modifications must be made to accommodate the SCR retrofit. In some installations, there can be significant engineering obstacles to changing the design of the heat recovery system while maintaining system efficiency. A reduction in system efficiency increases the overall long-term cost of the NOx control step.

The boilers, heaters and furnaces are integral parts of the process and, in many cases, unit shutdowns will be required in order to complete the SCR retrofit. The time required to perform SCR retrofits may extend the normal process downtime and result in additional production losses. Such production losses are not typically experienced with combustion hardware changes, which can generally be done during normal major turnarounds. TNRCC has not adequately addressed these issues in their analysis of technical feasibility and cost.

(c) Other Considerations

The addition of the SCR reactor to the flue gas path will increase pressure drop, which will reduce the firing rate if the loss is not compensated for through the addition of fans (either larger or new) to educt the hot flue-gas through the SCR catalyst bed. This will result in additional load on the site infrastructure, both electrical and steam production. The SCR system includes the ammonia injection grid and the ammonia handling equipment. There are safety concerns with the handling of anhydrous ammonia and PSM/RMP requirements must be met, which will add complexity to the operation of the furnaces and boilers, heaters.

1.7.4 ICI Turbines and Duct Burners

(a) Background

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Gas turbines can be found in utility plants, industrial plants, and remote pipeline transmission sites, with each location, and in may cases each machine, having its own unique design and operating conditions that needs to be considered when determining the feasibility and cost of a particular NOx reduction technology. Gas turbines in the HGA vary by manufacturer and model, and the manufacturer must develop the technology for each specific engine model. For example, steam and/or water and low NOx combustion hardware is not currently available from some manufacturers, narrowing the owners’ technology options. The combustion control technology for many models of gas turbines is still being improved and new technologies, such as catalytic burners, are being developed but are not yet in commercial application.

In summary, there are four types of NOx control technologies for gas turbines; (1) wet combustion controls (steam or water) that can get many models down below 42 ppm, (2) combustion hardware controls (known as DLN or Dry Low NOx for most models) that are available for many models to get the ppm down to the mid-twenties or low-teens, (3) SCR to get the ppm down to below the 10 ppm level and, (4) a combination of SCR and combustion controls to reach the mid-single digits, if feasible.

Current RACT for gas turbines in the HGA is 42 ppm NOx and went into effect at year-end 1999. Requiring a 90% reduction from current RACT, which can only be achieved today with SCR, basically skips the DLN option. Mandating such stringent proposed ESADs for turbines may preclude the use of emerging combustion technologies that may achieve SCR like NOx reduction performance levels without the adverse environmental impact of ammonia.

(b) Project Engineering Considerations

The 90+% NOx reduction requirements for turbines, if feasible, will essentially requires the use of SCR which must be located in the correct temperature zone of the flue-gas handling system to ensure proper operation. Gas turbines in industrial sites are generally designed with heat recovery/ steam generating systems to capture exhaust gas heat, often resulting in stack exit temperatures significantly below 300°F. Current SCR technologies require higher flue-gas temperatures for the reduction of NOx to nitrogen. Unless space is already available in the proper temperature zone of the heat recovery system, major system modifications must be made to accommodate the SCR retrofit. In some installations, there can be significant engineering obstacles to changing the design of the heat recovery system while maintaining system efficiency. A reduction in system efficiency increases the overall long-term cost of the NOx control step.

The time required to perform SCR retrofits will extend the normal turbine downtime and result in additional production losses. Such production losses are not typically experienced with combustion hardware changes, which can generally be done during normal major turnarounds.

(c) Other Considerations

The backpressure increase for an SCR retrofit installation can be significant, increasing the

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overall turbine heat rate and subsequent loss in output. The loss in output must be compensated for, or production loss can occur.

Catalytic burners, an emerging technology for new gas turbines, have the potential to reduce NOx levels as low as SCR systems with no ammonia slip, and will likely be significantly lower in cost. Downtime for retrofits will certainly be less compared to an SCR installation that requires a heat recovery system modification. Operations and maintenance costs are also expected to be much lower and there will be no additional back pressure and resultant efficiency loss typically experienced with SCR retrofits. The long-term commercial viability of these burners for retrofit use is currently being tested.

The proposed 90% NOx reduction for all small stationary gas turbines is technically infeasible, physically limiting, economically impractical and would lead to unintended economic consequences. The proposed 90% plus NOx reduction for all small turbines (less than 10 - 20 Megawatts) imposes an excessively high cost for these units, which are often used with duct burners to generate thermal heat recovery efficiently. Solar Turbines Incorporated (Solar), a leading manufacturer of mid-range industrial gas turbines, with over 11,000 applications worldwide and over 90 applications in the HGA, has expressed similar concerns to TNRCC in a September 21, 2000 letter to TNRCC commenting on the proposed SIP regulations. Specifically, Solar stated that, "SCR systems may not be technically, operationally, and/or practically feasible for many of the applications as ~85% of the potentially affected units are in mechanical drive/compressor applications. Historically these applications, due to their high exhaust temperature, are not appropriate applications for an SCR and for which LAER levels have been 8-42 ppm." The use of efficient low NOx combustion technologies should be encouraged to achieve a reasonable 60 to 75% reduction to a 42 to 25 ppm NOx emission levels. In 2003, a mid-course correction evaluation should be undertaken before additional reductions are considered or attempted for small stationary gas turbines.

The TNRCC has not adequately addressed these issues in their analysis of technical feasibility and cost.

1.7.5 Internal Combustion Engines

(a) Background

Internal combustion (IC) engines can be separated into two broad categories, rich-burn engines and lean-burn engines, based on combustion characteristics. Rich-burn IC engines, characterized by being capable of operating with an exhaust oxygen content equal to or less than 0.5%, are subject to current TNRCC Chapter 117.205. These engines were required to meet a control level of 2.0 grams per horsepower hour (g/hp-hr) by November 15, 1999 reducing NOx emissions approximately 30 tpd in the HGA. The preferred method of control for rich-burn engines is non-selective catalytic reduction (NSCR), a flue gas treatment technology similar to automobile catalytic converters.

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Lean-burn IC engines cannot be operated with an exhaust oxygen content of 0.5% or less. They cannot be practically retrofitted with NSCR technology due to the high oxygen content of their exhaust. The preferred method of control is generally referred to as low emission combustion (LEC) technology. LEC, in broad terms, consists of increasing the air supply to the combustion cylinder and providing a high-energy source of ignition. In some cases measures must be taken to improve mixing of the fuel and air within the combustion chamber as well. The current TNRCC Chapter 117.205 rules do not apply to lean-burn engines.

(b) Emission Limitations

TNRCC has proposed a two-tiered emission limitation for IC engines. Plant sites with a total of 3,000 horsepower (hp) or more must control all engines to meet a NOX level of 0.17 g/hp-hr. Plant sites with a total of less than 3,000 hp must control all engines to meet a NOX level of 0.5 g/hp-hr. The 3,000 hp site size will apply the more stringent 0.17 g/hp-hr level to about 75% of the area's engines. Thus, about 75% of the gas-fired IC engines would be subject to 98% emission reductions. The remaining 25% of gas-fired IC engines would be subject to 75% reduction from the RACT level imposed just last year. One dual-fuel engine (capable of operating on either liquid or gaseous fuels or a combination of the two) was identified in TNRCC's survey. It is subject to a proposed limit of 0.5 g/hp-hr.

i) 0.17 g/hp-hr Standard

The preamble does not explain why IC engines were singled out as a source category for wholesale replacement. The preamble states that it is expected that the 0.17 g/hp-hr rate will necessitate replacement with electric drive motors. It would clearly be very difficult to meet this level with control technology. However, the preamble does not explain why a level so low as to force replacement is required.

Economic feasibility of replacement was based on limited data. The preamble cites costs for just one plant and that plant may not be operating the replacement electric drive motors as base load equipment. Other recent gas industry experience with electric drive replacement indicates the cost may be higher than cited in the preamble. The economic feasibility cited in the preamble also relies, in part, upon the value of credits generated by shutdown of the replaced engines. At a limit of 0.17 g/hp-hr however, replacing engines with electric drive will generate very few credits.

The preamble does not provide sufficient information to adequately analyze alternative approaches. It impossible to discern the relative number of rich-burn vs. lean-burn affected engines or the average horsepower of either class. It is impossible to discern the relative contribution of either class to the total tpd reduction.

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ii) 0.5 g/hp-hr Standard

The preamble concludes that the 0.5 g/hp-hr level can be achieved with control technology. For rich-burn engines, TNRCC expects additional NSCR catalyst to achieve the additional reduction. The one dual-fuel engine identified in TNRCC's survey is expected to use SCR to achieve the proposed limit. For lean-burn engines, the preamble assumes a combination of LEC technology and SCR.

SCR retrofits has been tried on a small number of engines in gas compression service in California with negative results. Its use has been so plagued with problems that, in every case, the operators who installed retrofit SCR abandoned its use; preferring instead to either accept a loss of capacity or find another way to achieve emission reductions.

EPA's Alternative Control Techniques Document -- NOx Emissions from Stationary Reciprocating Internal Combustion Engines (ACT Document), Table 2.5, indicates that SCR can achieve 90% reduction on lean-burn engines. However, a review of the test results supporting the ACT Document reveals highly variable reductions from the use of SCR. Only three of the six engines tested achieved 90% reduction on any test. Only one engine reported greater than 90% reductions for all tests conducted and it was a small (291 hp), non-typical gas engine. Two other engines achieved 90% reduction on at least one test, but did not achieve that level on other tests. Two engines had at least one test that reported zero NOx reduction. Test data with such variation over such a small sample is inadequate to support a decision to impose wide-scale retrofit of SCR technology on lean-burn engines.

Not only is the test data inadequate, the technology itself is unproven for the proposed application. Most engines in this class are used in either gas compression service or electrical power generation, both of which require that the engine follow swings in load. SCR has not proven to be very responsive to changing loads due to its inability to rapidly achieve a balance between inlet concentrations of NOx and the ammonia injection. Some SCR vendors contend that the feedback problem has been solved by the application of modern parametric monitoring systems (PEMS) which can react more rapidly than instruments. To date however, application of PEMS has been very limited and has been generally limited to new, well-instrumented, smaller, medium- to high-speed engines. There is little evidence that it would be possible to retrofit adequate PEMS systems on the older, large bore, low speed engines in current use in HGA.

(c) Alternatives to TNRCC Proposal

BCCA is committed to California-level retrofit standards, which would equal approximately a 75% reduction across point sources. BCCA is also committed to achieving reductions in ways that offer the greatest flexibility and in ways which maintain a healthy economy for the HGA. Therefore, BCCA offers an alternative to this TNRCC proposal to throw away good engines and replace them with electric motors.

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Rather than two tiers based on the availability of electric power, the standard should be based on the relative ease of controlling rich-burn vs. lean-burn engines. BCCA offers to work with TNRCC to identify the most cost-effective split between these technologies for the baseline engine population in HGA. A level could then be set for each class of engine that, in combination, would represent a 75% reduction from baseline emissions.

(d) Other Considerations

If electric drive motors replace engines, the sheer number of replacements will strain the availability of motors, switch gear, and other components. Power will have to be supplied to 36 sites at an average of three miles per site.

Installing NSCR on rich-burn engines will lead to the same concerns over catalyst availability and competition for welders and general construction workers as for other source categories.

LEC technology for lean-burn engines is highly specialized and requires almost case-by-case engineering to optimize the technology as well as specialized expertise to install the hardware. This specialized engineering and installation expertise is in short supply. The specialized hardware is supplied primarily by after-market vendors since many of the original equipment manufacturers are no longer in business or no longer support some of the engine models used in HGA. After-market vendors will have difficulty supplying parts for large-scale retrofit activity over a short time frame.

Clearly, the full available time up to the attainment year of 2007 will be needed for implementation on controls on internal combustion engines. BCCA believes the appropriate control technology for lean-burn IC engines is low emission control technology. To that end, BCCA commissioned a study6 of that technology with Enginuity and considerations for application to the mix of engines in HGA. (See Appendix III) TNRCC's survey results were not available at the time so the mix of engines differs somewhat. However, the major families of engines and their characteristics are represented.

1.7.6 Other Sources

There is no technical analysis presented by TNRCC to describe the technical and economic feasibility of the proposed retrofit limits for Refinery FCC unit sources, Incinerators, Dryers, Pulping Recovery Furnaces, Steel Furnaces, Kilns or other sources. The BCCA request specifically for FCCU and Incinerator sources that TNRCC provide the technical justification and economic feasibility analysis for the proposed emission limitations. Only 1 FCC unit in the United States has been recently retrofitted with SCR and there is no long term demonstrated commercial experience in the world to indicate this type of retrofit NOx standard is achievable for all the FCC unit sources in HGA.

6 Impact and Assessment of Proposed Emission Reduction Regulations for Houston Galveston Area Stationary IC Engines, Enginuity International, Inc. July 2000

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1.8 Use of Ammonia-Based Technology

1.8.1 Adverse Effects of Increased Ammonia Emissions

TNRCC has proposed emission limitations for boilers, heaters, turbines, and IC engines that will require the widespread use of flue-gas NOx reduction technologies that utilize ammonia. The use of ammonia in flue-gas treatment technologies such as Selective Catalytic Reduction (SCR) and Selective Non-Catalytic Reduction (SNCR) provides the chemical reducing environment necessary to convert NOx to molecular nitrogen and water. Equipment manufacturers recommend, and experience has shown that excess ammonia must be injected into the catalyst beds to ensure maximum conversion of NOx. Ammonia emissions are typically controlled at the catalyst bed outlet to about 10 ppm ammonia. This excess ammonia from the catalyst bed is required by design and is commonly referred to as ammonia slip.

The Coalition is concerned that increased ammonia emissions from the use of NOx control technologies such as SCR and SNCR could result in unintended negative environmental consequences that have not been considered or evaluated by TNRCC. Such consequences could include, but are not limited to, increased ambient levels of fine particulate matter that might negate any environmental benefit that might otherwise be achieved from use of this technology to reduce regional ozone levels. To better understand this issue, the BCCA contracted with Dr. David Allen at the University of Texas in Austin to quantify the potential environmental consequences associated with a significant increase in ammonia emissions within the HGA from the NOx control technologies envisioned by TNRCC7. (See Appendix IV) Specifically, Dr. Allen was asked, (1) Will the increase in ammonia emissions associated with NOx controls represent a significant change in the amount of ammonia released to the atmosphere in the HGA, and (2) Will increased ammonia emissions effect particulate matter concentrations.

Utilizing the proposed TNRCC emission limitations for point sources, it was assumed that all combustion units greater than 40 MBtu/hr would require to use of ammonia-based NOx control technologies. Furthermore, it was assumed that the vendor recommended ammonia slip rate of 10 ppm would be used for controlling NOx emissions from each unit. Under this assumption, ammonia emissions in the 8-county HGA would increase approximately 31.5 tons per day or approximately 23 million pounds per year. This increase in emissions will bring some of Houston-Galveston area counties to the top of EPA's Toxic Release Inventory list for ammonia.

Will the Increased Ammonia Emissions Associated with NOx Controls Represent a Significant Change in the Amount of Ammonia Released to the Atmosphere in the HGA?

Based on recent data in the EPA's Toxic Release Inventory (TRI), TNRCC's proposed point source control plan would increase ammonia from point sources in Harris County by up to an

7 The impact of ammonia emissions on particulate matter concentrations in the Houston/Galveston Area (HGA) non-attainment region, Dr. David Allen, University of Texas at Austin, April 29, 2000.

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order of magnitude. Based on a preliminary comprehensive ammonia inventory being developed by the University of Texas, total Harris County ammonia emissions would increase by 25-50%, while ammonia in the 8-county HGA would increase by approximately 10%. These TRI and preliminary comprehensive inventory data clearly indicate that ammonia emissions in the HGA will significantly increase as the result of the proposed TNRCC NOx reduction plan for point sources.

Will increased ammonia emissions effect particulate matter concentrations?

Increased ammonia emissions may or may not have an impact on ambient particulate concentrations. If there is a significant quantity of unneutralized acids (e.g., sulfuric acid) in the atmosphere then increases in ambient concentrations of ammonia will lead to increased amount of particulate matter. Ambient particulate data collected across the Greater Houston area by the City of Houston, the TNRCC, and the Houston Regional Monitoring Corporation from March 1997 to March 1998 suggests that 10-30% of the acids contained in ambient particulates are not neutralized. Thus, particulate matter in the region is acidic and increasing ammonia concentrations have the potential to increase fine particulate matter ambient concentration. Specifically, additional ammonia from NOx reduction technologies would react with excess sulfuric acid in the air to form ammonium sulfate, a fine particulate, until the sulfuric acid is fully neutralized. In the Houston-Galveston Area, full neutralization of the sulfuric acid could lead to an increase in ambient fine particulate matter of 0.2 to 0.5 micrograms per cubic meter (ug/m3).

Furthermore, it is possible that the increased ammonia emissions might also neutralize nitric acid, forming ammonium nitrate. This ammonia nitrate might also add further to ambient particulate matter concentrations. Currently, there is not enough information available to assess this possibility, but it is incumbent upon TNRCC to assess this potential before finalizing the SIP.

In summary, the projected ammonia releases associated with proposed SIP NOx controls could add 0.2-0.5 ug/m3 to ambient particulate matter in the HGA. Increasing the mass of particulate matter in the atmosphere would drive the HGA closer to violating the pending National Ambient Air Quality Standard (NAAQS) for fine particulate matter (i.e., PM2.5). It is incumbent that TNRCC fully assess the benefits (e.g., lower ozone) and potential risk (e.g., higher particulates) of requiring NOx control technologies that significantly increase ammonia emissions.

1.8.2 Increased Risk of Ammonia Storage and Handling

Ammonia for use in flue-gas treatment technologies will have to be transported into the region in bulk and stored on-site at virtually every plant location in the HGA. Larger industrial sites with multiple combustion units may require multiple on-site storage facilities with extensive piping networks to deliver ammonia to the flue-gas treatment catalyst beds. It is estimated that under the proposed TNRCC point source control strategy, ammonia usage in the HGA will increase by 330 tons per day, or over 240 million pounds per year.

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The nearest ammonia production facility is in Beaumont, Texas. A significant increase in truck and rail transport of ammonia into the Houston-Galveston area will be required unless additional local ammonia production is added. The transportation, handling, storage, and use of such bulk quantities of ammonia throughout the HGA increases the risk of accidental releases. Before mandating the widespread use of ammonia-based NOx control technologies, the TNRCC should assess the overall regional risk of introducing these new major quantities of ammonia in the HGA relative to the NOx/ozone reduction benefit derived from the controls.

A recent paper8 shows that ammonia is the number one reported Risk Management Plan (RMP) chemical in terms of accidental release events. Increased production, transportation, handling, transferring, and storage of ammonia needs to be evaluated for this region. TNRCC should review the range of RMP issues raised by the proposed SIP and fully address this issue in the final rule.

8 Accident Epidemiology and the U.S. Chemical Industry: Preliminary Results from RMP*Info, Paul R. Kleindorfer, Harold Feldman, and Robert A. Lowe, Center for Risk Management and Decision Processes, The Wharton School, University of Pennsylvania, February 3, 2000.http://epihb.wharton.upenn.edu

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Section 2: Texas Clean Fuels

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2.0 Texas Clean Fuels

2.1 Overview of Fuels Issues

The BCCA supports cleaner fuels for Texas. Emerging federal clean motor fuel requirements in combination with lower emission vehicles and construction equipment will provide significant reductions in NOx emissions not only in the Houston-Galveston area (HGA), but also across the nation.

The HGA is unique in having approximately 15% of the petroleum refining capacity of the nation represented by 8 world-class facilities. Correspondingly, this area will bear a major portion of the capital investment necessary to make the cleaner burning fuels for the nation. Cleaner fuels are typically achieved by product reformulation to modify the fuel characteristics such that NOx emissions are reduced. Cleaner motor fuels, for the purposes of these comments, include gasoline and diesel fuels used in both on-road vehicles and non-road equipment.

On-road mobile sources include passenger vehicles, such as cars, trucks, and busses, which travel on public roadways and utilize gasoline and diesel fuels. Non-road mobile sources include a broad range of equipment that does not typically operate on public roadways and largely operate on diesel fuel. Such equipment can include, but is not limited to, heavy highway construction equipment (e.g., road graders, bull dozers), industrial/commercial/residential construction equipment (e.g., cranes, fork lifts, back hoes), marine vessels (e.g., cargo ships, barges, tugs), locomotive engines, and commercial airplanes. In total, both on-road non-road vehicles and equipment account for approximately 40% of the total NOx emissions slated for the HGA.

2.2 Proposed Texas Low Sulfur Gasoline (LSG) Rule

The proposed TNRCC LSG rule establishes the most stringent gasoline specifications in the nation. While the proposed Texas LSG will achieve significant NOx reductions, the Coalition supports EPA’s new Tier 2 low sulfur gasoline rule, adopted late last year, as a much better alternative that provides virtually identical NOx reduction benefits at a much lower cost to the motoring public because:

(1) The proposed Texas LSG presents a much higher market risk and uncertainty for gasoline supplies throughout east Texas than EPA's Tier 2 gasoline rule.

(2) The proposed Texas LSG will result in a much higher production cost relative to EPA Tier 2 gasoline.

(3) The proposed Texas LSG will produce virtually the same NOx and ozone reduction benefits as EPA's Tier 2 gasoline.

(4) The proposed implementation schedule for Texas LSG does not allow sufficient time

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for compliance.

(5) The existing fuels distribution infrastructure is not currently sufficient to deliver Texas boutique fuels to the marketplace in a timely fashion.

(6) A boutique fuel is not needed to maintain attainment outside of the HGA.

(7) The proposed Texas LSG is not legally defensible

2.2.1 Higher Market Risk of the Proposed LSG Rule

The BCCA contracted with Dr. Philip Verleger, a nationally recognized energy market expert, to assess the potential impacts of the proposed TNRCC fuel rules on the fuels commodity market in Texas. This study9, included as Appendix V, utilizes the California experience with special regional, or "boutique" fuels to predict the response Texas LSG will have on the fuels market in Texas. A similar retrospective assessment was performed by Dr. Verleger on the market impact of California Clean fuels and is included in Appendix VI10. In summary:

The Proposed LSG Will Reduce Region Fuel Supplies

The proposed regulations will have a significant financial impact on refiners operating in Texas as a result of the high capital cost necessary to achieve the extremely low sulfur levels proposed by TNRCC. It is highly likely that some refiners in the region will not make the necessary investments to produce Texas LSG for technical, financial, or market-based reasons. This will result in a reduction in the number of fuel suppliers and the available supply of fuels to the Texas boutique fuel market. Additionally, due to the very stringent fuel specifications, the refiners that choose to produce the proposed Texas fuels will not be able to produce as much fuel as before. Severe hydrotreating and other process changes needed to achieve the proposed fuel specifications will reduce the volume of boutique fuel that can be produced relative to historical volumes. Finally, some refiners may decide to produce only EPA Tier 2 fuel at a much lower capital and operating cost for consumption outside the Texas boutique fuel area. These measures collectively will reduce the supply of available fuel for Texas consumers.

The Proposed Texas LSG Reduces Incentives for Refiners to Invest

A refiner's decision to invest in a special Texas fuel will depend on factors that impact their ability to recover the investment costs in the market place and earn a return on that investment. Refiners are unlikely to undertake significant capital investments that are high risk or that are expected to be unprofitable. In fact, when comparing capital projects for the proposed Texas

9 The Economic Consequences of Rigid Clean Fuel Regulations in Texas, by Dr. Philip K. Verleger, Jr., The Brattle Group, Washington, D.C. August 200010 The California Conundrum: Causes of Gasoline Price Volatility, by Dr. Philip K. Verleger, Jr., The Brattle Group, Cambridge, MA March 2000

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LSG verses the EPA Tier 2 gasoline, investment risk will be a key consideration in developing a refiner’s fuel strategy.

The sulfur levels proposed by TNRCC have never been achieved before in a broad market place and the necessary technologies to achieve those sulfur levels are in limited use. This results in a higher investment risk to refiners when considering whether to make the proposed Texas LSG for a limited market verses nationally based fuels. Furthermore, there is possibility of TNRCC, EPA, or the Texas Legislature allowing “waivers” for refineries to sell non-compliant motor fuels in time of high demand or short supplies. Such waivers will artificially reduce fuel prices to below the level that would otherwise allow the recovery of capital and operating costs at refineries producing compliant fuels. Such concerns represent additional investment risk to refiners.

As a result of these investment risks, some refiners may choose not to make investments for Texas LSG and make only EPA Tier 2 fuels for marketing nationwide. Other refiners may close or consolidate their Texas operations if the necessary investments are unprofitable and if there are no viable alternative strategies. Each of these reactions occurred in California when that state introduced CARB gasoline and diesel. TNRCC is likely to see a similar mix of responses by Texas refiners.

The Proposed Texas LSG Limits Refiner’s Ability to Build New Facilities

The implementation schedule for the proposed TNRCC fuels both proceeds and overlaps the phase-in of EPA Tier 2 gasoline and the introduction of the proposed EPA diesel. The National Petroleum Council (NPC)11, an advisory body appointed by the Secretary of Energy, has determined that “design and construction resources may be taxed during periods of peak workload as refiners prepare to produce gasoline that meets the Tier 2 requirements”. (See Appendix VII) The NPC also cautioned that “engineering and construction resources will likely be inadequate if federal diesel sulfur reduction significantly overlaps the implementation of Tier 2 gasoline." The TNRCC proposals calls for the simultaneous design, engineering, and construction of both cleaner gasoline and diesel for Texas during the same period refiners are trying to bring federal fuels to market. Additionally, these clean fuel projects overlap significant stationary point source NOx reduction efforts that will compete with the same design, engineering, and construction resources as the fuel projects in the HGA.

A study commissioned by the BCCA with the Fluor Daniel Company assessed the available supply of and demand for manpower, equipment and material resources necessary for, (1) HGA point source NOx SIP requirements and, (2) nationwide EPA fuel requirements. Manpower, equipment, and material resources needed for the Texas fuel proposals, and other Texas and nationwide SIP requirements (e.g., NOx SIPs for other ozone non-attainment areas, the OTAG NOx SIP Call) were not estimated in the study. This study concluded that even if all available engineering and design resources nationwide were dedicated to just these two efforts alone,

11 U.S. Petroleum Refining - Assuring the Adequacy and Affordability of Cleaner Fuels, National Petroleum Council, June 2000.

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demand would exceed current supply by up to 40%. There are also shortages in materials and equipment as well. In summary, the scope and breadth of national and Texas environmental requirements will severely limit the ability of refiners to make the necessary clean fuel upgrades by the TNRCC proposed deadline.

2.2.2 Higher Production Costs for the Proposed Texas LSG

TNRCC has estimated the increase in production cost for the proposed Texas LSG is $0.03 to $0.07 per gallon based on the EPA’s regulatory impact analysis of the new Tier 2 gasoline rule (Regulatory Impact Analysis: Control of Air Pollution from Motor Vehicles: Tier 2 Vehicle Emission Standards and Gas Sulfur Control Requirements). TNRCC has significantly underestimated the production cost for the proposed Texas LSG by basing production cost estimates on the much less stringent EPA Tier 2 gasoline regulations.

EPA's Tier 2 gasoline has an 80 ppm sulfur cap verses the proposed Texas LSG sulfur cap of 15 ppm; EPA's Tier 2 gasoline also has a 30 ppm average sulfur specification. While the Texas LSG does not have a mandatory average sulfur specification, in order to consistently achieve a 15 ppm cap, sulfur level in LSG must average 7-10 ppm. In other words, the sulfur specification for the Texas LSG proposal is about 75% lower than the EPA Tier 2 gasoline standard. Additionally, there is a significant technology transition as sulfur levels drop below about 30 ppm. Refiners may be able to upgrade existing and/or build new hydrotreaters to remove sulfur from gasoline component streams down to 30 ppm. At sulfur levels below 30 ppm, new high pressure/high temperature hydrotreaters are needed and more gasoline component streams must be treated to remove sulfur. The more severe hydrotreating operation requires significant new process equipment and plant design changes that are very expensive. The National Petroleum Council has estimated that the cost to produce the EPA Tier 2 gasoline is about $0.045 per gallon. BCCA estimates that the cost to produce the new Texas LSG, with an additional 75% reduction in sulfur level, could be as much as 3 times the cost of EPA Tier 2 gasoline. This estimate is based on the extremely low sulfur specification for Texas LSG and the required use of high-pressure hydrotreating on more gasoline component streams.

2.2.3 Virtually No Additional Environmental Benefits for Texas LSG

TNRCC has proposed sulfur levels lower than any gasoline ever required in the U.S. Although lower sulfur levels generally produce lower NOx emissions, the reduction diminishes significantly below 150 ppm and is virtually indeterminate below 30 ppm. Sulfur levels in gasoline were the subject of nationwide debate for over a year during development of the EPA Tier 2 gasoline. EPA conservatively chose the maximum NOx reduction target by requiring a 30 ppm average/80 ppm cap on sulfur in conjunction with new engine standards and exhaust treatment systems coming on the market in 2004. TNRCC has not modeled NOx emission reductions below 30 ppm because no data exist. Nevertheless, the agency claims the proposed Texas LSG will result in a 1.15 tpd greater NOx reduction than the EPA Tier 2 gasoline in 2007. Given the lack of science to support this claim, the 1.15 tpd NOx reduction claim is, at best, an optimistic estimate. The Coalition estimates that the incremental cost to achieve the 1.15 tpd

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NOx reduction is over $400,000 per ton. The Coalition believes that, given the high cost and low environmental benefits of the proposed Texas LSG, the TNRCC should not adopt the proposed fuel and maintain Texas gasoline standards consistent with EPA Tier 2 standards.

2.2.4 Insufficient Time to Implement the Texas LSG Rule

The TNRCC has proposed that Texas LSG be in the market place by 5/04. Assuming a final rule is adopted by year-end 2000, this provides about 3 years for industry to design, engineer, permit, procure equipment, construct, and begin production of the new fuel. Given the extremely low sulfur levels required by the proposed LSG rule and the severe hydrotreating that would be necessary to achieve those levels, production facilities will be much more extensive than those facilities required for the EPA Tier 2 gasoline rule. Furthermore, the implementation schedule for Texas LSG is further constrained by on going refinery modifications for EPA Tier 2 compliance that are already underway across the nation. Refineries in the Houston-Galveston area (HGA) that choose to make Texas LSG, will be required to re-engineer the existing EPA Tier 2 gasoline facilities to ensure the ability to comply with the Texas fuel proposal. This will certainly further delay the front-end engineering and design of the cleaner fuel projects.

As noted in Section 2.2.1, the National Petroleum Council study, and the independent study by the Fluor Daniel Company, have indicated there will be a significant shortfall in the manpower, material, and equipment resources to simultaneously deliver EPA Tier 2 gasoline, Texas LSG gasoline, and the HGA point source NOx reduction projects. These shortfalls will be worsen by demand for similar manpower, material, and equipment resources in other ozone non-attainment areas and the OTAG NOx SIP Call and SIPs for other ozone non-attainment areas across the country. These projected shortfalls in critical project resources will place the HGA in an untenable compliance situation.

Fortunately, from a fuels perspective, an alternative exists in EPA’s Tier 2 gasoline requirements that were finalized in late 1999. Industry is already in the planning and permitting stages for these national fuel projects. EPA's Tier 2 gasoline provides comparable NOx reduction benefits to the proposed Texas LSG at a much lower cost to the motoring public. The BCCA supports the EPA Tier 2 gasoline rule as the clean fuel of choice for the HGA SIP.

2.2.5 The Existing Distribution Infrastructure is not Adequate

TNRCC has not assessed the potential impacts of creating special fuels for Texas on the existing fuel distribution system. The proposed Texas LSG rule will create four additional grades of gasoline to be blended and distributed through systems that are already stretched beyond design. These four additional grades are 87 octane RFG/LSG, 93 octane RFG/LSG, 87 octane conventional LSG, and 93 octane conventional LSG. There are serious and real concerns that it will not be possible to blend and distribute the boutique fuels throughout Texas while providing the rest of the country with EPA specified fuels. Additionally, there are serious and real concerns that it will not be possible to consistently maintain an ample supply of a 15 ppm sulfur cap product to the market place while significantly higher sulfur products are being shipped in

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the same fuel distribution and delivery system. The recently published study by the National Petroleum Council concluded that, “The question of whether the distribution system can handle ultra-low sulfur product and maintain the integrity of the sulfur level is very much in doubt as long as higher sulfur products are shipped in the same distribution system. The domestic industry has no experience with handling ultra-low sulfur fuels."

A harmonization between state and federal fuel specifications is needed in order to have a reliable supply of affordable fuels available to the driving public. The TNRCC has not assessed whether or not the 15 ppm sulfur cap LSG product can actually be delivered to a retail station while still maintaining the sulfur integrity of the product from refinery tanks, through pipeline shipments to remote distribution terminals, through transfers to transport trucks to retail underground storage, and finally to the consumer. It may be likely that new dedicated fuel distribution systems or system components will be needed to deliver low sulfur Texas fuels to the market place. The TNRCC should seek input from refiners, pipeline carriers, and fuel distributors on these critical issues. Adopting the EPA Tier 2 standards as the fuel of choice for Texas would alleviate many of these fuel distribution and integrity concerns.

2.2.6 A Boutique Fuel is not Needed to Maintain Attainment Outside the HGA.

There are several concerns with the inclusion of attainment areas in this rule. The Coalition believes that requiring a special fuel, made nowhere else in the nation, for areas that are in attainment, has no technical, environmental, or legal basis and is not necessary to meet the NAAQS in those areas. Clearly, EPA's Tier 2 gasoline rule will be available in these attainment areas and provide ample NOx and VOC reductions to maintain and improve air quality in attainment regions.

TNRCC has not presented adequate technical or scientific information such as photochemical modeling, to demonstrate that there is any incremental measurable ozone reduction benefit to the HGA associated with the proposed Texas LSG verses EPA Tier 2 Gasoline when applied to attainment areas. To simply say that all is interrelated without substantiation is not a reasonable basis for such a costly SIP proposal.

TNRCC states that the proposed Texas LSG gasoline requirements were developed in order to meet the ozone NAAQS set by the EPA under 42 USC, §7409, and therefore meet a federal requirement. Provisions of 42 USC, §7410, require states to adopt a SIP which provides for “implementation, maintenance, and enforcement” of the primary NAAQS in each air quality control region of the state. We point out that there is no requirement to regulate air quality in attainment counties.

2.2.7 The Proposed Texas LSG is not Legally Defensible

The BCCA believes that the proposed Texas LSG rule has a number of legal deficiencies that

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will ultimately result in protracted litigation and a delay in the delivery of cleaner fuels to Texas. Each legal deficiency is avoided by the adoption of EPA Tier 2 gasoline as the fuel of choice for Texas:

TNRCC Has Not Performed the Required Regulatory Impact Analysis

The Texas Government Code (TGC) §2001.0225, as amended by Senate Bill 633 (SB633) during the 75th Legislative Session, requires a Regulatory Impact Analysis (RIA) for proposed regulations that meets the definition of a “major environmental rule”, as defined by statute. The BCCA believes that the proposed LSG rule meets the definition of a major environmental rule, and that the RIA requirements of TGC §2001.0225 are triggered because the proposed rule: (1) exceeds standards set by federal law, and (2) exceeds an express requirement of state law. The proposed LSG rule goes beyond what is required by state and federal law, goes far beyond what is necessary to achieve air quality goals in Texas, exceeds technical and economically feasibility and reasonableness, and exceeds TNRCC legal authority. TNRCC can alleviate the need for a RIA by adopting EPA Tier 2 gasoline as the fuel of choice for Texas.

Federal Preemption On Controls for Gasoline

The Federal Clean Air Act preempts States from regulating any characteristics of fuels if EPA has either determined that regulating such characteristics is unnecessary, or if EPA has already regulated fuel characteristics under 211(c)(1) of the Clean Air Act. There are two exceptions – the State of California is not preempted, and section 211(c)(4)(C) allows the Administrator to waive preemption. To qualify for the waiver, a State must demonstrate that the proposed fuel control is necessary to achieve a national ambient air quality standard (“NAAQS”) and that there are no reasonable or practicable non-fuel control measures available that will result in timely attainment. Eight of the counties in HGA and four counties in the DFW area are already subject to federal fuel controls (i.e., the reformulated gasoline ("RFG") program) which establish restrictions on sulfur content by the limits of the Complex Model in the RFG regulations. Section 211(c)(4) preempts states from imposing any fuel controls that are related to, or connected with, any fuel characteristic regulated by EPA under section 211(c)(1). TNRCC's proposed sulfur control for Texas Low Sulfur Gasoline would be a fuel control related to, or connected with, EPA's fuel NOx control program and as such is preempted by 211(c)(1) of the Clean Air Act.

Additionally, TNRCC's proposed gasoline sulfur control is preempted by EPA's Tier 2 low sulfur gasoline regulation. States are required to obtain EPA’s approval before prescribing gasoline sulfur content requirements that differ from the controls that EPA has already imposed as part of its Tier 2 gasoline regulation. To obtain EPA's approval, TNRCC must show that the proposed Texas Low Sulfur Gasoline is necessary to achieve a NAAQS and that the fuel control would result in emission reductions. In addition, the TNRCC must consider all reasonable and practicable non-fuel measures, quantify the emission reductions that would result if the non-fuel measures were imposed, and demonstrate that the non-fuel measures are unreasonable or

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impracticable. TNRCC has not made such as demonstration.

Lack of Authority to Require Fuel Controls in Attainment Areas

TNRCC is limited under state law to mandate a fuel control in areas of the state that are currently in attainment. Section 382.037(g) of the Texas Clean Air Act prohibits TNRCC from establishing vehicle fuel content standards contrary to standards promulgated by EPA unless:

(1) Specifically authorized by the legislature, or(2) It is demonstrated as necessary for the attainment of federal ozone ambient air quality

standards, or(3) It is demonstrated as necessary for the protection of public health based on appropriate

health studies and consultation with the Texas Department of Health.

TNRCC does not establish in the record for the proposed rule that any of these criteria are met and must do so before finalizing new fuel rules for Texas that are different from federal fuel requirements.

The BCCA supports cleaner fuels for the HGA and the state of Texas. Cleaner fuels will be critical to achieving the air quality goals of the region. We believe that the new federal Tier II low sulfur gasoline coming on the market in 2004 and the proposed federal ultra-low sulfur diesel expected to be on the market in 2006 will provide substantially similar environmental benefits at a much lower cost to the motoring public in Texas.

2.2.8 Other Gasoline Issues

i) Mid-Course Correction

TNRCC has committed to rerun the mobile source scenarios for this proposed rule with MOBILE6 when that model is available. We support this and point out that updates for the diesel proposals and for the yet to be offered federal off road diesel proposal next spring should also be modeled using MOBILE6. As for the mid course correction, as it applies to these proposed rules, the Coalition has some concern. For fuels issues, investment and construction plans require such long lead times (typically 4 years) that certainty, more than delivered on time and without supply disruption. The fuels adopted in December will not reach the market place for 4 years and any fuel specification changes at the mid-course correction may compromise the overall regional fuel strategy. We ask that TNRCC take this into account when considering mid course SIP corrections in the fuels arena and that we be consulted in that process.

ii) Waivers

The commission is concurrently submitting, as part of the SIP and with this proposed rulemaking, a waiver request in accordance with the 42 USC, §7545(c)(4)(C), to implement this proposed Texas LSG gasoline rule which is more stringent than the federal sulfur control rules.

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The Coalition does not support this waiver for all the same reasons we oppose this proposed rule and believe that EPA’s Tier 2 gasoline rule is a much more viable alternative.

iii) Alternative Gasoline Formulations

The commission solicited comment regarding the possible benefits of controlling components of gasoline other than sulfur by which equivalent emission reductions could be achieved as a possible alternative to the controls on sulfur as described in this proposal. We point out that EPA has studied this issue and has not seen fit to propose any other gasoline specification controls in their recently adopted rule. The Coalition opposes any additional gasoline specifications other than sulfur reductions to achieve NOx reduction benefits.

iv) Small and Micro-Business Impacts

The Commission does not adequately evaluated fiscal implications on small business or micro-business as a result of administration or enforcement of the proposed new fuels. Any retailers in boundary areas could be individually and significantly impacted by the unique nature of the fuels proposal. This would not be true if the federal LS gasoline program was adopted. Impacts will also be felt by distribution facilities that serve areas across boundaries and refineries that make product for use inside and outside of the covered areas. These competitive pressures could be individually significant, so much so as to seriously impact the viability of future operations.

v) Emission Reductions

We believe that a serious unanswered question remains relating to emissions accounting. It is how to account for programs that are implemented, but not at maturity during the ozone attainment year in question. The Texas fuel proposals are such a program. Full program maturity, in terms of NOx reduction, will not occur until the gasoline engine (cars and trucks) fleet has turned over with new vehicles that can efficiently make use of the low sulfur gasoline being supplied to the market place. The region is currently measuring the effectiveness of this program in 2007 when it achieves a 32 tpd NOx reduction. We estimate that only 3 years later in 2010 it will achieve a 53 t/d and, at maturity, it will achieve over 100 t/d NOx reduction credit. TNRCC should work with EPA and all the other areas in this predicament to develop a method for crediting these prospective NOx reductions in the attainment SIP.

vi) Gasoline Additives

TNRCC has proposed control measures including identified and unidentified gasoline and diesel fuel additives elsewhere in the SIP. For the most part, these proposed additives are in the process of being evaluated and performance under actual conditions of use is still being quantified. For example, TNRCC has implied that additives may be approved for use in compliance with the Texas Low Emission Diesel (LED) program. We also understand that additive manufacturers are discussing with TNRCC applications in the LS gasoline program. While this class of potential emission reduction additives is still being evaluated, it is premature

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to include them as a mandatory fuel control measure. Rather, they more properly belong to that group of potential emission reduction measures for use in a market based incentives program. A market based incentive program for NOx and VOC emission reductions provides for the development, validation, certification (if necessary) and introduction of fuel additives based on the demand for, and price of, such additive. Market based incentive programs can achieve emission in a manner that is superior to, and more cost effective than, mandatory measures. TNRCC should include this class of emission reduction measure in a market based incentive program.

2.3 Proposed Texas Low Emissions Diesel (LED) Rule

The proposed Texas LED rule, like the proposed Texas LS Gasoline rule, establishes the most stringent diesel specifications in the nation. While Texas LSD will achieve significant NOx reductions, the Coalition supports a nationally based diesel standard as a much better alternative. EPA has proposed new low sulfur diesel standards that are expected to be finalized by year-end 2000 and in the market place by 2006, consistent with the proposed Texas LED fuel. The proposed federal diesel rule is expected to provide virtually identical NOx reduction benefits at a much lower cost to the motoring public because:

(1) The proposed Texas LED presents a much higher market risk and uncertainty for diesel supplies throughout east Texas.

(2) The proposed Texas LED will result in a much higher production cost relative to both CARB diesel and the proposed EPA diesel rule

(3) The proposed Texas LED will produce virtually the same NOx and ozone reduction benefits as the proposed EPA diesel rule.

(4) The proposed implementation schedule for the Texas LED rule does not allow sufficient time for compliance.

(5) The existing fuels distribution infrastructure is not currently sufficient to deliver Texas boutique fuels to the marketplace in a timely fashion.

(6) A boutique fuel is not needed to maintain attainment outside of the HGA.

(7) The proposed Texas LED is not legally defensible

2.3.1 Higher Market Risk of the Proposed LS Diesel Rule

The higher market risks associated with the proposed Texas LED rule are similar to those described in Section 2.2.1 for the proposed Texas LSG rule. In summary, the proposed Texas LED rule will:

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Reduce Regional Diesel Fuel Supplies

Reduce Incentives for Refiners to Invest in LS Diesel Facilities

Limit Refiners’ Ability to Build New Facilities

2.3.2 Higher Production Costs for the Proposed Texas LED Rule

The TNRCC has estimated the increase in production cost for the proposed 2006 Texas LS diesel (15 ppm sulfur, 10% aromatics, and 48 cetane) at $0.08 per gallon (after phase-in of the 15 ppm ultra-low sulfur requirements). We believe this estimate to be low by over a factor of two (2) or more. Current California Air Resource Board (CARB) diesel, similar to the proposed Texas LED in 2002 at 500 ppm sulfur and 10% aromatics, is estimated to increase the manufacturing costs about 9 cents/gallon based on the EPA MATHPRO: 9-99 Gasoline Modeling Studies for proposed federal low sulfur diesel rule. From the CARB diesel market place experience, we would expect that the production cost of Texas LED 2002 fuel to be in the same league as CARB diesel, or about 9 cents/gallon, since the two fuel specifications are similar.

The second step to make Texas LED for 2006 will require very deep fuel desulfurization to reduce sulfur levels from 500 ppm today down to 15 ppm sulfur by 2006, while maintaining the aromatics at below 10%. This will be very challenging. Overall we estimate the production cost to go from the 500 ppm sulfur 2002 Texas LED to the 15 ppm sulfur Texas LED in 2006 will be comparable to the cost to produce the proposed federal ultra-low sulfur diesel (15 ppm sulfur), or about $0.10 per gallon. Therefore, unless there is a desulfurization technology break through, or new refining process synergies developed, the combined cost for the Texas LED program in the year 2006 is estimated to be over 2 times higher than the TNRCC estimate of $0.08 per gallon.

2.3.3 Virtually No Additional Environmental Benefits for Texas LED

The TNRCC has overestimated the NOx reduction benefits for Texas LED. As described in Appendix G to the proposed Rule (Revised SIP Modeling Procedures for the Houston Galveston Non-Attainment Area), the NOx reduction benefits for the proposed Texas LED was assessed by the Eastern Research Group (ERG) in a document dated July 26, 2000. ERG’s analysis of NOx reductions from diesel vehicles and engines is based heavily on two models that both contain very limited sets of data. In projecting NOx reductions from post-1990 engines, the model was based on only one large Caterpillar engine study using a matrix of laboratory diesel fuel formulations that are not even commercially available. While the study was well executed, the extremely limited scope makes it inappropriate to presume it will accurately predict NOx reductions from the fleet of in-use vehicles throughout Texas. A decision to regulate diesel fuel that could significantly increase costs should be based on adequate data that accurately reflects actual in-use fleets. The BCCA believes it is not proper to draw conclusions simply because it is

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the only data available, and especially if the data set is extremely small.

EPA evaluated the effectiveness of regulating diesel parameters other than sulfur during the development of their proposed low sulfur diesel rules. In the preamble to the notice of proposed rulemaking, EPA states: “According to correlations between these fuel properties and emissions that have been presented in various published documents, the effects are rather small." Given this evaluation, and the forthcoming federal rulemaking for on-road diesel that provides substantially equivalent NOx emissions benefits, the BCCA support the pending federal low sulfur diesel fuel for Texas.

2.3.4 Insufficient Time to Implement the Texas LED Rule

The TNRCC has proposed that the first phase of Texas LED be in the market place by 5/02, with ultra low sulfur levels due by 5/04. Assuming a final rule is adopted by year-end 2000, this provides about 1 year for industry to design, engineer, permit, procure equipment, construct, and begin production of the new fuel. Given the extremely low sulfur levels required by the proposed Texas LED rule in 2004, and the severe hydrotreating that would be necessary to achieve those levels, production facilities will be much more extensive than those facilities required for diesel fuel today. Furthermore, the implementation schedule for Texas LED is further constrained by on going refinery modifications for EPA Tier 2 compliance that are already underway across the nation.

As noted in Section 2.2.1, the National Petroleum Council study (See Appendix VI), and in the independent study by Fluor Daniel (See Appendix I), have indicated there will be a significant shortfall in the manpower, material, and equipment resources to simultaneously deliver EPA Tier 2 gasoline, Texas boutique fuels, and the HGA point source NOx reduction projects. These shortfalls will be worsened by demand for similar manpower, material, and equipment resources in other ozone non-attainment areas across the nation and in the OTAG NOx SIP Call states. These projected shortfalls in critical project resources will place the HGA in an untenable compliance situation.

Fortunately, from a fuels perspective, an alternative exists to the proposed Texas LED in the EPA proposed ultra-low sulfur diesel rule. The national diesel will provide comparable NOx reduction benefits to the proposed Texas LED at a much lower cost to the motoring public. The BCCA supports efforts to align the Texas diesel rulemaking with EPA's nationwide diesel proposal.


TNRCC has not assessed the potential impacts of creating special fuels for Texas on the existing fuel distribution system. The proposed Texas LED rule will create an additional grade of diesel

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to be blended and distributed through systems that are already stretched beyond design. There are serious and real concerns that it will not be possible to blend and distribute the boutique fuels throughout Texas while providing the rest of the country with EPA specified fuels. Additionally, there are serious and real concerns that it will not be possible to consistently maintain an ample supply of a 15 ppm sulfur cap product to the market place while significantly higher sulfur products are being shipped in the same fuel distribution and delivery system. The recently published study by Charles River Associates (CRA)12 concurs with this view and estimates the magnitude of the market impacts that would stem from implementation of the proposed EPA rule which calls for sulfur at 15ppm, but does not carry with it the aromatics and cetane specifications proposed by TNRCC. (See Appendix VIII)

A harmonization between state and federal fuel specifications is needed in order to have a reliable supply of affordable fuels available to the driving public. The TNRCC has not assessed whether or not the 15 ppm sulfur cap LED product can actually be delivered to a retail station while still maintaining the sulfur integrity of the product from refinery tanks, through pipeline shipments to remote distribution terminals, through transfers to transport trucks to retail underground storage, and finally to the consumer. It may be likely that new dedicated fuel distribution systems or system components, such as new tank terminals, will be needed to deliver low sulfur Texas fuels to the market place. The TNRCC should seek input from refiners, pipeline carriers, and fuel distributors on these critical issues.


We have several concerns with the inclusion of attainment areas in this rule. The Coalition believes that requiring a special fuel, made nowhere else in the nation, for areas of Texas that are in attainment with all air quality standards has no technical, regulatory, or legal basis. Clearly the fuel measures that the Coalition recommends including in this SIP will cover all areas of Texas and will provide ample NOx and VOC reductions to maintain and improve air quality in attainment area.

2.3.7 The Proposed Texas LED is not Legally Defensible

The BCCA believes that the proposed Texas LED rule has a number of legal deficiencies that will ultimately result in protracted litigation and a delay in the delivery of cleaner fuels to Texas. Our comments here are again similar to those outlined in our comments on the LSG proposal in Section 2.2.7.

2.3.8 Other Diesel Issues

i) Mid-Course Correction

12 An Assessment of the Potential Impacts of Proposed Environmental Regulations on U.S. Refinery Supply of Diesel Fuel,prepared for the American Petroleum Institute by Charles Rivers Associates, August 2000.

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TNRCC had indicated that it would rerun on-road modeling scenarios using Mobile6 for the diesel proposals when that data is available. As for the mid course correction, as it applies to this specific rule, we have some concern. Specifically, for fuels issues, because our investments and construction plans carry such long lead times (typically 4 years), we need certainty more than anything. We need to know that a rule finalized in December 2000 will not change at mid-course correction. We ask that TNRCC take this into account when considering mid-course SIP corrections in the fuels arena and that we be consulted in that process.

ii) Waivers

The commission is concurrently submitting, as part of the SIP and with this proposed rulemaking, a waiver request in accordance with the 42 USC, §7545(c)(4)(C), to implement this proposed Texas LED rule which is more stringent than the federal diesel rules. The BCCA opposes this waiver and supports the adopting of federal diesel rules for Texas.

iii) Alternative Diesel Formulations

TNRCC should remove the aromatic and cetane specifications associated with the proposed Texas LED rule. These specifications are much less relevant when the new federal ultra-low sulfur diesel enters the market in 2006 followed by the low emission heavy-duty diesel engines in 2007. Previous analysis by EPA as part of the proposed federal ultra-low sulfur diesel rule indicates that the correlations between fuel properties [such as aromatics and cetane] and emissions are rather small. We encourage TNRCC adopting the proposed EPA diesel formulation that does not contain aromatic and cetane specifications.

iv) Small and Micro-Business Impacts

The commission does not anticipate fiscal implications, which have an adverse fiscal impact on any small business or micro-business as a result of administration or enforcement of the proposed new sections. We disagree. Any retailers in boundary areas could be individually and significantly impacted by the unique nature of the fuels proposal. Impacts will also be felt by distribution facilities that serve areas across boundaries and refineries that make product for use inside and outside of the covered areas. These competitive pressures could be individually significant, so much so as to seriously impact the viability of future operations.

v) Emission Reductions

We believe that a serious unanswered question remains relating to emissions accounting. It is how to account for programs that are implemented, but not at maturity during the ozone attainment year in question. This is such a program. Maturity will not occur until the diesel

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engine fleet has turned over and vehicles with exhaust treatment systems that can efficiently make use of the low sulfur diesel we supply. TNRCC is currently modeling the effectiveness of diesel programs in 2007. We estimate that 3 years later, in 2010, the proposed EPA ultra-low sulfur diesel regulations will achieve an additional 20 tpd NOx reduction, and it maturity, it will achieve almost 90 tpd NOx reduction credit. TNRCC should work with EPA and all the other areas in this predicament to develop a method for crediting these prospective reductions

vi) Diesel Additives

TNRCC has proposed control measures including identified and unidentified gasoline and diesel fuel additives elsewhere in the SIP. For the most part, these proposed additives are in the process of being evaluated and performance under actual conditions of use is still being quantified. For example, TNRCC has implied that additives may be approved for use in compliance with the Texas Low Emission Diesel (LED) program. We also understand that additive manufacturers are discussing with TNRCC applications in the LS gasoline program. While this class of potential emission reduction additives is still being evaluated, it is premature to include them as a mandatory fuel control measure. Rather, they more properly belong to that group of potential emission reduction measures for use in a market based incentives program. A market based incentive program for NOx and VOC emission reductions provides for the development, validation, certification (if necessary) and introduction of fuel additives based on the demand for, and price of, such additive. Market based incentive programs can achieve emission in a manner that is superior to, and more cost effective than, mandatory measures. TNRCC should include this class of emission reduction measure in a market based incentive program.

2.4 Proposed Texas Diesel Emulsions Fuel (DEF) rule

The TNRCC proposed rule for DEF requires that a unique and never before used grade of diesel fuel be offered at the retail level in the Houston-Galveston Area (HGA) for on-road and off-road use beginning May 1, 2004. The diesel component of the DEF must also meet the proposed specification for Low Emission Diesel Fuel (LED) as proposed elsewhere in this SIP proposal. We believe that this rule will have a negative effects on the market for diesel fuel in the HGA and is not in the best interest of HGA consumers. We believe that the proposed DEF rule should be withdrawn as a mandatory measure and its use encouraged through a market based incentives program. Our reasons are outlined below and detailed on the following pages.

(1) Diesel Emulsion Fuel Is Not Commercially Available

(2) DEF Technical Requirements are not Attainable

(3) The Marketplace is Unlikely to Accept this Untested Fuel

(4) Installation of New Equipment will be Costly

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(5) Enforcement, Quality Control and Liability are not Addressed

(6) Can TNRCC Mandate Retailers to Offer this Fuel?

2.4.1 Diesel Emulsion Fuel Is Not Commercially Available

Diesel emulsion fuel (DEF) is an emergent fuel technology 13 not currently mandated anywhere in the U.S. and not being used, other than in small pilot programs, anywhere else in the world. TNRCC has mandated this experimental technology without the benefit of adequate development and testing. Preliminary lab results from a single additive supplier do not constitute research and development activities that are typically a part of the development process for environmental rules, let alone to develop a commercial market. While developmental data may indicate that DEF might have future applications, BCCA believes that inclusion of a DEF in the HGA SIP as a mandatory measure is premature.

We are aware that one company has done a some work in developing a diesel emulsion additive and that they are currently involved with the City of Houston as it initiates a testing program for Fall, 2000 in 9-10 diesel vehicles. This is how such programs should start. There is no reason however to mandate public use prior to the start of pilot tests. While there may be other diesel emulsion additives available by 2004, since there is presently only one approved diesel emulsion additive, the TNRCC is effectively mandating public use of one supplier's product.

TNRCC has not considered the long-term stability of water emulsions with diesel given the many applications and potential for long term storage of diesel products, particularly in non-road applications. Such products must be stable at the time of manufacture, and remain so after long periods of time, in widely cyclical ambient temperatures, up until the time of delivery to the engine. Action by the TNRCC to mandate emulsions, prior to demonstrating long term stability and proven environmental value, is premature.

Additionally, the TNRCC has not taken into account the disruptions and handling impacts of broken emulsions in the market place. Enforcement mechanisms and environmental handling procedures for excess tank water bottoms have not been identified by TNRCC. Likewise, standards requiring the use of emulsion additives have not been proposed, presumably assuming that emulsion manufacturers will utilize the additives needed to assure long term storage capabilities. Absent such standards, bulk purchasers of such emulsions are exposed to potentially substandard products that will lead to customer and market place disruptions. TNRCC must consider these outcomes as it projects environmental benefits from DEF.

2.4.2 DEF Technical Requirements are not Attainable

The only data TNRCC has supplied indicates that the greatest amount of NOx reduction (5%) achievable by a DEF, as compared to its baseline diesel fuel, is well below that being proposed 13 25 Texas Register 8197, Diesel Emulsion Fuel

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NOx reduction requirements for both on-road (15%) and off-road (20%) engines under the rule. On this basis alone, the proposed rule appears to be technically infeasible. Additionally, the requirement that there be no other pollutant increases in using DEF may not be attainable. From the limited data available, it appears that the NOx reduction mechanism from the technology is directly due to lowering flame temperature in the combustion reaction. Data from direct injection of water in heavy-duty diesel engines indicates that lowering combustion temperature to reduce NOx emissions will increase other pollutants such as hydrocarbons. Considering these observations, it would appear that TNRCC is establishing a standard that is not technically achievable.

Laboratory experiments and even controlled fleet tests, do not in any way simulate the market place impacts of new fuel formulations. When the public is part of the test other variables must be considered such as mis-fueling, fuel mixing and performance in a wide range of vehicles. TNRCC should address these issues in assessing the net NOx reduction benefit of this proposed as part of the final rulemaking package.

Finally, vehicle performance and warranty is another subject that TNRCC has not considered. Mandating the use of an emergent fuel technology, prior to rigorous testing with Original Equipment Manufacturers, could result in voiding of engine and equipment warranties. TNRCC must consider how to handle any vehicle and equipment repairs that result from the use of this emergent fuel technology as the state of California did when CARB diesel caused widespread fuel pump failures in that state.

2.4.3 The Marketplace is Unlikely to Accept this Untested Fuel

BCCA is concerned about market acceptance of DEF. The proposed rule will affect diesel vehicle and equipment owners including the general public, construction company equipment, interstate trucking fleets, and rural farm equipment in the HGA. While it may be too onerous for individual consumers to refuel outside the area, long haul trucking fleets, concerned with fuel economy and engine manufacturer warranties and guarantees, will probably elect to bypass this unproven fuel if at all possible. BCCA strongly urges the TNRCC to seek input from the truck transport community as well as diesel engine manufacturers before attempting to promulgate any rule requiring the use of this fuel.

As for acceptance by diesel fuel retailers, we believe the net effect of this rule will be to reduce retail diesel fuel availability in the HGA area. If all retailers who sell more than 25,000 gallons per month of diesel are required to install extra tanks for this product (and possibly blending facilities on site) as implied by the rule, we believe that many retailers will simply exit the market rather than make those investments. Diesel is typically the slowest moving retail fuels and the lowest margin clean product for both refiners and marketers. TNRCC should seek input from marketers and distributors on this issue before adopting a rule of this type.

2.4.4 Installation of New Equipment will be Costly

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Not withstanding the other issues associated with supplying a LED fuel to the HGA area, there are costs associated with marketing and distributing DEF that TNRCC has not considered. Capital will be required to install tankage and equipment at terminals supplying the HGA area with both LED and DEF. If the water component of the emulsion is 15-20 volume percent, the tankage required for the terminal upgrade to DEF would be a major cost. Additionally, piping, loading arms and computer controls would likely be required in addition to the blending equipment that appears to be critical to the successful preparation of this fuel. Terminal operators could be faced with major permitting and real estate obstacles to meet these capital requirements. They would be entering into the permit process at the same time refiners are attempting to upgrade their facilities for EPA's Tier 2 Low Sulfur Gasoline Regulations and the EPA's Ultra Low Sulfur Diesel Regulations (both federal actions). While the EPA has promised permit streamlining for the projects aimed at these two regulations, we believe that significant backlogs will result. Also there would be at least two tanks required at each terminal supplying the diesel emulsion fuel; one in service for water and one as a diesel emulsion rack tank. The diesel throughput at a terminal would dictate the size for both. In many cases, there may not be enough physical space to construct sufficient new tankage.

2.4.5 Enforcement, Quality Control, and Liability Issues are not Addressed

The proposed rule has no language to address enforcement, quality control, blender registration and operation, product labeling and liability. The TNRCC must address such issues as part of every rulemaking process. Every party involved, from the refiner to the consumer, must understand what the agency's intentions are and how to comply with the requirements. The proposed rule does not address how distributors and retailers, who do not plan to market DEF, can continue to sell diesel to classes of customers not affected by this rule. Additionally, retailers will not be able to determine vehicle gross weights or equipment horsepower ratings for self-service customers. We ask that TNRCC provide guidance in any final rulemaking package, on how retailers must regulate fuel dispensing to avoid mis-fueling and guidance on how TNRCC inspectors will enforce mis-fueling with the fuel consuming public.

2.4.6 Can TNRCC Mandate Retailers Offer this Fuel?

BCCA asks TNRCC to provide their legal basis for requiring that retailers offer this fuel. It would appear questionable that simply because a retailer sells 25,000 gallons per month of diesel fuel, that TNRCC can mandate that he purchase and install equipment and offer DEF for sale. This would seem more reasonable that TNRCC can require that if DEF is offered for sale, it must meet state and federal specifications. We believe the choice of fuel offerings should be up to the retailer and cannot be mandated by TNRCC.

2.4.7 Alternatives to the Proposed Texas Diesel Emulsion Fuel Mandate

While the proposed Texas DEF is still being evaluated, it is premature to include it as a mandatory fuel control measure in the SIP. Rather, DEF more properly belong to that group of

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potential emission reduction measures for use in a market based incentives program. A market based incentive program for NOx and VOC emission reductions provides for the development, validation, certification (if necessary) and introduction of fuel additives based on the demand for, and price of, such additive. Market based incentive programs can achieve emission in a manner that is superior to, and more cost effective than, mandatory measures. TNRCC should include DEF in a market based incentive program.

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Section 3: On-Road and Non-Road Mobile Source Control Strategies

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3.0 On-Road and Non-Road Control Strategies

3.1. On-Road Control Strategies

On-road mobile source emissions accounted for approximately 32% of the total NOx emissions in 1993. Photochemical modeling (see Section 11) shows that NOx reductions from ground level dispersed sources are approximately three times as effective in reducing ozone as NOx reductions from elevated point sources. Clearly, control of these sources will form a crucial part of any NOx control strategy to bring the Houston/Galveston/Brazoria area into attainment of the ozone standard. However, certain on-road mobile source control programs have been difficult to implement, because they affect citizens so directly, and, if they are not crafted carefully, have the ability to disrupt lifestyles. Citizen acceptance is key to the success of these programs, and the BCCA has played a leadership role in public education and advocacy about the necessity of obtaining reductions from all source categories. As a general principle, the BCCA encourages the use of technologically-based programs whenever possible over use-restrictive strategies.

TNRCC has calculated credit from some federal on-road mobile source control programs, and has proposed some control strategies that would apply specifically to the eight-county ozone nonattainment area to reduce emissions from this sector.

3.1.1 Speed Limit Reduction

The TNRCC has proposed a reduction in speed limits from the current speed limit (if it is greater than 55 miles per hour), to 55 miles per hour on all roadways. The BCCA recognizes the relationship between VOC and NOx emissions and vehicle speeds, and that speed limit reductions in certain areas may indeed reduce NOx emissions. However, the BCCA believes this rule should not be applied to the entire eight-county nonattainment area without a technical demonstration that it will result in emission reductions on individual roadways. The BCCA supports a speed limit reduction for those roadways where it has been demonstrated that emission reductions could be expected to occur due to reduced speeds. The BCCA suggests that TNRCC work closely with HGAC to evaluate roadways with current speed limits over 55 miles per hour, and select roads for a lower speed limit due to this analysis.

3.1.2 Federal On-Road Vehicle Emissions Standards

Vehicle emission standards over the years have focused on reducing VOC emissions and have been very successful. Emissions from passenger vehicles sold today are 95 % lower than their 1968 counterparts. Total on-road VOC emissions in the Houston-Galveston area have declined significantly over the years despite a significant increase in vehicle miles traveled.

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Control technologies to reduce emissions of NOx have not emerged as quickly as VOC controls and, as a result, NOx emissions have steadily increased as vehicle miles traveled have increased. To counteract this trend of increasing on-road NOx emissions, EPA has finalized new on-road vehicle engine standards that will result in significant short and longer-term emission reduction steps are identified for all classes of passenger vehicles.

For example, the larger and heavier vehicles, such as the popular selling large trucks and Sport Utility Vehicles, a 1.1 gram/mile standard (at 50,000 miles driven) was established for model-year 1994. This standard is expected to drop to 0.07 grams/mile with Tier 2 emission standards in 2007, essentially too late to make a meaningful contribution towards ozone attainment in the Houston-Galveston area. These larger, higher emitting vehicles represent over 50% of new on-road passenger vehicles sold in the United States today and represent an increasing contribution to on-road NOx vehicle emissions. Additionally, emerging information suggests that current on-road inventory projections for 2007 likely under-predict the vehicle miles traveled (VMT) fraction of these heavier on-road vehicles. Correction of this under-prediction will further increase the total emissions inventory from these vehicles.

Meaningful progress in reducing on-road NOx emissions from passenger vehicles will be made when the more stringent emission standards (Tier 2) for the heavier on-road trucks and Sport Utility Vehicles are in place and make significant market penetration (e.g., vehicle turnover). Realistically, meaningful fleet turnover will not occur until beyond the 2015 time frame, well past the 2007 attainment deadline for the Houston-Galveston area.

For heavy duty on-road diesel vehicles, new standards will go into effect for model-year 2002 engines that result in roughly a 50% NOx reduction from today's engines. Further regulation of highway diesel vehicles is not expected before 2007. Currently, EPA projects on-road heavy duty diesel engines to contribute about 15% of the mobile source NOx inventory nation-wide in 2007.

The BCCA supports these new emission standards and encourages their early introduction into the Texas market. However, the BCCA understands that it may not be possible for auto manufacturers to introduce these new vehicles across the nation on an accelerated schedule. In 1997, the EPA reached a voluntary agreement with the major auto manufacturers to introduce national low-emissions vehicles into the Ozone Transport Region before they were introduced into the rest of the country, specifically to reduce ozone levels in the Northeast. The BCCA suggests that TNRCC and EPA work with automakers and other interested parties on a voluntary agreement to introduce Tier II vehicles into the Texas market prior to national introduction.

3.1.3 Vehicle Inspection and Maintenance

TNRCC’s analysis of on-road vehicle emissions indicates that, absent more stringent vehicle technology standards, a vehicle Maintenance and Inspection (I/M) Program achieves a greater level of emission reduction than any other mobile source control evaluated. TNRCC has proposed a new I/M test for the eight-county area, which requires Accelerated Simulation Mode

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or equivalent testing as well as On-Board Diagnostic testing. The TNRCC has proposed an implementation plan that allows for phased-in implementation of the I/M test for central and outlying counties within the non-attainment region. The BCCA supports the program as proposed for the region, and further supports the phased-in implementation period. The BCCA believes that careful design and implementation of the program will be essential to its success in the region, and encourages the TNRCC to design flexibility into the final program for citizens and test facilities.

3.1.4 Vehicle Idling Standards

The TNRCC has proposed a rule which limits idling time for all vehicles over 14,000 pounds to five consecutive minutes, and applies from April 1 to October 31 each year. The BCCA recognizes that unnecessary idling contributes to advanced engine wear, increased fuel consumption and the emission of additional ozone precursors and other pollutants. However, it is not possible for all fleets to curtail idling during all applications. For example, METRO has voluntarily reduced idling in the early morning start-up of their buses. However, under some circumstances, METRO must retain the flexibility to idle their buses for longer than five minutes to provide air conditioning and air circulation to passengers. Therefore, the BCCA supports a modification to the rule which would allow fleet owners and operators the flexibility to achieve equivalent or greater reductions from an emission reduction plan in lieu of compliance with the rule. BCCA believes that this would provide for equivalent emission reductions while allowing fleet owners appropriate operational flexibility.

3.1.5 Voluntary Mobile Source Emissions Reduction Program (VMEP)

Over the past year, the Houston-Galveston Area Council and a broad stakeholder group, of which the BCCA is a member, has worked diligently to identify numerous programs to include in a voluntary mobile source emissions reduction program (VMEP). The BCCA believes that one of the primary purposes of a VMEP program is to encourage the development of new or emerging technologies or control strategies, and to develop a methodology to account for them in the SIP, even if they are not yet fully quantifiable or enforceable. Two new technologies in particular, a diesel emulsion additive and a NOx catalyst retrofit for diesel engines, were suggested as VMEPs, and appeared to be an especially appropriate application of the program. Unfortunately, as the TNRCC worked to identify mandatory measures for inclusion in the SIP, these technologies and others were mandated into the SIP.

As a consequence, HGAC has not been able to identify enough other measures that will make up the entire 24 tons per day of reductions that are allocated to VMEPs in the SIP. The BCCA believes that the emulsion and retrofit programs should be removed as mandatory measures from the SIP, and placed back into the VMEP category. Furthermore, the VMEP program should be closely tied to a voluntary incentive program (See Section 9 on Market-Based Incentives). This would allow businesses and government fleets the ability to purchase, test, and prove the technical and commercial feasibility of these new technologies. If at some future time they are well-proven, they may be moved out of the VMEP program and mandated as SIP controls.

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3.1.6 Transportation Control Measures

The HGAC has worked diligently with the TNRCC and other stakeholders to identify transportation control measures for the SIP. The BCCA supports these transportation control measures, and encourages the identification of others, especially in time for the mid-course correction.

3.1.7 Motor Fuel Additives

TNRCC has proposed control measures including identified and unidentified gasoline and diesel fuel additives elsewhere in the SIP. For the most part, these proposed additives are in the process of being evaluated and performance under actual conditions of use is still being quantified. For example, TNRCC has implied that additives may be approved for use in compliance with the Texas Low Emission Diesel (LED) program. We also understand that additive manufacturers are discussing with TNRCC applications in the LS gasoline program. While this class of potential emission reduction additives is still being evaluated, it is premature to include them as a mandatory fuel control measure. Rather, they more properly belong to that group of potential emission reduction measures for use in a market based incentives program. A market based incentive program for NOx and VOC emission reductions provides for the development, validation, certification (if necessary) and introduction of fuel additives based on the demand for, and price of, such additive. Market based incentive programs can achieve emission in a manner that is superior to, and more cost effective than, mandatory measures. TNRCC should include this class of emission reduction measure in a market based incentive program.

3.2 Non-Road Mobile Source Control Strategies

3.2.1 Construction Hour Shift

(a) Introduction

The TNRCC proposes to impose a prohibition14 in the eight-county area against operation of non-road diesel construction equipment of 50 horsepower or more between 6:00am and 12:00am, effective April 3, 2005,15 during the months when daylight savings time is observed.

The inventory of equipment affected is approximately 30,000 units. The majority of them, approximately 17,000 units, are used in the construction industry; most of the balance is in use by the Port of Houston and in related dockside activities, and in industrial facilities. The inventory of affected equipment in the region was developed by the construction industry and

14 Proposed 30 Texas Administrative Code (“TAC”) Section 114.482

15 Proposed 30 TAC Section 114.489.

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the Port of Houston working in cooperation with the TNRCC.

(b) Specific Comments

The TNRCC lacks statutory authority to impose the workday shift on all the equipment covered by the rule. The residual air quality benefit does not pass the practical and economically feasible test that TNRCC rules must meet.

An agency such as TNRCC must have legislative authority for its regulatory actions.16 The TNRCC cites as statutory authority for the construction workday shift in the HGA proposal, the Texas Water Code section 5.103 (authority to adopt rules necessary to carry out its purposes and duties under the Water Code and other laws of the state), the Health and Safety Code sections 382.011 (authority to control the state’s air17), 382.012 (authority to develop a general, comprehensive plan for the control of the state’s air18), 382.017 (authority to adopt rules consistent with the policy and purposes of the TCAA), 382.019 (authority to adopt rules to control and reduce emissions from engines used to propel land vehicles) and 382.039 (authority to develop and implement transportation control programs and other measures necessary to demonstrate attainment and protect the public from exposure to hazardous air contaminants from motor vehicles).

There is no specific statutory authority for imposition of the workday shift. The only statutory provision cited by TNRCC that deals with emissions from vehicles section 382.019 which is entitled, Methods Used to Control and Reduce Emissions From Land Vehicles. Subsection (a) reads as follows:

“(a) The commission may by rule provide requirements concerning the particular method to be used to control and reduce emissions from engines used to propel land vehicles.” (Emphasis added)

Subsection (a) is not authority to impose the workday shift because it is limited by its terms to (1) controlling and reducing emissions (2) from engines used to propel land vehicles. A prohibition against operation of diesel engines in the morning hours affects the timing of emissions from engines, and it may in a general sense control emissions, but such a prohibition

16 Ronald L. Beal, Texas Administrative Practice and Procedure, Section 1.2.3 (1997)

17 However, the Commission shall seek to accomplish the purposes of the Texas Clean Air Act through the control of air contaminants by all practical and economically feasible methods. Section 382.011(b). (emphasis supplied)

18.This broadly stated authority is circumscribed with in the same section-except as provided by other enumerated sections, one of which is Section 382.019, the Commission may not by rule specify a particular method used to control or abate air pollution. See Section 382.017(f).

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does not specifically control and reduce them. The prohibition neither imposes limits upon emissions nor does it reduce them. ‘Reduce’ is the word the Legislature used in Section 381.019(a). Unless that word is written out of the sentence, actions taken pursuant to Section 382.019 must ‘reduce’ emissions. Notwithstanding the rationale for the workday shift (theoretical reduction of ozone by shifting NOX emissions), the statutory authority in section 392.019 is to reduce ‘emissions’.

The same emissions of NOx (including particulates and other materials produced by operation of diesel engines) are emitted either before or after 1200 noon; moving them to a different part of the day does not limit or reduce them. The language used in Section 382.019(a) is “control and reduce”. This phrase is conjunctive; it does not say control or reduce. Both components must be present to be an exercise of the authority of Section 382.019(a).

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The TNRCC can only regulate emissions from engines that propel land vehicles. The actions taken by TNRCC pursuant to Section 382.019(a) can lawfully only apply to specific engines-“those used to propel land vehicles.” This limitation on the power of the TNRCC is unambiguous. If an engine is not used to propel land vehicles, the TNRCC has no authority to regulate with respect to that engine. However, the proposed workday shift covers a broader universe of engines.

Some units of equipment covered cannot move at all without being towed or hauled on a trailer. These include crushing and processing equipment, signal boards, cement and mortar mixers (those not truck mounted), and others. Still other items of equipment can, in the broad sense, move as a result of their engine being operated but such movement is incidental to the device’s function. Examples of these devices include:

Plate tampers, compactors and rammers Pavers Trenchers Boring rigs Concrete saws (movement regulates the speed of the blade through the material being

sawed) Surfacing equipment Excavators Certain cranes (which must be repositioned)

The devices just listed do not make use of an engine and transmission to move or propel themselves in any normal sense and are not within the language of Section 382.019(a) and the first list is certainly not. This point is reinforced by the definition of the term, motor vehicle, found in the Texas Transportation Act19:

Motor vehicle-Any self propelled device powered by an internal combustion engine and designed to operate with four or more wheels in contact with the ground, in or by which a person or property is or may be transported, and is required to be registered under Texas Transportation Code (TTC) section 502.002, excluding vehicles registered under TTC, Section 502.006(c).

The equipment discussed above is not designed to move people or property as its primary function and is not required to be registered.

The conclusion drawn is that any attempted regulation by TNRCC of equipment the movement of which is an incidental result of its engine is outside the authority of TNRCC. Adoption of such a regulation would exceed the authority of TNRCC.

The additional authorities (over and above HSC Section 392.019) cited by TNRCC do not help establish power to regulate beyond the power to control and limit emissions from engines that propel land-based vehicles. The additional authorities are general

19 Section 114.500(2)

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provisions that cannot overcome the limits of section 382.019. Specific authority to regulate may not be embellished through the expansion of general powers. Implied power is only permissible when it is first concluded that the legislature obviously intended the agency to have it.20 The language used in Section 392.019 is measured and grants the ability to regulate in certain ways (control and limit emissions) as to certain devices (engines) used for certain purposes (propelling land vehicles). Little is left to the imagination and nothing else is “obviously” inferred.

The critical point is that TNRCC may not regulate engines that do not propel land vehicles. Once those devices that are not within the TNRCC’s authority are removed from the inventory, the NOx emissions equivalent is reduced, and the modeled benefit of ozone reduction becomes minimal.

The remaining ozone reduction benefit is neither a practical nor economically feasible one.

The modeled benefit of the proposed workday shift is, according to the TNRCC, 8 tons per day of NOX shifted to a later time and isthe equivalent of a 6.7 tons per day of NOX reduced for the entire universe of the affected equipment. In terms of ozone concentration, this would theoretically produce a reduction of about one (1) part per billion (ppb) or less. However, if those items that TNRCC may not regulate (see discussion above) are removed, what is the benefit? Is the theoretical ozone reduction now ½ ppb? Is it 1/10 ppb? Whether the benefit is one, ½ or1/10 ppb of ozone reduction in modeled benefit, compared with the costs of the workday shift which is estimated at 450 million dollars annually (discussed below) neither passes the “practical and economically feasible” test required by Section 382.011(b):

“The commission shall seek to accomplish the purposes of this chapter through the control of air contaminants by all practical and economically feasible methods.”

An estimate of the annual cost of the rule has been prepared by a knowledgeable member of the construction industry. The estimate is derived from the number of employees in a particular company, the number of hours worked per year, the number of overtime hours worked per year, annual base wages, the total annual payroll and takes into account two considerations specifically associated with the workday shift. Those two considerations are (1) a loss in efficiency as a result of the shift and (2) an average increase by 10% of the payroll. It is expected that, especially in a job market represented by very low unemployment, that wages paid to construction workers and onsite management will rise either in the form of a recognized premium pay or escalation as a result of the labor market. A payroll tax increment follows the payroll increase.

An incremental cost to the specific company was calculated and extrapolated to the construction industry in the eight county area, using the equipment inventory developed

20 Beal, Section 1.2.3 at page 1-14

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by the HCIC which has been accepted by the TNRCC as appropriate for use in SIP development activities. The extrapolated cost of the workday shift rule is $450 million dollars annually, based on implementation of the shift during daylight savings time.

A shift in the construction workday to commence at 12:00 noon or later will have adverse health and safety implications.

Commencing construction work at the conventional time (early in the day, e.g., 6:00am to 7:00am) minimizes the likelihood that, during the hot weather period in Texas, workers will not be exposed to the highest risk of heat stroke and heat exhaustion. The hot weather season roughly coincides with the high ozone season. The balance of the population is the subject of frequent warnings from the media and government to avoid exposure to the extreme heat of midday heat.

Construction work is challenging at best. It is occasionally desirable for work to be done, on a voluntary basis, under late day and evening conditions. However, doing so voluntarily and pursuant to a government mandate are different things. The adoption, as a matter of policy, of a rule that systematically exposes 458, 000 21 construction workers in this state to a risk that the balance of the population is encouraged to avoid is an unsupportable policy. It is an expression of preference for the health and safety of part of the population at the expense of the rest and inconsistent with the TNRCC’s mission to protect (all) public health and the environment. The workday shift will have a great and adverse quality of life impacts impact on

workers in the construction industry who are significantly minority.

There is reason to believe that the burdens of a shift in the workday would fall disproportionately on the minority community. See the discussion above for health and safety considerations. If, as evidence discussed therein suggests, the construction workforce is predominately minority, additional burdens like a disruption in family life will disproportionately affect the minority community. It is no answer to say that the term “disparate impact”, because of its origination and association with the Civil Rights

21 US Census Bureau, the Official Abstract TM Statistical Abstract of the United States: 1998, Sep. 30, 1998, Item 686. (Hereafter, Statistical Abstract). The same source identifies the entire nonfarm workforce as 8.602 million in Texas and the entire population as 19.439 million (item 34). On a national basis, for the same year (1997) Black and Hispanic workers were 22% of the nonsupervisory construction workforce (Item 672). There is anecdotal evidence that the construction workforce is predominately minority; primarily Hispanic in the Houston area. This is supported by training records of the Associated Builders and Contractors of Greater Houston which, in cooperation with area community colleges, operates an extensive craft training programming program, mostly in the evening. For the spring and fall, 1999 classes, Hispanic students made up 64% (739) and 62% (864), respectively. Black students were 5% and 6%, respectively for the same two semesters. To the extent the anecdotal evidence is borne out by the craft training enrollment, it is clear that the incremental risk of sun exposure and other hazards will fall heavily on a heavily minority workforce.

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Act, does not fit the discussion of the workday shift. The reality is that minority families will disproportionately feel the disruptive impacts of the workday shift.

The proposed rule and the rulemaking process is procedurally defective because TNRCC erroneously concluded that adoption of the workday shift does not a regulatory impact analysis (RIA). This conclusion is erroneous because the workday shift exceeds express requirements of state law, is not specifically required by federal law and is adopted solely under the general powers of the agency.

The workday shift exceeds specific requirements of state law for reasons stated in part 2.a., above. The workday shift is not a requirement of federal law because, as TNRCC acknowledges in the preamble (25 Tex. Reg. 8244) to the rule, the Federal Clean Air Act specifically defers to states in selection of measures to demonstrate attainment which is what the federal law does require. The workday shift is a measure that is the choice of the TNRCC and is in no sense a requirement of federal law.

There being no specific authority for the workday shift under state law, its only possible statutory basis is the TNRCC’s general powers. Since none of the exceptions apply, TNRCC is required to perform a RIA incident to the adoption of a major environmental rule (Section 2001.0225). The agency concedes that the workday shift is such a rule (25 Tex. Reg. 8244). Moreover, the TNRCC was required to incorporate a draft impact analysis into the notice of the proposed rule. The TNRCC devotes a single conclusory paragraph (25 Tex. Reg. 8243) to the potential impacts. This paragraph has limited cost figures that are attributed to the Texas Department of Transportation (TxDOT) and an unsupported estimate of an increment associated with rule. The paragraph does not substantively address the requirements of Section 2001.025(c). The proposed rulemaking is thus procedurally defective.

The rule cannot be the subject of SIP credit for NOx reduction because it is a dispersion technique that is contrary to CAA Section 123.

The rule depends, for its claimed benefit of ozone reduction, upon release of the NOX emissions at a time of day when atmospheric conditions operate to produce less ozone or alternatively, are less favorable for ozone formation. The benefit and the rule are inseparable from atmospheric conditions.

The rule is preempted by the CAA Section 209. The CAA section 209 reserves to the EPA imposition of “...any standard or other requirement relating to the control of emissions...” of new or used nonroad engines. The workday shift is such an “other requirement” which is not available to a state except under the limited circumstance where California adopts such a requirement which is not the case.

The BCCA strongly supports, as a substitute for the workday shift (and the accelerated Tier II/Tier III purchase rule) an incentive-based program that will produce more cost-effective NOX reductions.

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The cost of the workday shift to the construction industry is estimated to be $450 million dollars annually (see discussion above at I.B.1.c) compared with a claimed equivalent reduction of less than eight tons per day of equivalent NOX reduced. As a result the per ton cost of the workday shift will be astronomical and unreasonable compared to other mechanisms. The state of California has implemented an incentive program referred to as the Carl Moyer Program that makes funds available to public and private entities on a competitive basis for use in acquiring cleaner, advanced technology and implementing other measures as well on a voluntary basis. The upper limit on eligibility for funding for the Carl Moyer program is $12,000 per ton with dramatically lesser actual costs per ton experienced.

Discussions with legislative leaders in Texas have indicated significant interest in such a program. The BCCA urges the TNRCC to substitute an incentive-based program for the workday shift and the accelerated engine purchase measures through the mechanism of an enforceable commitment to implement such a program.

3.2.2 Accelerated Turnover of Tier II/Tier III Equipment

(a) The TNRCC is pre-empted by the Federal Clean Air Act from imposing a requirement for accelerated purchase of Tier II and Tier III diesel engines.

The Federal Clean Air Act Section 209(e)(1) and (2) in effect prohibits states from imposing standards and other requirements relating to the control of emissions on vehicles and engines. The prohibition applies to new engines used in construction equipment that are smaller than 175 horsepower (and those in locomotives) and to used engines as well. A limited exception allows the State of California to adopt other standards and requirements (with other states having the ability to follow California) but California has not done so. See Engine Manufacturers Association vs. U.S.E.P.A., 88 F.3d 1075. The EPA has promulgated standards for the advanced engines including in particular, schedules by which they will be required. For Tier III engines, the applicable time frame is 2006 through 2008.

The proposed TNRCC rule imposes a duty on owners and operators to have in place, engines that meet the Tier II/III standards on a schedule that is earlier that the federal standard. This imposes, effectively, a standard on those engines for the period in which the advanced engine would not be required under federal law and the accelerated schedule is clearly an “other requirement”. Therefore, the BCCA opposes this rule, and supports the formation of an emissions incentive reduction program, as described in Section 3.2.1 above, to achieve equal or greater reductions in this source category. The BCCA also urges EPA to accelerate the penetration of new engines into the Texas market.

3.2.3 Airport Ground Support Equipment

The BCCA supports the consensus agreement that has been reached on airport ground support equipment by Continental Airlines, the City of Houston, and the TNRCC. This

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agreement provides for significant emission reductions by the airline, and the reductions contributed by the City of Houston at their airport facilities allows Continental to retain important operational flexibility. The BCCA particularly applauds the leadership shown by the City of Houston in negotiating this agreement, and supports additional agreements at other City-owned airports. Furthermore, the BCCA encourages the TNRCC and EPA to use this agreement as a model of providing for significant emission reductions while allowing businesses needed flexibility.

3.2.4 California Spark Ignition Engine Standards

The TNRCC has proposed a new rule to require that all affected large spark ignition engines are certified to California Large Spark Ignition Standards. The BCCA supports this rule, and supports the listed exemptions for smaller agricultural and construction equipment, recreational equipment, stationary engines, marine vessels and equipment on tracks. The BCCA believes that it is appropriate that this rule be effective statewide to maximize its effectiveness.

3.2.5 NOx Reduction Systems

The BCCA supports the principle that non-road mobile source engines should contribute a significant share of emission reductions to the total needed to bring the Houston/Galveston region into attainment of the ozone standard. Some of the items listed in this rule show promise as effective technologies to reduce non-road engine emissions. However, the BCCA believes that a well-crafted voluntary mobile emission reduction program (VMEP) in conjunction with a market-based incentive program, could provide equal or greater emission reductions at a lower cost and with minimal disruption to the construction industry. The BCCA recognizes that despite an established track record of success in California, EPA may be reluctant to approve voluntary or incentive-based programs. Therefore, the BCCA recommends that the TNRCC adopt as a contingency rule a mass-cap emission limit for the non-road mobile source sector. TNRCC could establish a date certain by which a certain amount of reductions would be certified through a voluntary program, and implement the contingency rule if it were not sufficient to achieve attainment.

3.2.6 Lawn Service Equipment Operating Restrictions

The BCCA believes that the Lawn Service Equipment Operating Restrictions rule has many of the same unintended economic and social consequences as the Construction Shift rule, and therefore opposes it. The BCCA is concerned that the impacts of this rule will fall disproportionately on small and historically disadvantaged business owners. Furthermore, the BCCA is concerned that the shift of this vigorous outdoor activity to the late afternoon and early evening hours presents a safety hazard to lawn service workers.

As a general principle, the BCCA encourages the use of technologically based rules and economic incentives rather than use-restrictive rules. Therefore, the BCCA recommends

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that this rule be replaced by programs to achieve equal or greater reductions from this sector. First, the TNRCC should aggressively work with the EPA to develop and implement the next generation of lower-emitting lawn service equipment, and press for its early introduction into the Texas market. Second, because the primary ozone reduction benefits of this rule occur due to VOC reductions, the TNRCC should consider implementing a California rule which requires the sale of only low-spillage and evaporation gasoline cans in the state. Finally, the TNRCC should develop a program which provides for voluntary emission reduction incentives. As part of this program, lawn service operators and citizens could receive a rebate for the incremental cost of electric or low-emissions lawn service equipment, in exchange for scrapping old equipment, thus accelerating the turnover of newer technology in the region.

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Section 4—Proposed Other Control Strategies

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4.0 Proposed Other Control Measures

4.1 Residential and Commercial Air Conditioner Catalyst System

Th TNRCC has proposed a rule which would require new residential and commercial air conditioner units to reduce ozone from ambient air that is drawn across their external heat exchanger. The BCCA notes that the TNRCC and EPA are engaged in monitoring and verification programs and in determining the correct protocol to account for reductions from this new technology. The BCCA believes that results to date show promise for the catalyst system, and that this verification process should continue. If the technology is proven to significantly reduce ambient ozone, the BCCA supports this control strategy.

Some air conditioner manufacturers have recently claimed that new, highly energy-efficient air conditioner models could reduce energy demand and therefore NOx emissions by an equivalent or greater amount than the catalyst system envisioned in the rule. The BCCA urges the TNRCC and the EPA to work with both the catalyst and air conditioner manufacturers, and to grant flexibility to both parties to achieve emission reductions.

Furthermore, should either of these two new technologies prove effective, the BCCA recommends that a voluntary retrofit or replacement program for residential and commercial air conditioners be included in an economic incentive program to encourage earlier penetration of these technologies into the eight-county region.

4.2 Energy Efficiencies

The TNRCC has included a program in the SIP to implement energy conservation measures for buildings to reduce electricity usage through use of better insulation, reflective roofing, and other criteria. Municipalities will be required to enact local ordinances to implement this strategy. The City of Houston has indicated that it will move quickly to meet and exceed these standards. The BCCA encourages other municipalities in the eight-county region to enact similar ordinances. The BCCA also encourages the EPA and the TNRCC to provide technical guidance to smaller municipalities to facilitate the adoption and implementation of these ordinances.

4.3 City of Houston, Harris County, and Houston-Galveston Area Council Initiatives

The City of Houston has moved aggressively to develop an emissions inventory, emission reduction target, demonstration projects and strategies to reduce ozone precursors across all city operations. These actions have placed the City in a national

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leadership role among cities with similar air pollution problems. Actions taken by the City can serve as a model for other municipalities and businesses within the region.

Harris County has also demonstrated a strong commitment to developing a balanced, scientifically based plan. The County has funded demonstration projects, worked with the Port and other stakeholders to develop improved emissions inventories for non-road and on-road mobile sources, and funded important scientific studies that improve the model. The County has also played a leadership role in developing a voluntary emissions incentive reduction plan, which the BCCA believes will be crucial to making significant emission reductions in the area while providing greater flexibility to individuals and businesses.

The Houston-Galveston Area Council has also worked diligently to ensuring that all possible local options have been considered, and has provided numerous forums for diverse stakeholders to work together to find a common understanding of the issues and solutions. The HGAC has also funded public education efforts, and studies to improve our understanding of SIP elements, particularly for on- and non-road mobile sources.

The BCCA has been pleased to work as partners with the City, County, and HGAC, and encourages the EPA and the TNRCC to facilitate and allow local decision-making about SIP strategies to the greatest extent possible.

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Section 5: Federally Pre-Empted Control Measures

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5.0 Federally Preempted Control Measures

5.1 Federal NOX Reductions should be Fully Incorporated

A dramatic NOX reduction in HGA is expected to result from emerging Environmental Protection Agency ("EPA") regulations affecting certain sources (e.g., on-road vehicle and low sulfur gasoline standards, on- and off-road diesel engine and low sulfur diesel standards). EPA-regulated sources account for about 40% of the NOX emissions in the region. These sources are federally preempted; that is, only EPA—not the State of Texas—can effectively regulate them. The statutory framework of the federal Clean Air Act allots responsibility for different categories of emission reductions to state and federal agencies. Under established case law in the D.C. Circuit, Congress intended the states' statutory obligations to be read in concert with EPA's statutory obligations, and adjusted when appropriate to balance state/federal responsibilities. TNRCC should incorporate an appropriate level of federal reductions into the Plan, to restore its balance and to address the Plan's undue reliance on state-regulated sources.

EPA has issued regulations for some federally preempted sources well after the applicable statutory deadlines. Examples are as follows:

Nonroad engines

– Statutory deadline: 11-15-92 (42 U.S.C. § 7547(a))

– Rule promulgation dates:

a. Small Land-Based Spark–Ignition Engines: 7-3-95 (60 Fed. Reg. 34581).

b. Large Land-Based Spark-Ignition Engines: proposed 2-8-99 (64 Fed. Reg. 6008); not yet finalized.

c. Land-Based Diesel Engines: 6-17-94 (59 Fed. Reg. 31306).

d. Commercial Diesel Marine Engines: 12-29-99 (64 Fed. Reg. 73300).

e. Recreational Marine Engines – (outboard engines and personal watercraft only): 10-4-96 (61 Fed. Reg. 52088).

f. Aircraft Engines: 5-8-97 (62 Fed. Reg. 25355).

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Locomotive engines

– Statutory deadline: 11-15-95 (42 U.S.C. § 7547(a))

– Rule promulgation: 4-15-98 (63 Fed. Reg. 18,978)

In addition, EPA has recently strengthened the rules governing on- and off-road vehicles and fuels. Examples include:

Low Sulfur Gasoline: 2-10-2000 (65 Fed. Reg. 6698).

Low Sulfur Diesel: 6-2-2000 (Proposed Rule) (65 Fed. Reg. 35430).

Tier II Motor Vehicles: 2-10-2000 (65 Fed. Reg. 6698).

Heavy-Duty Highway Vehicle Standards: signed on 7-31-2000 (not yet published in the Federal Register).

Non-road Tier II/Tier III Heavy-Duty Engine Standards: 10-23-98 (63 Fed. Reg. 56968).

The newly strengthened rules will contribute significantly to ozone attainment in HGA. However, the delays in effectively regulating federally preempted sources have prompted the TNRCC to propose technically and economically infeasible emission reductions from those sources in HGA that the state has authority to regulate, including point sources, to make up for the missing reductions. Additionally, these delays have forced the TNRCC to propose expensive regional fuels and significant "use restriction" regulations on the public and businesses in the terms of mandatory speed limit reductions, and a prohibition on the use of non-road heavy-duty diesel equipment and lawn service equipment in the morning hours.

Based on established legal precedent, TNRCC and EPA have inherent authority to implement the intent of the federal Clean Air Act by balancing federal and state reductions in the SIP approval process. HGA's situation warrants a flexible approach, due to both the uncertainties in acknowledging the role of NOX reductions, and EPA's delays in adequately controlling the federally preempted sources as required by the Act. TNRCC and EPA can ensure an equitable distribution of the compliance burdens necessary to achieve the mandated air quality improvement in HGA only by allowing the Plan to capture the anticipated emission reductions from federally preempted sources.

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Section 6--Proposed Cap and Trade Program

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6.0 Proposed Cap and Trade Program

6.0 The Cap-and-Trade Program should be Strengthened

The Proposal would establish a market-based cap-and-trade program for demonstrating compliance with the proposed point source NOX emission reductions required under the proposed HGA SIP. BCCA understands that the intended role of the cap-and-trade is to be a flexibility mechanism for achieving overall NOX reductions at the least cost. BCCA supports such a mechanism in the HGA SIP, but has significant concerns as to its implementation in the Proposal. BCCA's comments on the proposed cap-and-trade program are set forth below.

6.1 A Viable Cap-and-Trade Depends on Feasible Reduction Levels

In order for the proposed cap-and-trade to function, NOX reductions required by the HGA SIP must be set at technologically and economically feasible levels for each source category, both new and retrofit. BCCA believes that a cap-and-trade can add value only if the SIP imposes current California-level point source controls, the most stringent achieved in practice.

6.2 The Cap-and-Trade should Afford a Five-Year Phase-in Period The Proposal would establish a three-year implementation window. Initial allocations would be issued in 2002. The final, target allocations would be issued in 2005 and remain fixed thereafter. In other words, the necessary controls must be in place by year-end 2004 in order to meet the target allocations under the Proposal. This timeframe is neither practical nor feasible. The Proposal should be amended to incorporate a five-year phase-in period, beginning in 2002 and ending in 2007.

6.3 The Cap Allocation Methodology should be Strengthened

Allocation methodology is at the core of the cap-and-trade program. The Proposal contains a number of ambiguities and inequities that would threaten its viability. The following changes would clarify and streamline the administration of the process.

(a) The Baseline Activity Level Should be Derived from a 12-Month Average

The TNRCC has proposed the use of an entire 3-year average (1997–1999) to determine baseline activity level. This approach will not result in an accurate baseline in many cases. BCCA believes that a consecutive 12-month period approach will more accurately reflect activity levels, and as a result will dramatically reduce the number and complexity

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of petitions for case-by-case review.

(b) Cap Reductions Should be Weighted Toward the Target Year

The proposed rule includes an allocation methodology that reduces the cap by thirds from the initial allocation year to the target year. However, there is no reasoned justification for a straight-line reduction in allocations. Instead, reductions from the initial to the target year should be weighted toward the target year. This approach would more accurately reflect industry project schedules and resource requirements, and put less pressure on a new trading program early on in the process. BCCA recommends 10% reductions per year from 2003-2006, followed by the target allocation in 2007 and forward.

(c) Allowances should be Allocated for 30 Future Years, not Year-by-Year

The Proposal suggests that allowances would be re-allocated every year, rather than allocated for a stream of years. This approach would hinder a fluid market. The proposed rule should be revised to provide for Cap Accounts to be credited their 2002 through 2032 vintage allowances at program inception.

(d) The Additional Definitions "Account" and "NOX Cap Plant" should be Incorporated

The "source" threshold and the related mechanisms for program participation are ambiguous, and must be clarified. "Source" is used to suggest an overall site in the 10-ton applicability trigger, but the same term is used to suggest an emitting unit in the cap calculation provisions. The general term "source" cannot be used for these diverging goals. To eliminate ambiguity, the existing term "Account" (as defined in Section 101.1(1)) can be used in the applicability provision to define a covered location. An "account" would be subject to the cap-and-trade if it had ESAD sources with emitting capacity aggregating ten or more tons per year. However, BCCA believes that a new, unique definition is needed to delineate each aggregation of sources subject to cap compliance. The Proposal contemplates that one or more existing sources and accounts may be aggregated under a cap. This aggregation is a new concept. BCCA recommends that existing terminology be avoided, and a flexible new definition be established. BCCA suggests, "NOX Cap Plant" to clearly distinguish its purpose and effect. At the outset, each covered "account" would be a "NOX Cap Plant" unless and until the Executive Director approved an aggregation or division.

(e) Allocations Should be Fixed Despite Equipment Shutdowns or Changes

Many stakeholders anticipate complying with the SIP by shutting down existing combustion equipment, and substituting new, cleaner-burning fired sources. The Proposal suggests that allowances derived from baseline activity levels from 1997-1999

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will be allocated to a NOX Cap Account, that this target allocation will be permanent, and that this target allocation will not change, despite shutdowns, replacements or changes to the equipment whose baseline activity level and rates formed the basis for the target allocation. TNRCC should insert clarifying language in the final rule establishing this concept with more certainty.

(f) An Opt-in Mechanism Should be Incorporated for Non-ESAD Sources

Many stakeholders have sources not subject to ESAD rates under the SIP, for which surplus reductions might be successfully obtained. In order to provide an effective incentive to accomplish these reductions, an opt-in provision should be incorporated into the Proposal. Under such a provision, any source may be opted into the cap-and-trade, and its allowances allocated using the same methodology established for ESAD sources.

(g) Modified, as well as New, Sources should be Granted Allocations at Permitted Levels.

The Proposal provides for sources not operating, but newly authorized by permit applications or permits-by-rule, to receive allocations at their permitted or actual activity levels. BCCA supports this approach. However, the current language ignores newly-modified sources. These sources should receive the same treatment as new sources in the allocation process. TNRCC should revise the language to harmonize the treatment of new and modified sources.

(h) The Allocation Methodology should be Simplified

The allocation methodology language in proposed Section 101.353 is overly complicated and confusing. The methodology is based on a complete re-allocation in each of the initial four years, and is structured to revisit allocations for new sources several times. As noted above, the methodology should allow all allocations for 2002 through 2032 to be issued in a single action before program commencement.

6.4 Open-Market Credits should be Fully Incorporated

Any cap-and-trade program must preserve the investment in existing emission credits.

(a) ERCs should be Creditable to Allowances

BCCA supports the ability to convert all types of recognized emission credits to allowances. The Proposal would provide for the conversion of DERCs to allowances and allow allowance credit for DERCs. The Proposal would provide that allowances could be converted to ERCs, but would disallow ERCs to be converted or credited to allowances. This prohibition represents a departure from the established framework of emission credits, without a reasoned justification.

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(b) The 10% Assessment should be Dropped for Credit Use in the Cap-and-Trade

The existing DERC trading rules require that a 10% environmental contribution and 5% compliance margin be added to each trade. BCCA believes that these deductions no longer add value for NOX trading intended to meet a fixed area-wide cap. Accordingly, the percentage reductions should be removed for DERCs used in lieu of cap-and-trade allowances.

6.5 Daily and 30-Day Limits should be Dropped for Sources Participating in the Cap-and-Trade

BCCA objects to the retention of daily and monthly NOX limits for utility sources in addition to the annual cap. The flexibility afforded by a mass-based cap-and-trade is rendered meaningless if the underlying emission-rate rules are retained on individual companies. TNRCC should adhere to the cap-and-trade as the sole compliance mechanism for covered stationary sources, and abandon the mandatory application of individual rate-based system caps.

6.6 Plantwide Applicability Limits should be Incorporated

BCCA understands that new accounts and facility changes will be required to undergo traditional NSR in addition to cap-and-trade compliance. BCCA believes that the cap-and-trade program should integrate with NSR by incorporating a Plantwide Applicability Limit ("PAL") in lieu of netting for changes under the cap. Under the PAL concept, cap compliance will satisfy NNSR and PSD requirements with respect to any changes at the account affecting NOX emissions.

6.7 The True-Up Period should be Extended to April 1

The Proposal requires cap compliance by January 31 of the year following each compliance year. BCCA believes that one month is not sufficient time to calculate the past year's emissions, locate and contract for needed allowance trades, and have such trades registered with TNRCC. No environmental goal is served by advancing the true-up period. The true-up should be extended so that compliance is required by April 1 of the succeeding year, to conform to the annual Emission Inventory deadline.

6.8 Allowances Should be Divisible in Tenth Tons

The Proposal would require NOX allowances to be rounded to full tons up or down,

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whichever provides the holder or user less credit. This provision is arbitrary and unreasonable. NOX allowances in California's RECLAIM program are denominated in pounds, not tons. RECLAIM credits have traded as high as $80,000 per ton. A quarter-ton of such credits is worth up to $20,000. Taking that amount of value, solely in the interest of rounding, is completely arbitrary, unreasonable and lacks a reasoned justification. Whole-ton rounding is also inconsistent with the existing open-market rules, under which ERCs are traded in tenth-ton increments. Like ERCs, allowances should be tradable in tenth-tons.

6.9 Enhanced Monitoring Should Await the Target Year

The point source rule proposed parallel to the Proposal would require installation of all of the enhanced monitoring equipment specified in the SIP—such as CEMS, PEMS and totalizing flow meters—by December 31, 2001. There is no rational justification for advancing this new monitoring ahead of the substantive reductions needed for attainment. This new monitoring is presumably imposed to assure that the attainment demonstration emission levels are observed. The resource constraints that sources face in implementing retrofits will only be compounded if the new monitoring equipment is required early, and out of sequence. The new monitoring equipment should be installed by the year in which the target allocations begin under the cap-and-trade program ( i.e., 2007).

6.10 VOC Credits Should be Creditable Against NOX Allocations upon an Appropriate Demonstration

The Commission solicited comments in the Proposal "on how to address allowing certain VOC reductions which produce equal or better ozone results in lieu of NOX reductions for compliance with the cap." 25 Tex. Reg. at 8143. BCCA supports the inclusion of such a provision. The toxics, environmental "hotspot" and justice concerns typically associated with VOC/NOX trades are absent where VOC reductions are being traded against NOX requirements. BCCA supports a general provision allowing the use of VOC reductions in lieu of NOX allocations, upon an application demonstrating equivalency of ozone reductions.

6.11 The Economic Incentive Program should be Expanded and Strengthened

Although the Proposal's cap-and-trade and open-market credit programs are useful and valuable, a broader range of economic incentive programs is essential to achieve ozone attainment expeditiously and with the least economic and social disruption. BCCA supports an incentive program designed to provide funds on a competitive basis to assist in the cost of emission reductions on the broadest range of source categories. If such a program relies on a private source of funding, it should provide appropriate credit or benefit to the parties providing the funding. In addition, BCCA supports an incentive

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program whereby any party could obtain appropriate credit for identifying and developing innovative emission reduction measures outside the framework of the existing incentive programs. The Plan should incorporate the broadest authority for the Executive Director to approve and credit such initiatives on a case-by-case basis.

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Section 7—SIP Implementation Issues

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7.0 SIP Implementation Issues

7.1 Background

In order to demonstrate attainment, the HGA must have three years of ambient monitoring data to confirm that on average, there has not been more than one ozone violation annually. TNRCC has proposed that all control measure be in place by YE 2004 in order to collect ambient monitoring data in the summers of 2005, 2006, and 2007 to demonstrate ozone attainment.22

TNRCC is not expected to have final control regulations promulgated until YE 2000, at which time facility operators will need 12-18 months to scope and design equipment, secure permits, perform detailed engineering, secure funding and begin the installation of controls. It will therefore, not be until 2002 that many companies will be in a position to begin control installation. This will leave only 3 years for some 180 companies to begin retrofitting over 2,500 individual pieces of equipment with the proposed control technology.

7.2 Impact of Proposed Deadline on Plant Maintenance

The time between turnarounds for these types of combustion sources ranges from 4 - 7 years, depending on service, or about 5 years on average. Given the three year window available to install controls, companies across the region will be required to take over 800 unscheduled equipment downtimes at a significant loss in production. Such non-optimum downtimes not only result in loss of production, but also in short-term product supply shortages and escalation of price to consumers, especially in the bulk commodity industries such as ethylene and fuels. TNRCC must consider the impact of these unscheduled equipment shutdowns associated with the proposed SIP on the overall economy of the region.

7.3 Impact of Proposed Deadline on Permitting

Permitting of combustion controls (e.g., Low NOx Burners) will be relatively straight forward using the standard permit process and the time to obtain such permits is included in the 12-18 month pre-construction lead-time. However, many controls will employ the use of ammonia and result in additional ammonia emissions. Ammonia emissions in the HGA are projected to increase by about 11,500 tons per year solely from the application 22 Current EPA policy and precedent allows implementation of source controls as late as the attainment year (2007). See 57 Fed. Reg. 13509 (April 16, 1992) (State Implementation Plans; Genera; Preamble for the Implementation of Title I of the Clean Air Act Amendments of 1990). See also page 82 of EPA's last draft of Proposed Implementation Guidance for the Revised Ozone and Particulate Matter (PM) National Ambient Air Quality Standards (NAAQS) and the Regional Haze Programs, November 7, 1998. The BCCA encourages the TNRCC to pursue this interpretation when developing and finalizing the SIP regulations in 2000.

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of Selective Catalytic Reduction control technology on multiple individual point sources greater than 40 MBtu/hr. It is expected that the use of ammonia in such controls will trigger more complex permitting requirements due to increased ammonia emissions, and will likely increase the pre-construction lead-time. This, in turn, shortens the total amount of time available to install the controls, resulting in more unscheduled equipment downtimes and economic burden to the region that must be considered in the selection of controls. TNRCC is encouraged to consider and authorized these more complex permitting activities through the rule-making process and not on a case-by-case basis.

7.4 Project Design and Engineering Considerations

There are many engineering challenges associated with the retrofit of existing combustion devices with flue-gas treatment technologies that add significantly to the cost of a NOx control project. Many of these challenges are identified in the engineering design phase of a project. The TNRCC must make every attempt to quantify these additional costs and include them in the economic analysis associated with the proposed SIP.

The availability of plot space for large flue-gas treatment catalyst beds in retrofit applications is a significant cost factor. If the available space is limited (as is often the case in retrofit applications) and new structural platforms and extensive ducting are required, standard cost-estimating techniques apply a factor of 4 to the Total Installed Cost (TIC) of the project. Therefore, a $10,000/ton NOx reduction control project will escalate to a $40,000/ton project if space is not readily available for catalyst beds.

The most common flue-gas treatment technology, Selective Catalytic Reduction, typically operates at flue-gas temperatures in the range of 550 - 800°F for the catalytic reduction of NOx to nitrogen. Boilers and heaters commonly employ elaborate heat recovery designs and technologies (e.g., air pre-heat systems, waste heat recovery units) that can reduce flue-gas temperatures down to the 200-300°F range as an energy conservation step. In such cases, extensive facility redesign/reconfiguration is necessary to direct flue-gas from the heat recovery system to the SCR device at the optimum temperature. Once the flue-gas passes through the SCR catalyst beds for NOx removal, it must then be re-directed back into the heat recovery systems. In other words, in many retrofit applications, SCR cannot simply be placed at the end of the flue-gas handling system, but must be designed and constructed to operate at the optimum point within the heat recovery system. Such equipment reconstruction adds significantly to the construction cost and to the production downtime necessary to install the project.

SCR technology will increase the pressure drop and reduce the draft characteristics in the combustion device’s flue-gas handling system. This effect will, in many cases, reduce the capacity or production rate of the facility. In other retrofit applications, large flue-gas conveyance fans and associated equipment must be added or expanded to compensate for the increased pressure drop, significantly increasing the construction cost of the project.

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The installation of combustion controls, such as Low NOx Burners will, in many cases, reduce the existing capacity of certain combustion devices by about 10-15% relative to conventional burners. This furnace capacity must be reestablished by addition of significant new equipment or production capacity is lost. The heat input replacement cost or production loss associated with this control technology will significantly increase the overall cost of the NOx reduction project and should be included in the overall regional cost impact assessment.

There are a number of project implementation issues that may impacts project schedule and therefore, how quickly controls can be put in place. Most of the issues in the case of the HGA SIP will result from the fact that over 180 individual companies will be competing for limited resources to engineer, design, permit, construct, and operate some 1,900 boilers, heaters, turbines, and engines, newly modified with SCR technology. TNRCC must assess and consider these potential project implementation constraints before determining regulatory standards and deadlines.

7.5 Projected Demand for Manpower and Material Resources

Facts establishing that the proposed SIP implementation deadline of year-end 2004 as infeasible are presented in the attached NOx Implementation Resources Study completed by Fluor Daniel23 for the BCCA. (See Appendix I) Engineering, materials, & labor availability, as well as implementation timing issues were examined. Labor resources (engineering and construction) & materials (such as burners, SCR catalyst, NOx analyzers, electric motors, etc.) were included. Projected demand for manpower and material resources was compared to estimates of available supply with the following conclusions:




Highly specialized labor resources, such as furnace engineering evaluation specialists and flue-gas computational fluid dynamics modelers are expected to be in short in

23 Houston-Galveston Area State Implementation Plan Resource Availability Study, Fluor Daniel Company, August 2000.

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supply and a critical path limitation to timely completion of engineering design activities.



BCCA requests the TNRCC comment on each of these projected manpower and material constraints in the final rulemaking package.

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Section 8: Emissions Incentives Reduction Programs

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8.0 Market-Based Incentives

BCCA supports the development of market-based programs that provide incentives to reduce emissions from all sources that contribute to the region's overall NOx emissions. Market based programs will be particularly effective in reducing emissions of VOC and NOx from sources that are traditionally more difficult to control, or that are federally preempted from control. Existing programs in California and other states have shown that market-based incentives efficiently and cost-effectively reduce emissions at a cost lower than a traditional command-and control approach.

BCCA proposes a tiered market based incentive program, which will ultimately address all source categories in the HGA thereby allowing all stakeholders in the region to participate in the SIP NOx reduction strategy. Currently, a three-tiered program is envisioned, but this is only a preliminary assessment and other programs types can certainly be developed. The programs currently envisioned include:

(1) Emissions Trading Programs(2) Financial Incentive Programs(3) Voluntary Incentive Programs

8.1 Emissions Trading Programs

Emission Trading Programs should be developed for all source categories (stationary, mobile, and non-road sources) that establish emission caps, emission rights, and a system of trading in those rights throughout the non-attainment area. TNRCC has proposed such a program for stationary sources, which is described in Section 6 of these comments. However, TNRCC should go further and establish Emission Trading Programs for federally preempted mobile and non-road sources in order to achieve the emission reductions necessary for ozone attainment. Such a trading program should allow trading among sources and source categories and offers the potential to achieve the greatest emission reductions at the lowest cost to the program participant.

8.2 Financial Incentives Program

Several options exist for creating market mechanisms that may, as part of government and/or privately financed program, generate significant reductions in ozone precursor emissions. Such financial incentive programs could offer funding assistance through tax credits, direct loans or grants aimed at approved emission sources. These incentive programs could be enforced and utilize enforceable commitments between TNRCC and EPA for a specific ton per day reduction to ensure reductions are credited in the HGA SIP. Alternative, financial incentive program can also be strictly voluntary where third parties pursue emission reduction credits through approved mechanisms. Depending on the structure of the program (strictly voluntary, enforced, or mixed), a number of options

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are available. Below are a few examples to the types of programs that could utilize a financial incentive market based program:

8.2.1 On-Road Mobile Sources

(a) Vehicle Retirement Program

TNRCC should pursue a vehicle scrappage program for the HGA that is based on the actual emissions of the retired vehicle, purchased for retirement at market-based prices.

(b) Vehicle Repair and Retrofit Program

TNRCC should pursue a voluntary program by which emission reduction credits would be generated from the repair or retrofit of high-emission vehicles. Such a program would apply primarily to low-income individuals that would otherwise be exempt from mandatory repairs under a vehicle Inspection and Maintenance (I/M) Program. The vehicle owner could elect to have a third party repair or retrofit a non-compliant engine through state or third party funding, thereby generating a certified emission reduction credit for use in the HGA.

(c) Fleet Vehicle Repair and Replacement Program

TNRCC should pursue a voluntary program with government and private owners of fleet vehicles (e.g., school buses, garbage trucks, police cars, and delivery trucks) for repair or replacement of engines to reduce emissions. Emission reduction credits offer the necessary incentive to make the program work. The program should permit third party financing of the emission reduction transaction.

8.2.2 Non-Road Vehicle and Equipment Sources

(a) Vehicle and Equipment Scrappage Program

Similar to the on-road program described above, TNRCC is encouraged to pursue programs that generate voluntary credits, based on actual emissions and market prices, for the scrappage of non-road vehicles, engines, and equipment.

(b) Vehicle and Equipment Repair, Replacement, and Retrofit Program

Similar to the on-road program described above, TNRCC is encouraged to pursue programs that generate voluntary credits, based on actual emissions and market prices, for the repair, replacement and retrofit of non-road vehicles and equipment. Such a program could create an early market for engine turnover and could be paid for by the equipment owner, or a third party with transferable a transferable emission reduction credit.

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BCCA is committed to working with TNRCC and the Texas Legislature in developing market based incentive programs to achieve additional NOx and VOC emission reductions in the HGA.

8.3 Voluntary Incentives Program

Strictly voluntary programs could be developed to reduce emissions of ozone precursors. For example, number of the programs identified in Section 8.2 could also be deployed on a voluntary basis where the only incentive necessary to develop the market is the need to reach mandatory emission reduction targets.

There are a number of other voluntary programs that TNRCC could pursue in the point source sector that would reduce ozone precursor emissions. Such programs include, but are not limited to:

(a) Shutdown Management Program

TNRCC should pursue Agency/Industrial partnerships to initiate the development of voluntary industrial standards for the scheduling of major industrial maintenance activities so that ozone precursor emissions are minimized during the ozone formation season.

(b) Upset and Maintenance Emission Standards

TNRCC should pursue Agency/Industrial partnerships to develop a voluntary program to reduce upset and maintenance emissions. Such a program would be founded on management systems that include performance standards, root-cause analysis, measurements, and stewardship to ensure the desired results are achieved. Reducing upset and maintenance emissions will be critical to the long-term air quality goals of the region.

8.4 Implementation Issues

The BCCA believes that ultimately, a completely market-based approach will create a sustainable, competitive, effective incentive system. However, the BCCA recognizes that a public/private funding partnership is the most effective mechanism to begin the rapid deployment to this program that is necessary in order to make meaningful reductions before 2007. Therefore, the BCCA supports the establishment of a grant fund to cover the incremental cost, on a competitive basis, of projects that achieve the most cost-effective NOx reductions. The BCCA supports the policy recommendations of the “Incentive Fund for Early Smog Reduction” developed by the Texas Clean Air Working Group, of which it is a member. The BCCA encourages the TNRCC and EPA to use this program as a mechanism to obtain early, cost effective reductions in place of those proposed rules that are not technologically feasible or have unintended negative social

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and economic consequences.

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Section 9: Mid-Course Correction

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9.0 Mid Course Evaluation

The BCCA supports a mid-course evaluation of the SIP to take place no later than the end of the year, 2003. This evaluation and adjustment should provide for a comprehensive scientific review of the model and other decision-making tools; should take into account new data collected from the TxAQS 2000 study; and evaluate new and emerging technologies.

Furthermore, the BCCA believes that the TNRCC should perform a through evaluation of the selected control strategies in the final December 2000 attainment SIP, to ensure that they are the optimum strategies for reducing ozone at the lowest possible cost. The TNRCC should make the appropriate adjustments to remove or relax unnecessary controls, and strengthen those strategies that are not as effective as planned.

The BCCA has suggested that certain technology-forcing controls should be deferred until they have been fully developed and verified and are commercially available. The BCCA commits to work aggressively to pursue and develop new technology and pursue programs to hasten their penetration into the marketplace. The BCCA encourages the TNRCC to work closely with the recently announced "Texas Council on Environmental Technology" to ensure that new technologies developed by the program are incorporated in the SIP at the mid-course evaluation.

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Section 10: Cost of Controls and Implementation

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10.0 Cost of Controls and Implementation

10.1 Stationary Source Control Costs

In order to assess the potential capital costs of controls to stationary point sources, five Coalition member companies conducted engineering studies of their combustion sources. Each of the participating companies has world-class industrial facilities in the HGA and, in total, represents about 40% of the boiler and heater firing capacity. Each company used in-house technology, project engineering, and cost-estimating experts to build a seriatim of combustion control projects up to the limits of technology. The end-product was a Capital Cost vs. NOx Reduction curve for each company that was then scaled up to estimate regional costs for the combustion sources in the HGA. Cost estimators assumed that no extraordinary costs, such a limited plot spacing or significant furnace convection section rebuilding, were incurred since such details do not emerge until more definitive engineering is underway. Such extraordinary cost, however, will certainly occur in retrofit applications and will add significantly to total project costs.

These estimates continue to be the best current estimates until BCCA member companies begin to complete in 4Q2000 some on-going facilities screening studies. These will be shared with the TNRCC, as they become available.

10.2 Utility and ICI Combustion Units

TNRCC has estimated the total capital cost for affected sources in the HGA at approximately $2.7 billion. We believe this estimate is low by more than a factor of two. BCCA member companies have been unable to review the TNRCC cost estimate background documentation, which provides the basis and experience for the "NESCAUM spreadsheet." We speculate that, much like the other EPA ACT reference documents, there is limited actual installed retrofit cost data for ICI boilers, heaters, furnaces, gas turbines, and miscellaneous sources like FCC Units. As a result, TNRCC has likely based most of the cost estimates for the proposed SIP on new, grass roots facilities that have been specifically designed for low NOx performance technology, as opposed to cost estimates for the retrofitting of equipment already in operation. The incremental cost to apply that low NOx technology in a new design is much lower than the cost to apply that same technology on an existing unit. In retrofit applications, there are unique sets of design and operating conditions inherent to the existing equipment that must be considered on a case-by-case basis in an attempt to achieve the desired NOx reduction target. In some cases, it will be possible to achieve the intended NOx reduction targets; in other cases, it will not be technologically or economically feasible to do so.

The regional cost curve for Utility and ICI combustion point sources, based on BCCA member company engineering studies, is presented in Figure 10-1 and shows that the cost to achieve a 90% NOx reduction target (assuming the technology achieved the

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desired targets in all cases) is between 5 and 6 billion dollars. Again, no extraordinary costs such a plot spacing limitations, new infrastructure, or significant combustion unit rebuilding were assumed since such details do not emerge until more definitive engineering is underway. Such extraordinary cost, however, will certainly occur in retrofit applications and will add significantly to total project costs. Additionally it was assumed that the prescribed technology would achieve the desired NOx reduction target in all cases, that no unit replacements, consolidations, or shutdowns would be required. Based on the experience in the South Coast Air Quality Management District with less stringent standards than those proposed by TNRCC, we believe these to be conservative assumptions that will tend to underestimate combustion unit retrofit costs.

10.1.2 Discussion of TNRCC Cost Estimate Basis vs. Industry Experience

BCCA member companies have been developing a record of actual installed capital cost for NOx reduction projects. These actual installed capital costs and some recent cost estimates in individual pieces of equipment are as much as 10 times the cost as estimated by TNRCC's methodology. Specific case study examples are provided below. This record, though limited, indicates the TNRCC has underestimated the cost of retrofit technology applications where it has relied on the following sources:

(a) EPA's Alternative Control Techniques Document - NOx Emissions from Industrial/Commercial/Institutional Boilers & the STAPPA/ALAPCO "Controlling Nitrogen Oxides Under the Clean Air Act : A Menu of Options" understate burner retrofit costs , impacting the NOx reduction cost effectiveness for a) 235 ICI boilers less than 40 MMBtu/hr b) 726 gas fired process heaters less than 40 MMBtu/hr firing.

TNRCC used an average retrofit burner cost factor of $3100 per million Btu. Industry installed cost experience ranges from about $3000 per million Btu to $8000 per million Btu. The ultra-low NOx burners required to meet the proposed standard for the less than 40 million Btu sources, in addition to being significantly higher cost than the TNRCC proposal, also often result in the boiler / furnace experiencing a significant loss of capacity. The additional investment required maintaining capacity is not factored into the proposal's cost estimate.

Several of the HGA large sites are currently doing refined screening studies and will be able to share with TNRCC better retrofit cost estimates in the November, 2000 time frame to provide a better estimate basis for the final rule.

(b) Spreadsheets provided by NESCAUM & the STAPPA/ALAPCO "Controlling Nitrogen Oxides Under the Clean Air Act : A Menu of Options" understate SCR costs in all cases for -a) 90 40 MMBTU/hr to 100 MMBtu/hr gas fired ICI boilers b) 180 > 100 MMBTU/hr gas fired ICI boilers c)14 FCC units d) 23 Incinerators e) BIF units f) 424 gas fired process heaters > 100 MMBtu/hr firing g) 216 gas fired process heaters with a firing between 40 and 100 MMBtu/hr.

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A BCCA member company capital cost for a 68 million Btu/hr furnace retrofit was $1.5 million dollar. TNRCC's cost tool calculates a $641k capital retrofit cost for a comparable furnace. Actual cost is 2.3 times the TNRCC cost estimate.

A BCCA member company SCR cost estimate for a 260 million Btu/hr furnace is $5 million total capital retrofit cost. The comparable TNRCC cost tool calculates a $1.45 million capital retrofit cost. Actual cost is 3.5 times the TNRCC cost estimate.

A BCCA member company SCR retrofit cost estimate for a 260 million Btu/hr furnace is $5 million. The comparable TNRCC cost tool calculates a $1.45 million capital retrofit cost. Actual installed cost is 3.5 times the TNRCC cost estimate.

A BCCA member company has recently completed an engineering study and estimate for a new grassroots ~300 MBtu/hr furnace designed with SCR technology. The incremental cost to add SCR on this new furnace is estimated to be about $1.5 million, more in-line with TNRCC estimating tools.

A BCCA member company installed SCR capital cost for a single FCC unit retrofit is more than 3 times the TNRCC cost estimate. However, most FCC unit configurations in the HGA will be significantly more difficult and costly to retrofit than the example above. The TNRCC's cost estimate of $2.8 million for a FCCU retrofit will likely be less than 30-40% of the actual cost for FCCU retrofits in the HGA.

A BCCA member company SCR retrofit capital cost for a 470 MBtu/hr boiler was $4.5 million. TNRCC's cost tool calculates a $2.8 million capital cost for a comparable boiler. Actual installed cost was 1.6 times the TNRCC cost estimate.

(c) “Status Report on NOx Control Technologies and Cost Effectiveness forUtility Boilers” Issued by NESCAUM/MARAMA in June, 1998 understates SCR costs for gas and coal-fired boilers.

A BCCA member company has performed detailed, unit-specific SCR cost estimates for its gas and coal-fired boilers. The SCR cost estimates for gas-fired boilers range from $30-70/kW. These costs are significantly greater than the TNRCC’s estimated cost of $30/kW for this type of control equipment. Furthermore, the company’s estimated SCR costs for coal-fired boilers exceed the costs identified in TNRCC’s proposal.

In summary, BCCA believes the TNRCC has underestimated the capital cost for point source Utility and ICI combustion unit NOx control technology retrofits by at least $2.5 billion dollars. BCCA member companies begin to complete in 4Q2000 some on-going facilities screening studies that will be shared with the TNRCC so that a more accurate economic assessment can be provided to the general public during the final rule package. 10.3 Turbines

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10.3.1 General Information

The TNRCC Gas Turbine cost estimate of $2.1 million dollars per Turbine / HRSG ($403 million total for the HGA) underestimate retrofit costs for the region. We believe the EPA reference guide used does not adequately represent retrofit costs, but instead is more representative of the cost of new, grassroots SCR installations as noted in the reference document itself.

Additionally, the largest size Gas Turbine SCR retrofit we have been able to document is a 35-Megawatt unit. Turbines of this size and larger represent 40% of the total turbine population in the HGA. There is also a lack of retrofit cost data for the remaining 60% of the turbine population in the HGA.

Table 10.1Turbine Size Distribution in the HGA

Turbine Size Range % of Turbines in HGA Inventory

0.3 to 3 MW 22

3.01 MW to 10 MW 10

10 MW to 20 MW 25

20 MW to 35 MW 4

35 MW to 80 MW 24

Greater than 80 MW 15

Total 100

Although input from gas fired turbine owners is limited at this time, the data currently available yields a curve similar in shape to Figure 10-1 for boilers and heaters. In other words, capital investment costs rise exponentially with increasing NOx reduction, with cost increasing significantly as reductions exceed the 65% level and becoming extremely expensive above a 90% reduction level. Small and low capacity factor turbines will especially be high cost retrofits.

There are approximately 180 gas-fired turbines in the HGA to be retrofitted with SCR controls. Based on the best engineering data available from BCCA member companies, it is estimated that the capital cost to achieve the desired NOx reduction target will be in the 800 - 1,200 Million dollar range, depending on the turbine design, power output and use. No extraordinary costs such a plot spacing limitations, new infrastructure, or significant turbine or HRSG rebuilding was assumed since such details do not emerge

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until more definitive engineering is underway. Such extraordinary cost, however, will certainly occur in retrofit applications and will add significantly to total project costs. Additionally it was assumed that the prescribed technology would achieve the desired NOx reduction target in all cases, and that no turbine replacements, consolidations, or shutdowns would be required. Based on the experience in the South Coast Air Quality Management District with less stringent standards turbine standards than those proposed by TNRCC, we believe these to be conservative assumptions that will tend to underestimate turbine retrofit costs.


EPA's ACT document "Alternative Control Techniques Document NOx Emissions from Stationary Gas Turbines " understates the retrofit cost of control for the 189 gas turbine / HRSG combinations. In fact, Page 6-1 of this document says "No SCR retrofit applications were identified, and costs for SCR retrofit applications were not available. The cost to retrofit an existing gas turbine installation with SCR would be considerably higher than the costs shown for a new installation, especially for combined cycle and cogeneration installations where the heat recovery steam generator (HRSG) would have to be modified or replaced to accommodate the catalyst reactor."BCCA member cost estimate surveys (case studies) support this conclusion

Actual installed cost for a GE Frame 5, 20 Megawatt Gas Turbine / HRSG in California was $8.8 million dollars. This gas turbine was used as a driver to supply shaft horsepower to a process unit blower.

A Louisiana GE Frame 6, 35 Megawatt Gas Turbine / HRSG co-generation unit retrofit was ~$4 million dollars

A 15 Megawatt Gas Turbine / HRSG co-generation unit retrofit in the Netherlands was $2.5 million.

A 4 Megawatt Gas Turbine / HRSG retrofit in Texas was $1.34 million. This gas turbine was used as a driver turbine.

A recent BCCA member company screening cost estimate for a GE Frame 6, 35 megawatt Gas Turbine / HRSG co-generation unit retrofit was $6.3 million.

These limited case studies indicate the actual installed costs are much higher than TNRCC anticipates, and quite variable depending on individual gas turbine use and location specifics. Thus, we do not believe the TNRCC cost estimate adequately reflects the retrofit costs operators

10.4 Internal Combustion Engines

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BCCA member companies did not have sufficient time to assess the capital cost of the extreme controls placed on internal combustion (IC) engines given the very short comment period. BCCA agrees however, that the proposed limits will force widespread replacement of both rich and lean-burn IC engines with electric motors. BCCA does not support such a proposal for all the reasons outlined in Section 1.x.

Until BCCA developed cost data for the IC engine proposed standards, it will use the TNRCC cost estimate of $441 million dollars. However, just based on the need for significant new electrical infrastructure associated with the proposal, we anticipate the TNRCC cost estimate is low.

10.5 Emission Monitoring Systems

Use of the US EPA's continuous Emission Monitoring System Cost Model, Version 3.0 understates the cost of NOx CEMS for CEMS. Industry experience with installed retrofit costs under the TNRCC RACT I program was in the $350K - $400k range. The preamble also underestimates the # of CEMS the new point source rule will require as all units equipped with SCR will require installation of a NOx CEMS. We believe the number of new CEMS will be closer to 700, not 300. Based on industry experience of $350 thousand per installation, and 700 new instruments required, BCCA estimates the cost of new emission monitoring systems required by the proposed SIP to be $245 million dollars.

10.6 On-Road and Off-Road Fuels

10.6.1 Proposed Texas LS Gasoline Rule Cost

Definitive engineering estimates of the capital costs for LS Gasoline for east/central Texas have not been made. However, very reasonable assumptions can be made based on estimates provided in the National Petroleum Council Study (see Appendix VII), the Charles Rivers Associates Study (See Appendix XIII), and California experience with CARB diesel. It is clear, however, that the special requirements for Texas fuels, over and above the of the EPA Tier II gasoline and proposed low sulfur diesel, will impose significant additional capital costs on refiners and cost to the consumer at the pump.

BCCA estimates the capital cost to produce 522,000 B/D of proposed Texas LS gasoline for east/central Texas, with a 15 ppm sulfur cap, at approximately $2 billion.

New technology breakthroughs in deep gasoline desulfurization technology and/or newly developed synergies in producing low sulfur fuels has to potential to reduce this 2 billion dollar cost for the proposed Texas LS Gasoline program.

10.6.2 Proposed Texas LED Costs

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Definitive engineering estimates of the capital costs for 2002 LED for all of Texas and 2006 LED for east/central Texas has not been made. There is more uncertainty in estimating the costs for the Texas LED program since such fuel specifications have never been established. EPA is in rulemaking process for a federal diesel rule and the oil industry and the diesel engine manufacturers are just beginning to model refinery requirements to meet potential new diesel fuel specifications. For implementation of California's diesel specifications in 1993, California refiners expended about 600-800 million dollars (today's dollars) to make CARB diesel which is similar to the 2002 LED specifications that will apply to all of Texas. There is no similar experience on which to base the cost for the ultra-low sulfur diesel TNRCC has proposed for east/central Texas.

However, learning from the CARB diesel experience and recent estimates made by EPA and Charles Rivers Associates for very low sulfur diesel, it is estimated that the capital cost for state-wide 2002 LED will be $500 million. The estimated capital cost to produce the ultra-low 2006 LED for east/central Texas is $700 million.

New technology breakthroughs in deep distillate desulfurization technology and/or newly developed synergies in producing low sulfur fuels has to potential to reduce this $1,200 million dollar price tag for the proposed Texas LED program.

10.7 Estimated SIP Cost

Table 10.1 summarized the estimated cost of the proposed SIP for those elements of the plan that can be quantified and reaches an estimate of about 10 billion dollars. There are many elements of the proposed SIP for which cost estimated could not be developed at this time including:

The proposed ban on the use of construction equipment between the hours of 6 AM and Noon between the months of April and October. This proposal alone could add billions of dollars in added cost to the heavy construction industry, Port of Houston Authority, and petrochemical/refining complex in the HGA.

The proposed ban on the use of lawn service equipment between the hours of 6 AM and Noon between the months of April and October.

The electrification of airport ground service equipment.

The Off-road equipment Tier II/III engine replacement and exhaust gas treatment system requirements.

The mandatory distribution and marketing of proposed Diesel Emulsion Fuel

BCCA is committed to working with the TNRCC to reduce the cost of the proposed SIP through more cost-effective control measures, technology development, and market-based incentives to reduce emissions.

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Figure 10- 1

Total Capital Cost for Controlling NOX Emissions from Boilers and Process Heaters up to 90% (Dotted Line Indicates Extrapolation for Emission Reductions Greater than 84%)

Table 10-1

SUMMARYCOST OF CONTROLS SCREENING ANALYSIS(1)

Source CategoryTNRCC Estimated Capital Investment

$Million

BCCA Estimated Investment Cost

$Million

Annual(2)

O&M Costs$Million

Stationary Sources- Utility/ICI Units 1565 5,000 - 6,000 150 - 250- IC Engines 441 441 10 - 15- Gas Turbines 403 900 - 1200 30 - 50- Instrumentation 58 245 10

Texas Fuel Proposals(3)

- Texas Gasoline 484 2,000 160- Texas Diesel 340 1,200 100

Construction Industry- Shift in Operating Hours Not Quantified Not Quantified Not Quantified

Total Screening Cost 3,233 9,800 - 10,900 460 - 585Notes

(1) Does not include increased cost to area consumers for products such as motor gasoline, diesel, and electricity(2) Operating and Maintenance (O&M) costs estimated to be 15-20% of annual (amortized) cost of capital(3) Does not include the cost of Federal Phase II/Low Sulfur gasoline requirements which are projected to cost HGA refineries approximately 2 billion dollars.

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Section 11—Modeling of Attainment Control Strategies

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11.0 Modeling of Attainment Control Strategies

The TNRCC’s proposed SIP revision is based on photochemical modeling of the September 8 – 11, 1993, ozone episode. The BCCA is very concerned about the model’s base case accuracy for this episode and its inability to quantitatively predict the emission reductions needed to attain the ozone NAAQS. This is despite performance statistics that seem to fall within EPA guidelines for acceptability. Foremost of our concerns is the fact that the modeled peak ozone levels that are driving the extreme breadth and depth of TNRCC’s proposed control strategy are just an aberration of poor model performance that occurred in a relatively small area of the modeling domain. Our concerns about the model performance and recommendations for overcoming the modeling limitations are presented in the following paragraphs.

11.1 Concerns about Model Performance on September 8, 1993

Of the four primary episode days modeled by TNRCC, September 8, 1993 requires the most emission reductions needed to demonstrate modeled attainment. For that reason, modelers call September 8 the “controlling day”. The gap calculation prescribed by EPA Region VI and presented in Section 3.6 of the proposal is based just on the predicted ozone maximum for September 8. As the following paragraphs show, the predicted ozone maximum that TNRCC’s control strategy struggles to abate, in reality, never occurred in the time and place the model said it did.

Figure 11-1 shows the model’s predicted ozone levels for September 8 for the future control strategy case. Note that the maximum occurs in southern Harris County. The legend at the bottom of the figure shows that the maximum is 146.4 ppb and it occurs in grid cell (26, 31) (the base case maximum, before controls, was 187 ppb, in grid cell (26, 30)). Figure 2 shows the locations of all the public and private ozone monitoring sites that were operating during this episode. Croquet, identified as HCQA in Figure 11-2, is the monitoring site closest to the modeled peak. It is also in grid cell (26, 31). Here is how TNRCC’s modeling contractor, MCNC, summarized the base case model performance at Croquet:

“SITE T-18 CROQUET TX (time series): (scatter plot) This site is located in far southern Harris County. It is generally characterized by model overpredictions (50 ppb on the 8th, 30 ppb on the 9th and 10th, 40 ppb on the 11th).”

--http://envpro.ncsc.org/projects/TNRCC-TOC/

The model’s base case over-prediction at Croquet is actually more than 50 ppb. It is roughly 70 ppb (nearly 40% bias). What's more, the highest one-hour ozone level that was monitored at Croquet on September 8, 1993 was only 114 ppb, a level that is 10 ppb less than the level of the one-hour standard (never mind how far below the model predictions). Figure 11-3 is a time series plot that compares the monitored ozone levels at Croquet with base case model predictions for every hour of the four days beginning with September 8, 1993. Note how poorly the model

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replicates the measured ozone levels on September 8. Figure 11-4 shows the time series plot, comparing monitored and modeled ozone levels, at Swiss & Monroe (HSMA), the other monitoring site in southern Harris County. Note that the model overestimated the observed ozone levels there, as well.

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Figure 11-1. Model Predictions of Daily Maximum Ozone Levels for September 8 after Implementation of the Modeled Control Strategy.

Figure 11-2. Locations of Public and Private Ozone Monitoring Sites that were Operating on September 8, 1993.

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Figure 11-3. Time Series Graph Comparing Base Case Modeled Ozone (aak93 and 93basA)24 with Monitored Ozone Levels (Obs) at Croquet on September 8 – 11, 1993.

Figure 11-4. Time Series Graph Comparing Base Case Modeled Ozone (aak93 and 93bas A) with Monitored Ozone Levels (Obs) at Swiss & Monroe on September 8 – 11, 1993.

24 Model scenarios aak93 and 93basA are two different base cases used in the SIP modeling, each representing different assumptions about base case emissions.

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In its October 1999 SIP Revision, Appendix B (pages 38-39), referring to the peak ozone levels in southern Harris County, TNRCC noted:

“We believe that this ozone peak is artificially enhanced because of [problems with] the simulated meteorology and may, in fact, be easier to control, than the

model is currently showing.”

-- TNRCC, October 1999 SIP Revision, Appendix B

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In the August 2000 proposal, however, TNRCC simply cites the performance statistics in Table 3.3-4 as the basis for acceptable model performance and fails to acknowledge or take account of the unacceptable model performance in precisely the area that is requiring the most emission reductions needed to demonstrate modeled attainment.

True, the base case performance statistics for all four days of the episode, including September 8, fall within the acceptance criteria guidelines given by EPA’s 1991 document titled, “Guideline for Regulatory Application of the Urban Airshed Model25.” However, TNRCC has not taken appropriate account of the graphical performance methods, such as the surface level isopleths and time series plots (as shown in Figures 1, 3, and 4), that its December 1998 modeling protocol says would be considered.

The TNRCC’s claim that model performance is acceptable seems to rest on the fact that ozone levels monitored elsewhere in the domain (near Galveston Bay) were close to the modeled peaks for southern Harris County and because good agreement between modeled and monitored ozone levels was achieved for other sites. However, the effectiveness of NOx or VOC emissions reductions in reducing ozone levels depends on proximity of the ozone peak to the emissions sources. Therefore, a model that cannot accurately predict the location of the ozone peak probably will not accurately predict the benefits of future emission reductions.

Comments from EPA Region VI to TNRCC regarding TNRCC’s June 1999 SIP Revision Proposal show that EPA shares this concern. In its August 1999 comments, EPA noted the following:

“EPA/6 raised a concern with the modeling previously submitted (May 1998) and recommended that due to the model’s poor graphical performance caution is warranted in assessing the model’s projected ozone reduction to NOx control strategies in this urban portion of the modeling domain. We continue to have this concern. We note that TNRCC is also concerned about the model’s performance in this portion of the domain as discussed on pages 38-39 of Appendix B. EPA would like to work with TNRCC to find ways to address this mutual concern.”

If TNRCC and EPA Region VI have worked to address this concern, their efforts are not described in the August 2000 proposal and the latest model simulations show no evidence that they were successful.

The Houston Regional Monitoring Network (HRM) is also concerned about the model’s poor graphical performance and contracted Dr. Harvey Jeffries to review the model simulations. While praising the overall quality of the modeling effort, Dr. Jeffries noted that NO levels were grossly under-predicted at several central Houston monitoring sites on the morning of September 8 where afternoon ozone levels were over-predicted (none of the southern Harris County monitoring sites measured NO during this episode). Dr. Jeffries suggested that NOx inhibition 25 The performance criteria given in EPA’s 1991 guidance document were not developed with consideration of the minimum level of performance needed to make important regulatory decisions. They merely reflect what scientists, at the time, considered “reasonable expectations of model performance”.

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might have been suppressing the monitored ozone levels at these locations and that this was not reflected in the model. If true, this could explain both the base case over-prediction and the modeled peak’s stubborn response to simulated NOx emission reductions on September 8. Dr. Jeffries suggested that the model’s poor representation of the measured NO levels on September 8 could be due to some type of large misrepresentation of the mobile source fleet.

Whether due to a poor representation of some component of the emissions inventory or due to poor performance of the meteorological model (as TNRCC suggested), the model’s inability to accurately simulate ozone levels in southern Harris County on September 8 cannot be ignored. The modeled peak that is driving the immensity of the proposed control strategy, in reality, never occurred in the place and time the model said it did.

11.2 Alternate “Controlling Days”

Due to the model’s gross inability to replicate the location of the ozone peak on September 8, the BCCA recommends that TNRCC choose an alternate day for estimating the magnitude of emission reductions needed to demonstrate modeled attainment. Our analysis shows signs of poor graphical performance on all four of the episode days but September 8 and 9 appear by far the worst. Therefore, we recommend that TNRCC estimate the magnitude of emission reductions needed for attainment from the modeling results for September 10 and 11. Our analysis of model performance for September 9, 10, and 11 is summarized below.

11.2.1 September 9

For September 9, the modeled peak ozone level was also in southern Harris County, grid cell (32,27), but closer to the monitoring site at Swiss & Monroe, grid cell (31,31). The base case model performance at Swiss & Monroe for September 9 is shown in Figure 11-4, hours 24 through 48. Note again, the over-prediction at the monitoring site closest to the modeled peak. Here is how MCNC summarized the base case model performance at Swiss & Monroe:

“SWISS&MONROE / HARRIS CO TX (time series): (scatter plot) This is another far southern Harris Co. site, but the model vs. observed comparisons here are much better than at Site T-18. Peak daily ozone values are match within 5 ppb on the 6th, 8th, and 11th. Model performance is poor on the 9th with overestimations of 40 ppb.”

--http://envpro.ncsc.org/projects/TNRCC-TOC/

Dr. Jeffries, in his report to HRM, noted that September 9 had the worst model performance at in-land monitors of the four modeled days and speculated that a cloudy condition or some other meteorological phenomenon that was not accurately represented by the model was suppressing ozone formation.

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11.2.2 September 10

Like September 8 and 9, the modeled peak ozone levels were in southern Harris County (southwestern Harris County, on the 10th) but the highest monitored levels were near Galveston Bay (on Galveston Island, on the 10th). Like September 8, Croquet is the monitoring site closest to the modeled peak and ozone levels, there, were over-predicted by the model (Figure 11-3). Dr. Jeffries concluded that ozone levels on September 10 seem reasonably well simulated but he did not specifically address the over-prediction at Croquet.

Due to the similarities that September 10 shared with September 8 and 9 (with regard to the spatial patterns of measured and modeled ozone levels) the factors that drove the model to its poor graphical performance on the preceding days may also have been at work on September 10. However, for some unknown reason, perhaps because neither the monitored or modeled ozone levels were as high on September 10, the biases at particular monitoring sites were not as large.

11.2.3 September 11

September 11, 1993 was fundamentally different from the other three days of the episode in that it was the only day when the maximum monitored ozone levels were not near the edges of Galveston Bay. They were in central Harris County (HRM Site 1). September 11 was also the only day of the episode when the maximum modeled levels were not in southern or southwestern Harris County. They were in northwestern Harris County. Once again, though, the model did not replicate the location of the monitored ozone peak very well. The model underestimated ozone levels in central Harris County but there were no monitors near the modeled peak in northwestern Harris County to evaluate whether the model predictions, there, were overestimates. Compared with the preceding three days, the displacement of the modeled peak from the monitored peak was more uniformly aligned in the afternoon’s downwind direction. Of the four days of this episode, September 11 had a wind flow pattern that most closely resembled the classic land-sea breeze circulation.

11.3 Discussion

Despite model performance statistics that fall within EPA’s acceptance criteria, the model was unable to replicate the measured ozone levels in the areas where it counts the most – where the highest levels were either modeled or monitored. This is particularly troublesome because the September 8 – 11, 1993 episode is the only one of the seven episodes the TNRCC and its contractors have attempted to model for Houston – Galveston that passes even the gross statistical performance tests. This begs the question whether the model’s basic formulation sufficiently represents the complex chemistry and meteorology that result in high ozone levels in Houston – Galveston and whether the seemingly better performance for September 8 – 11, 1993 at some sites, is just a fortuitous result of compensating errors in the model.

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On three of the four episode days (September 8 – 10), the base case model underestimated ozone levels near the shores of Galveston Bay but overestimated ozone levels further inland, in south-central and southwestern Harris County. Yet, TNRCC has provided no explanation for this poor spatial representation nor has it provided any discussion of its impacts on the uncertainties of the proposed control strategy. The TNRCC has presented no evidence that the model is accurately simulating NOx or VOC levels, or other intermediate chemical species in the vicinity of the modeled peaks. Nor has TNRCC presented any corroborating evidence, either from observational-based models, other photochemical simulations, or other data of any kind, that support the extreme model predictions. Without such evidence, even the model’s ability to replicate some monitored ozone levels in the base case provides no assurances that the model can accurately predict the outcome of future emission reductions.

The TNRCC and its contractors have worked commendably to develop what may be, in many respects, the most accurate emissions inventory ever used in photochemical modeling. But major uncertainties still exist in other respects and in the model’s representation of the chemical reactions and meteorological processes that determine the location, time, and magnitude of high ozone levels in Houston – Galveston. Many of these uncertainties are currently being addressed in this summer’s $20 million field study of ozone formation in Houston – Galveston but unfortunately any improvements in the model formulations will come after the Commission acts on the current SIP proposal.

These doubts regarding the accuracy of the model predictions support the BCCA’s recommendations that new emission controls be based on proven cost-effective technology and that stakeholders be given as much time to implement controls as the Clean Air Act allows. The model simulations and basic science that are the foundations of TNRCC’s control strategy are currently not strong enough to support the unproven, technically infeasible, or economically – challenging measures in the proposal.

11.4 Recommendations

Despite the model performance issues raised here, Houston’s business community is still committed to attaining the ozone NAAQS and recognizes that photochemical modeling is still the preferred regulatory tool for developing a control strategy. However, we believe that TNRCC must address the risk that the modeling uncertainties have led them to a wrong estimate of the magnitude of emission reductions needed to attain the ozone NAAQS. Though most would agree that large reductions in NOx emissions are needed, TNRCC’s reliance on modeling results for September 8 has led them to base their unwavering estimate of the magnitude of the needed emission reductions on an ozone peak that is biased high by almost 40%. In fact, as we showed earlier, the ozone exceedance in southern Harris County that the proposed strategy is designed to abate never even existed in the place and time the model said it did.

The BCCA recognizes that the TNRCC and EPA have similar concerns about the performance

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of these episodes, and have worked to attempt to address it through a variety of studies and adjustments to the model. The BCCA supports the recent contract commissioned by Harris County with Environ. This work will re-run the model with an alternate meteorological simulation model, in a final attempt to address the non-performance of the grid cells in question.

The BCCA believes the best way to manage the risks of making a wrong decision on the magnitude of the needed controls is to base Houston – Galveston’s control strategy on the modeling simulations that have the least uncertainty. Though all four days of the September 8 – 11, 1993 base case simulation are characterized by poor graphical performance, by far, the greatest uncertainties exist for September 8 and 9. Therefore, the BCCA believes that the control strategy should be based on modeling results for either September 10 or 11.

For September 10, the modeled peak ozone level for the proposed control strategy is 139.9 ppb. For September 11, it is 132.6 ppb. Neither of these days passes the deterministic attainment demonstration test so we have applied the gap calculation methodology described in Section 3.6 of the proposal to the modeling results for each of these days. Table 11-2 gives the modeled peak ozone levels that were used to derive the gap equation and the equations for September 10 and 11 are given directly below (Equations (1) and (2), respectively).

Table 11-2. Modeled Peak Ozone Levels Used in Deriving the Gap Equation

SCENARIOModeled Peak Ozone (PPB)

September 10 September 11VI 159 155Via 148 141Vib 132 127

September 10: NOx = 0.2367 (OC)2 – 61.225 (OC) + 4205.7 (1)


Translating equations (1) and (2) to pass through the points (139.9, 395) and (132.6, 395) yield the following new equations for September 10 and 11, respectively.



Evaluating Equations (3) and (4) for OC = 124.5 yields NOx attainment targets of 374 tons per day and 358 tons per day for September 10 and 11, respectively. This results in gaps of 21 tons per day and 37 tons per day, respectively, for September 10 and 11, which could be filled (with surplus) from the list of gap measures given in Table 6.1-2 of the proposal.

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As our collective understanding of the science of ozone formation in Houston – Galveston continues to evolve, TNRCC must also take account of new information and make corrections to the control strategy, accordingly. Though TNRCC has expressed a commitment to conduct a mid-course review and implement further measures, if needed, it must make a similar commitment to relax or withdraw components of the control strategy if better science shows that the current model predictions are overly pessimistic.

11.5 Supplemental Modeling

The Houston Regional Monitoring Network contracted MCNC to perform supplemental modeling to determine the impact on TNRCC’s proposed control strategy if point source NOx emissions were reduced by 75% instead of the proposed 90%. The difference in total NOx emissions between the TNRCC proposal and HRM’s 75% point source control strategy (hereafter referred to as HRM Strategy 1) is 91 tons per day.

Additionally, HRM asked MCNC to model a second supplemental run by removing the additional 91 tons per day NOx emissions put into HRM Strategy 1 by subtracting it from the on road mobile and nonroad mobile source emissions inventories (this scenario is hereafter referred to as HRM Strategy 2). The results of the two supplemental modeling scenarios are given in Table 11-1.

Table 11-1. Results of HRM Modeling

StrategyModeling Results - Daily Maximum Ozone (ppb)

September 8 September 9 September 10 September 11TNRCC Strategy h13 146.4 134.7 139.9 132.6HRM Strategy 1 151.5 138.6 141.4 138.7HRM Strategy 2 140.7 130.8 130.9 131.8

Note that the 91 tons per day increase in point source NOx emissions produced daily maximum ozone increases ranging from 1.5 ppb (on September 10) to 6.1 ppb (on September 11). Also, note that the 91 tons per day decrease in on road mobile and nonroad mobile source NOx emissions produced ozone decreases, relative to HRM Strategy 1, ranging from 6.9 ppb (on September 11) to 10.8 ppb (on September 8). From this, we see relatively small benefits from TNRCC’s 90% point source control proposal relative to a 75% point control level but we see greater benefits if the same amount of incremental emissions was reduced from mobile sources.

Table 11-2 gives the ozone–reducing effectiveness of point source and mobile source (on road and nonroad) NOx emission reductions for each day of the simulation. Note that mobile source emission reductions ranged from 1.1 to 7.0 times more effective than point source NOx reductions at reducing ozone levels (given by the ratio of mobile source to point source NOx

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effectiveness). From this, it follows that mobile source NOx emission reductions are on average 3 times more effective at reducing ozone levels than are point source emission reductions.

Table 11-2. NOx Control Effectiveness for Point and Mobile Sources

Source CategoryNOx Control Effectiveness (ppb ozone per 100 tons NOx)September 8 September 9 September 10 September 11

Point 5.60 4.29 1.65 6.70On Road + Nonroad Mobile 11.87 8.57 11.54 7.58

Ratio (Mobile/Point) 2.1 2.0 7.0 1.1

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Section 12: Administrative Considerations of SIP Proposal

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12.0 Administrative Considerations

12.1 The Plan was Proposed without Adequate Notice and without Adequate Impacts Analyses

The Business Coalition appreciates this opportunity to provide relevant facts, analysis and alternatives, in the interest of helping craft a more reasoned and better-supported overall Plan. However, there appear to be a number of impact analyses, public disclosures, and other administrative requirements that have not been adequately addressed in proposing the Plan. These concerns are outlined below.

12.1.1 The Plan was Proposed without Adequate Notice

Section 2001.024 of the Administrative Procedures Act ("APA") requires adequate notice of a proposed rule, including information about its public benefits and costs. Tex. Gov't Code Ann. § 2001.024. Adequate notice is essential for fairness as well as a meaningful opportunity to comment on a proposed rule. Courts have considered notice "adequate" only if: (1) interested persons can confront the agency's factual suppositions and policy preconceptions, and (2) the agency provides interested parties the opportunity to challenge the underlying factual data relied upon by the agency. See Unified Loans, Inc. v. Pettijohn, 955 S.W.2d 649, 651 (Tex. App.—Austin 1997); Chemical Mfrs. Ass'n v. U. S. EPA, 870 F.2d 177, 200 (5th Cir. 1989). In proposing the Plan, TNRCC failed to provide interested parties with sufficient information to constitute adequate notice.

(a) Data Gaps in the Proposal Hindered Effective Comment

A number of critical gaps have been identified in the underlying factual data, methodology and analysis made available to date by TNRCC in support of the Plan. TNRCC has not adequately responded to requests for additional information from stakeholders regarding these gaps. By way of example, the following requests for information from interested BCCA members are still outstanding:

Information regarding the modeling of emissions.

Information regarding the corrected emissions inventory database.

Information supporting the estimated costs of control.

BCCA members need the required information in order to comment effectively on the Plan.

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(b) Inaccurate Cost Estimates Misled the Public

Aside from its data gaps, the proposed rule preamble also appears short of adequate notice due to the fundamental inaccuracy of the Plan's cost estimates. The available information suggests that the cost estimates presented to the public in the preamble are dramatically underestimated. The following examples illustrate this problem:

Actual point source capital costs that would result from the Plan were in some instances 10-15 times the capital costs used in calculating the dollar-per-ton estimates presented in the preamble.

Presenting a single average cost-per-ton figure for each point source category, instead of a range, masked the extremely high costs faced by some source categories.

The Plan's low emission diesel ("LED") rules require the use of LED fuel for both on-road and non-road use. However, there was apparently no consideration of the cost of the LED program on operators of non-road diesel equipment.

There was no stated basis for the estimate that only 10 percent of the current inspection stations in Harris County would need to purchase new emission testing equipment in order to conduct the proposed new vehicle emission testing method.

In connection with the Plan's diesel emulsion fuel ("DEF") program, several potential costs were apparently not considered, including lost sales to the petroleum industry as diesel emulsions replace approximately 20 percent of the diesel fuel with water, and the need for distributors to purchase additional storage tanks and storage tank agitators.

TNRCC provided no basis for its estimate that retrofit devices for gasoline or diesel engine exhaust systems would range between $500 to $2,000 per piece of equipment. Estimates obtained by the regulated community suggest that retrofit costs might exceed $40,000 per piece of equipment.

The proposed rule preamble states (without further explanation) that its cost estimates for controlling many point sources were "derived" from certain cost models. 25 Tex. Reg. at 8288-8293. As noted above, BCCA members have sought further information about how costs were "derived." However, even TNRCC has acknowledged that its estimates may have been low: "[T]here may be individual sources for which the equipment actual control costs are higher than the ones identified in this cost note." Id. at 8288.

In proposing the Plan, TNRCC published insufficient information and analysis regarding costs and impacts. The agency has not been completely responsive to stakeholder requests for information necessary to comment effectively. However, the available information suggests that

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TNRCC dramatically underestimated the costs of the proposed control strategies. This failure to provide the public with sufficient information renders the notice of the Plan inadequate. See Unified Loans, supra. Section 2001.024 of the APA requires that TNRCC provide sufficient information regarding the Plan for public review and comment before adoption.

12.1.2 The Plan was Proposed without a Regulatory Impact Analysis

Section 2001.0225 of the APA requires a Regulatory Impact Analysis ("RIA") for certain "major environmental rules." Tex. Gov't Code Ann. § 2001.0225. As part of the required analysis, TNRCC must consider the benefits and costs of the proposed rule in relationship to state agencies, local governments, the public, the regulated community, and the environment. TNRCC must also incorporate aspects of this analysis into the fiscal note in the proposed rules (e.g., identify the costs and the benefits; describe reasonable alternative methods for achieving the purpose of the rule considered by the agency; provide the reasons for rejecting those alternatives; and identify the data and methodology used in performing the analysis). The agency must also find that "compared to the alternative proposals considered and rejected, the rule will result in the best combination of effectiveness in obtaining the desired results and of economic costs not materially greater than the costs of any alternative regulatory method considered." Id. § 2001.0225(d).

In proposing the Plan, TNRCC asserted that the rules are exempt from the RIA requirement because federal law mandates the rules. TNRCC's effort to avoid an RIA is legally flawed, and may render the rules invalid. Federal law does not mandate the unprecedented control requirements, emission rates and use restrictions contained in the Plan. Many of the proposed rules exceed specific federal rules and standards applicable to the same sources. The following aspects of the Plan illustrate, by way of example, its departures from the federal framework:

Boiler, turbine and other fired equipment emission limits set well below federal NSPS, RACT, BACT or LAER limits for the same sources;

Compressor engine emission limits set at unprecedented low levels specifically designed to be unachievable and prevent the further use of the affected engines;

Fuel sulfur requirements set at 15 ppm, below recent federal rules specifically setting higher limits on the same fuels;

Unique hours restrictions on construction and lawn care activities, of a type never imposed under EPA's authority;

Experimental fuel/water blending rules and air conditioner technology requirements never contemplated under any federal program; and

A diesel engine control equipment retrofit mandate found nowhere in, and possibly inconsistent with, federal law.

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In its determination not to perform an RIA in the proposed rule preamble, TNRCC acknowledges that the Plan's components are "major environmental rules," but opined that an RIA is "seldom" required and is only required for "extraordinary" rules, although these criteria appear nowhere in the RIA requirements. The preamble determination concludes that, "[w]hile 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." 25 Tex. Reg. at 8249. This "no greater than is necessary or appropriate" determination is precisely the conclusion that an RIA is designed to evaluate and to offer for public review and comment. The Plan components are well beyond any federal mandates for the covered sources, and are certainly "extraordinary." Under Section 2001.0225 of the APA, an RIA must be performed and offered for public comment before the Plan can be finally adopted.

12.1.3 The Plan was Proposed without an Adequate Takings Impact Assessment

Section 2007 of the Private Real Property Rights Preservation Act requires an agency to prepare a written Takings Impact Assessment ("TIA") when proposing a rule. Tex. Gov't Code Ann. § 2007. The TIA provision mandates that covered agencies "take a 'hard look' at the private real property implications of the actions they undertake. . . ." Office of the Attorney General, Private Real Property Rights Preservation Act Guidelines, 21 Tex. Reg. 387 (Jan. 12, 1996) (the "AG Guidelines"). A TIA must describe the specific purpose of the proposed action determine whether engaging in the proposed governmental action will constitute a taking and describe reasonable alternative actions that could accomplish the specified purpose. The agency must also explain whether these alternative actions also would constitute takings. Tex. Gov't Code Ann. § 2007.043.

Agencies must also comply with guidelines developed by the Texas Attorney General when developing the TIA. According to these guidelines, agencies must carefully review governmental actions that have a significant impact on the owner's economic interest. "Although a reduction in property value alone may not be a 'taking,' a severe reduction in property value often indicates a reduction or elimination of reasonably profitable uses." AG Guidelines, 21 Tex. Reg. at 392.

The following aspects of the Plan, by way of example, could significantly impact private real property in a manner that constitutes a taking:

Gas-Fired Compressor Engines. TNRCC acknowledged that retrofitting compressor engines to the level specified in the Plan is infeasible. 25 Tex. Reg. 8137, 8291. The existing equipment, a significant capital improvement at a number of industrial sites, would be rendered unusable.

Other Point Source NOX Controls. As noted elsewhere in these comments, the 90-plus percent point source reduction requirement of the Plan is economically and technologically infeasible for a number of existing sites. This requirement

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could cause a number of facilities to shut down their operations, dramatically impacting the value of their real property.

Accelerated Purchase of Tier 2/Tier 3 Nonroad Equipment. The Accelerated Purchase rule requires the use of Tier 2/Tier 3 equipment by 2007. The existing equipment would be rendered unusable.

Airport Ground Support Equipment ("GSE"). TNRCC acknowledged that retrofitting GSE to satisfy a 90 percent reduction requirement is infeasible. Id. at 8137, 8225-8226. There could be real property value impacts associated with replacing the equipment with electrified equipment.

Construction Hour Ban. TNRCC's ban on the use of construction equipment between the hours of 6 a.m. and 12 noon could amount to a 25 percent reduction in productivity at businesses using covered equipment. This ban would likely result in a dramatic reduction in property value at these sites.

In the proposed rule preamble, TNRCC acknowledged that some of the rules may "burden" private real property ( e.g. LED fuel, LSG fuel, DEF fuel, GSE, point sources), but asserted an exemption from performing a TIA based on the assertion that the Plan does not impose a greater burden than necessary to advance a health and safety purpose and that the Plan "reasonably" fulfills a federal mandate. Id. at 8175, 8194, 8201, 8208, 8220, 8228, 8237, 8245, 8294 and 8295. However, TNRCC provided the public no basis to infer that a cost/benefit analysis or a reasonableness determination was, in fact, performed as necessary to support the agency's exemption claim. The preamble contains only the bare assertions. In fact, the Plan, if adopted as proposed, will impose a greater burden than is necessary, and is not "reasonably" taken to fulfill a federal mandate, as noted above. Tex. Gov't Code Ann. § 2007.003(a). Therefore, pursuant to the AG Guidelines, a full TIA was required to be completed with the Plan's proposal. Failure to perform a TIA could invalidate the Plan.

12.1.4 The Plan was Proposed without an Adequate Small and Micro-Business Assessment

In proposing a rule, Texas law requires a state agency to include a statement analyzing the costs of compliance for small and micro-businesses. Tex. Gov't Code Ann. § 2006.002. This statement must also compare the costs of compliance for these businesses with the costs for the largest businesses affected by the rule. The comparison must use at least one of the following standards: cost for each employee, cost for each hour of labor, or cost for each $100 of sales. Id. In Proposing the Plan, TNRCC failed to include such comparisons.

None of the Plan’s Small and Micro-Business Assessments applied the mandated cost comparison standards. This is the case even in those instances where TNRCC acknowledged a "significant" impact. The agency either restated the costs of compliance it identified in the Plan’s analyses of public benefits and costs, or concluded that it cannot determine the cost to

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small businesses. The following examples illustrate this defect:

Heavy Equipment Fleets Compression Ignition Systems. "The Commission anticipates significant fiscal implications to small businesses . . . [but] costs will be similar to those for businesses at large. . . ." 25 Tex. Reg. at 8236.

NOX Point Source Controls: “[T]he estimated capital and annualized cost of installing and operating control technology used for the various types of equipment in [the rule’s] fiscal note would appear to be a reasonable cost estimate for small and micro-businesses.” Id. at 8293.

Vehicle Inspection and Maintenance. “[T]he costs indicated in the public benefit portion of the fiscal note. . . will apply to small and micro-businesses.” Id. at 8184.

Construction Equipment Operating Restrictions. "Small and micro-businesses within the HGA ozone nonattainment area that have on-going construction projects may have significant fiscal implications as a result of enforcement and administration of the proposed rules in an amount which cannot be determined." Id. at 8244.

The Plan's assessments fall short of what Texas law requires. It is not sufficient for the agency merely to state that the costs for small and large businesses will be the same. The rationale behind requiring a comparison using an established standard (e.g., cost for each employee, cost for each hour of labor, or cost for each $100 of sales) is to determine whether there is a disparate impact on small businesses. Unified Loans, 955 S.W.2d at 652 (the statute's purpose is to obtain "an objective assessment of the agency's proposed action by forcing it to consider seriously. . . the effect of the rule on small businesses, including an analysis of their costs of [compliance] and a comparison of their costs with the cost of compliance for the largest businesses affected. . .."). Furthermore, the agency cannot merely conclude that the costs to small businesses "cannot be determined." TNRCC is obliged to include in the notice "some basis" for its conclusion so that interested parties can "confront that basis in a meaningful way in their comments." Id. at 653.

In proposing the Plan, TNRCC did not publish the information mandated by Texas law. As a result, it is impossible for the public to comment on whether the agency adequately considered the effect of the rule on small businesses. This failure to provide the required information renders the notice of the plan inadequate. Section 2006.002 of the Texas Government Code requires that TNRCC provide a comparison of the Plan’s impact on small and large businesses, using the specified standards, for public review and comment before adoption.

12.1.5 The Plan was Proposed without a Local Employment Impact Statement

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Section 2001.022 of the APA requires that TNRCC determine whether the Plan has the potential to affect a local economy before proposing the rule for adoption. Tex. Gov't Code Ann. § 2001.022. If answered affirmatively, TNRCC must request that the Texas Employment Commission prepare a local employment impact statement describing in detail the probable effect of the rule on employment in each geographic area affected by the rule for each year of the first five years that the rule will be in effect.

TNRCC failed to make the required initial determination, apparently ignoring that there is a great potential for the Plan to adversely affect the local economy. A local employment impact statement should have been requested and prepared in advance of the Plan's proposal.

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Section 13: Index of Comments

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Index of Comments

The BCCA requests a specific, detailed response to the following comments which are highlighted in the accompanying full text.

1.0 Point Source Control Strategies

1.1 Introduction

Most of the emission limitations have been developed with a less that complete analysis of the technical or economic feasibility of the resulting controls, or an analysis of the possible environmental or economic dis-benefit of the proposed controls. The TNRCC appears to have first established an arbitrary NOx reduction target for point sources (i.e., 90%) and, through an iterative process, back calculated emission rate limitations necessary to achieve the desired target. This is an arbitrary approach to establishing air pollution standards, and circumvents the intent established in the Texas Clean Air Act to establish standard based on a technological and economical review of available control measures.

1.2 Overview of Proposed Point Source Control Measures

The NOx SIP point source proposed rule package preamble shows an absence of valid, current and adequate scientific and technical support for the proposed NOx reduction targets and implementation timing. There is no discussion indicating the use of actual industry or vendor retrofit experience which would otherwise precede a determination that the proposed NOx reduction target is broadly achievable for all point sources categories. There is no discussion or consideration of design and implementation timing issues, which will impact the technological and economic feasibility of the required technology applications.

Although technology has advanced in recent years, there is no one demonstrated, commercialized, retrofit technology application today to achieve the 90 percent NOx reduction target for the point source category. There are other steps that must be taken to achieve the 90% reduction target such as wholesale replacement of sources, consolidation of sources to reduce fuel firing, and shutdown of marginally economic equipment and plants. However, the Coalition does not believe such steps are technologically or economically based emission control standards, nor has the TNRCC considered the cost and regional economic impacts associated with such steps.

Both combustion control improvements and post combustion retrofit controls have technological limitations that reduce their potential effectiveness in achieving the desired emission reduction targets.

For all of the HGA point source categories, there is no experience with retrofit NOx control technology applications that have been demonstrated to perform at the levels proposed by the

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TNRCC. TNRCC has not allowed for sufficient time for the necessary technology developments with the proposed year-end 2004 implementation deadline.

A 90 percent NOx reduction target effectively eliminates the ability to create surplus point source emission reduction credits under the proposed Cap-and-Trade program to permit future business expansion in the region. TNRCC has not considered the regional economic consequences of this "no future growth" plan.

The proposed year-end 2004 implementation timing does not recognize the magnitude of manpower and material resources required to implement the proposed rule, and does not allow for the practical implementation of controls. In short, a year-end 2004 implementation deadline is not physically possible.

The proposed Chapter 117 NOx standards are technologically infeasible and have no proven performance experience upon which to base a reasonable and technically viable regulatory program.

TNRCC's proposed emission limits will be unachievable by combustion retrofits for many sources and will require extensive implementation of SCR on an unprecedented and untested scale.

A review of worldwide retrofit experience found no equipment designed for and meeting emission standards as stringent as the TNRCC's proposed rule.

This very limited retrofit experience would not even qualify SCR as a MACT standard for air toxics and is therefore not sufficiently broad for industry to apply and extend confidently across all the regulated sources in the HGA under Reasonably Available Control Technology (RACT) standards.

1.3 On-Going Efforts to Define Technical and Economic Feasibility

1.3.1 Resource Supply and Demand




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Highly specialized labor resources, such as furnace engineering evaluation specialists and flue-gas computational fluid dynamics modelers are expected to be in short in supply and a critical path limitation to timely completion of engineering design activities.



1.3.2 Ethylene and Polyethylene Production Capability

A SIP implementation deadline of 2004 will effectively decrease the Ethylene industry capacity by 2.8% and cost the Houston-Galveston area ethylene plant operators $330 million dollars in lost sales during the implementation period of 2003-2004 when construction would take place. This product loss will add $1.65 million dollars, on average, to the cost of each Ethylene Plant furnace SCR retrofit.

1.4 Options for Reducing NOx

There is no evidence in the proposed rule that the TNRCC has weighed and analyzed the costs and technical feasibility of these potential control options that operators will be required to use to reach NOx reduction targets.

1.4.1 Application of Retrofit Control Technology on Existing Equipment

Technologies for reducing NOx emissions are available for a wide range of processes and combustion devices. However, these technologies alone will not produce a 90 percent reduction in NOx emissions.

1.4.3 Shutdown Existing Equipment

There will be instances where the direct application of retrofit technology will not meet the desired NOx emission targets and where replacement and consolidation of existing equipment will not be economically feasible. In those instances, the shutdown of equipment must be considered as the last remaining viable measure to meet the NOx reduction.

1.5 Developing a Technologically and Economically Feasible SIP

BCCA proposes that TNRCC establish point source a NOx standard comparable to the

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technology forcing rules being deployed in the SCAQMD.

BCCA proposes that the SIP implementation t iming be more consistent with normal process unit turnaround cycles and the availability of manpower and material resources. This will dramatically improve the cost effectiveness of proposed rule and minimizing the potential for product disruption, supply shortages and consumer price increases.

BCCA proposes that TNRCC consider establishing a partnership with the regulated community to develop technologically feasible standards for point source types which have very few, of any, NOx retrofit applications in the United States. An example of these sources includes ethylene plant pyrolysis furnaces, lean-burn internal combustion engines, hydrogen generation reactor furnaces, BIF and other incinerators, and Fluidized Catalytic Cracking (FCC) units.


TNRCC has proposed emission reduction targets for utility boiler and turbine applications (see Table 3) that are technically infeasible, exceed levels commonly achieved in practice, or are economically infeasible in wide-scale retrofit applications.

1.6.2 Utility Boilers

Although the proposed rate can be achieved in limited applications, the rate is technically infeasible and economically unreasonable for many gas-fired boilers.

The proposed emission reduction target of 0.01 lb/MMBtu for auxiliary boilers is technically infeasible and economically unreasonable for this source category. Consequently, for most of the operating schedule, flue gas temperatures will be well below conventional SCR operating temperature requirements, preventing effective NOx reduction.

1.6.3 Gas Turbines

Furthermore, the retrofit of combustion controls and SCR is not economically reasonable for certain low-capacity factor applications. For this reason, a number of local air districts in Southern California have regulations which allow for lesser NOx control requirements for gas turbines with limited operation TNRCC should consider the approach used in SCAQMD Rule 1134 which recognizes retrofit consideration issues associated with gas turbines of different sizes and applications. For instance, exemptions are provided for low capacity factor turbines, laboratory gas turbine units used in research and testing. Exemptions are also provided for gas turbine units operated exclusively for fire fighting and/or flood control, chemical processing gas turbine units, emergency standby and peaking gas turbine units demonstrated to operate less than 200 hours per calendar year, existing gas turbine units rated below 4 MW and operate less than 877 hours per year, etc. Tiered standards for gas turbines in the SCAQMD are provided in Table 4:

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1.7.1(b) Post-Combustion Control Technology

The experience in application of selective catalytic reduction technology in retrofit applications of existing combustion units is very limited, and in come combustion applications has never been attemptedIf SCR is applied in under less than optimum design and operation conditions, the NOx control efficiency will drop below TNRCC's assumed control efficiency range. TNRCC has not adequately addressed this issue.

Post-combustion control technologies have not been applied successfully in a number of combustion source applications. TNRCC failed to take this worldwide lack of experience into account when setting the emission limits in the proposed rule.


TNRCC has proposed emission reduction targets (see Table 4) for certain industrial, commercial, and institutional combustion sources that are not technically achievable or economically feasible in wide-scale retrofit applications.

1.7.3 ICI Boilers, Heaters and Furnaces

Unless space is available in the proper temperature zone of the heat recovery system, major system modifications must be made to accommodate the SCR retrofit. In some installations, there can be significant engineering obstacles to changing the design of the heat recovery system while maintaining system efficiency. A reduction in system efficiency increases the overall long-term cost of the NOx control step.

The time required to perform SCR retrofits may extend the normal process downtime and result in additional production losses. TNRCC has not adequately addressed these issues in their analysis of technical feasibility and cost. The addition of the SCR reactor to the flue gas path will increase pressure drop, which will reduce the firing rate if the loss is not compensated for through the addition of fans (either larger or new) to educt the hot flue-gas through the SCR catalyst bed. This will result in additional load on the site infrastructure, both electrical and steam production.

1.7.4 ICI Turbines and Duct Burners

Gas turbines can be found in utility plants, industrial plants, and remote pipeline transmission sites, with each location, and in may cases each machine, having its own unique design and operating conditions that needs to be considered when determining the feasibility and cost of a particular NOx reduction technology. For example, steam and/or water and low NOx combustion hardware is not currently available from some manufacturers, narrowing the owners’ technology options. The combustion control technology for many models of gas turbines is still

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being improved and new technologies, such as catalytic burners, are being developed but are not yet in commercial application.

Mandating such stringent proposed ESADs for turbines may preclude the use of emerging combustion technologies that may achieve SCR like NOx reduction performance levels without the adverse environmental impact of ammonia.

In some installations, there can be significant engineering obstacles to changing the design of the heat recovery system while maintaining system efficiency. A reduction in system efficiency increases the overall long-term cost of the NOx control step.

The time required to perform SCR retrofits will extend the normal turbine downtime and result in additional production losses. Such production losses are not typically experienced with combustion hardware changes, which can generally be done during normal major turnarounds.

The backpressure increase for an SCR retrofit installation can be significant, increasing the overall turbine heat rate and subsequent loss in output. The loss in output must be compensated for, or production loss can occur.

Catalytic burners, an emerging technology for new gas turbines, have the potential to reduce NOx levels as low as SCR systems with no ammonia slip, and will likely be significantly lower in cost

The TNRCC has not adequately addressed these issues in their analysis of technical feasibility and cost.

1.7.5 Internal Combustion Engines

The preamble does not explain why IC engines were singled out as a source category for wholesale replacement

Economic feasibility of replacement was based on limited data.

The preamble does not provide sufficient information to adequately analyze alternative approaches.

Alternative Control Techniques Document -- NOx Emissions from Stationary Reciprocating Internal Combustion Engines. Test data with such variation over such a small sample is inadequate to support a decision to impose wide-scale retrofit of SCR technology on lean-burn engines.

1.7.6 Other Sources

There is no technical analysis presented by TNRCC to describe the

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technical and economic feasibility of the proposed retrofit limits for Refinery FCC unit sources, Incinerators, Dryers, Pulping Recovery Furnaces, Steel Furnaces, Kilns or other sources.

.8 Use of Ammonia-Based Technology

1.8.1 Adverse Effects of Increased Ammonia Emissions

Under this assumption, ammonia emissions in the 8-county HGA would increase approximately 31.5 tons per day or approximately 23 million pounds per year. This increase in emissions will bring some of Houston-Galveston area counties to the top of EPA's Toxic Release Inventory list for ammonia.

Based on recent data in the EPA's Toxic Release Inventory (TRI), TNRCC's proposed point source control plan would increase ammonia from point sources in Harris County by up to an order of magnitude.

In the Houston-Galveston Area, full neutralization of the sulfuric acid could lead to an increase in ambient fine particulate matter of 0.2 to 0.5 micrograms per cubic meter (ug/m3).

In summary, the projected ammonia releases associated with proposed SIP NOx controls could add 0.2-0.5 ug/m3 to ambient particulate matter in the HGA. Increasing the mass of particulate matter in the atmosphere would drive the HGA closer to violating the pending National Ambient Air Quality Standard (NAAQS) for fine particulate matter (i.e., PM2.5). It is incumbent that TNRCC fully assess the benefits (e.g., lower ozone) and potential risk (e.g., higher particulates) of requiring NOx control technologies that significantly increase ammonia emissions.

1.8.2 Increased Risk of Ammonia Storage and Handling

It is estimated that under the proposed TNRCC point source control strategy, ammonia usage in the HGA will increase by 330 tons per day, or over 240 million pounds per year. The transportation, handling, storage, and use of such bulk quantities of ammonia throughout the HGA increases the risk of accidental releases. Before mandating the widespread use of ammonia-based NOx control technologies, the TNRCC should assess the overall regional risk of introducing these new major quantities of ammonia in the HGA relative to the NOx/ozone reduction benefit derived from the controls.

2.0 Texas Clean Fuels

2.2.1 Higher Market Risk of the Proposed LSG Rule

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It is highly likely that some refiners in the region will not make the necessary investments to produce Texas LSG for technical, financial, or market-based reasons. This will result in a reduction in the number of fuel suppliers and the available supply of fuels to the Texas boutique fuel market.

As a result of these investment risks, some refiners may choose not to make investments for Texas LSG and make only EPA Tier 2 fuels for marketing nationwide. Other refiners may close or consolidate their Texas operations if the necessary investments are unprofitable and if there are no viable alternative strategies.

The TNRCC proposals calls for the simultaneous design, engineering, and construction of both cleaner gasoline and diesel for Texas during the same period refiners are trying to bring federal fuels to market. Additionally, these clean fuel projects overlap significant stationary point source NOx reduction efforts that will compete with the same design, engineering, and construction resources as the fuel projects in the HGA.

In summary, the scope and breadth of national and Texas environmental requirements will severely limit the ability of refiners to make the necessary clean fuel upgrades by the TNRCC proposed deadline.

2.2.2 Higher Production Costs for the Proposed Texas LSG

TNRCC has significantly underestimated the production cost for the proposed Texas LSG by basing production cost estimates on the much less stringent EPA Tier 2 gasoline regulations.

BCCA estimates that the cost to produce the new Texas LSG, with an additional 75% reduction in sulfur level, could be as much as 3 times the cost of EPA Tier 2 gasoline. This estimate is based on the extremely low sulfur specification for Texas LSG and the required use of high-pressure hydrotreating on more gasoline component streams.

2.2.3 Virtually No Additional Environmental Benefits for Texas LSG

The Coalition estimates that the incremental cost to achieve the 1.15 tpd NOx reduction is over $400,000 per ton. The Coalition believes that, given the high cost and low environmental benefits of the proposed Texas LSG, the TNRCC should not adopt the proposed fuel and maintain Texas gasoline standards consistent with EPA Tier 2 standards.

2.2.4 Insufficient Time to Implement the Texas LSG Rule

The TNRCC has proposed that Texas LSG be in the market place by 5/04. Assuming a final rule is adopted by year-end 2000, this provides about 3 years for industry to design, engineer, permit, procure equipment, construct, and begin production of the new fuel.

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As noted in Section 2.2.1, the National Petroleum Council study, and the independent study by the Fluor Daniel Company, have indicated there will be a significant shortfall in the manpower, material, and equipment resources to simultaneously deliver EPA Tier 2 gasoline, Texas LSG gasoline, and the HGA point source NOx reduction projects. These shortfalls will be worsen by demand for similar manpower, material, and equipment resources in other ozone non-attainment areas and the OTAG NOx SIP Call and SIPs for other ozone non-attainment areas across the country. These projected shortfalls in critical project resources will place the HGA in an untenable compliance situation.

EPA's Tier 2 gasoline provides comparable NOx reduction benefits to the proposed Texas LSG at a much lower cost to the motoring public.


TNRCC has not assessed the potential impacts of creating special fuels for Texas on the existing fuel distribution system. The proposed Texas LSG rule will create four additional grades of gasoline to be blended and distributed through systems that are already stretched beyond design.

Additionally, there are serious and real concerns that it will not be possible to consistently maintain an ample supply of a 15 ppm sulfur cap product to the market place while significantly higher sulfur products are being shipped in the same fuel distribution and delivery system.

The TNRCC has not assessed whether or not the 15 ppm sulfur cap LSG product can actually be delivered to a retail station while still maintaining the sulfur integrity of the product from refinery tanks, through pipeline shipments to remote distribution terminals, through transfers to transport trucks to retail underground storage, and finally to the consumer.


TNRCC has not presented adequate technical or scientific information such as photochemical modeling, to demonstrate that there is any incremental measurable ozone reduction benefit to the HGA associated with the proposed Texas LSG verses EPA Tier 2 Gasoline when applied to attainment areas.

2.2.7 The Proposed Texas LSG is not Legally Defensible

The BCCA believes that the proposed LSG rule meets the definition of a major environmental rule, and that the RIA requirements of TGC §2001.0225 are triggered because the proposed rule: (1) exceeds standards set by federal law, and (2) exceeds an express requirement of state law.

Section 211(c)(4) preempts states from imposing any fuel controls that are

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related to, or connected with, any fuel characteristic regulated by EPA under section 211(c)(1). TNRCC's proposed sulfur control for Texas Low Sulfur Gasoline would be a fuel control related to, or connected with, EPA's fuel NOx control program and as such is preempted by 211(c)(1) of the Clean Air Act.

2.2.8 Other Gasoline Issues

The Commission does not adequately evaluated fiscal implications on small business or micro-business as a result of administration or enforcement of the proposed new fuels.

2.3.2 Higher Production Costs for the Proposed Texas LED Rule

From the CARB diesel market place experience, we would expect that the production cost of Texas LED 2002 fuel to be in the same league as CARB diesel, or about 9 cents/gallon, since the two fuel specifications are similar.

Overall we estimate the production cost to go from the 500 ppm sulfur 2002 Texas LED to the 15 ppm sulfur Texas LED in 2006 will be comparable to the cost to produce the proposed federal ultra-low sulfur diesel (15 ppm sulfur), or about $0.10 per gallon. Therefore, unless there is a desulfurization technology break through, or new refining process synergies developed, the combined cost for the Texas LED program in the year 2006 is estimated to be over 2 times higher than the TNRCC estimate of $0.08 per gallon.

2.3.3 Virtually No Additional Environmental Benefits for Texas LED

The TNRCC has overestimated the NOx reduction benefits for Texas LED.

2.3.4 Insufficient Time to Implement the Texas LED Rule

The TNRCC has proposed that the first phase of Texas LED be in the market place by 5/02, with ultra low sulfur levels due by 5/04. Assuming a final rule is adopted by year-end 2000, this provides about 1 year for industry to design, engineer, permit, procure equipment, construct, and begin production of the new fuel.


The proposed Texas LED rule will create an additional grade of diesel to be blended and distributed through systems that are already stretched beyond design. There are serious and real concerns that it will not be possible to blend and distribute the boutique fuels throughout Texas while providing the rest of the country with EPA specified fuels.

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The TNRCC has not assessed whether or not the 15 ppm sulfur cap LED product can actually be delivered to a retail station while still maintaining the sulfur integrity of the product from refinery tanks, through pipeline shipments to remote distribution terminals, through transfers to transport trucks to retail underground storage, and finally to the consumer.

2.3.7 The Proposed Texas LED is not Legally Defensible

The BCCA believes that the proposed Texas LED rule has a number of legal deficiencies that will ultimately result in protracted litigation and a delay in the delivery of cleaner fuels to Texas. Our comments here are again similar to those outlined in our comments on the LSG proposal in Section 2.2.7.

2.3.8 Other Diesel Issues

TNRCC should remove the aromatic and cetane specifications associated with the proposed Texas LED rule. These specifications are much less relevant when the new federal ultra-low sulfur diesel enters the market in 2006 followed by the low emission heavy-duty diesel engines in 2007.

2.4.1 Diesel Emulsion Fuel Is Not Commercially Available

Diesel emulsion fuel (DEF) is an emergent fuel technology 26 not currently mandated anywhere in the U.S. and not being used, other than in small pilot programs, anywhere else in the world.

TNRCC has not considered the long-term stability of water emulsions with diesel given the many applications and potential for long term storage of diesel products, particularly in non-road applications.

Additionally, the TNRCC has not taken into account the disruptions and handling impacts of broken emulsions in the market place.

2.4.2 DEF Technical Requirements are not Attainable

The only data TNRCC has supplied indicates that the greatest amount of NOx reduction (5%) achievable by a DEF, as compared to its baseline diesel fuel, is well below that being proposed NOx reduction requirements for both on-road (15%) and off-road (20%) engines under the rule. On this basis alone, the proposed rule appears to be technically infeasible.

Finally, vehicle performance and warranty is another subject that TNRCC has not considered. Mandating the use of an emergent fuel technology, prior to rigorous testing with Original Equipment Manufacturers, could result in voiding of engine and equipment warranties.

26 25 Texas Register 8197, Diesel Emulsion Fuel

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2.4.3 The Marketplace is Unlikely to Accept this Untested Fuel

While it may be too onerous for individual consumers to refuel outside the area, long haul trucking fleets, concerned with fuel economy and engine manufacturer warranties and guarantees, will probably elect to bypass this unproven fuel if at all possible.

2.4.4 Installation of New Equipment will be Costly

Not withstanding the other issues associated with supplying a LED fuel to the HGA area, there are costs associated with marketing and distributing DEF that TNRCC has not considered.

2.4.5 Enforcement, Quality Control, and Liability Issues are not Addressed

The proposed rule has no language to address enforcement, quality control, blender registration and operation, product labeling and liability. The TNRCC must address such issues as part of every rulemaking process. The proposed rule does not address how distributors and retailers, who do not plan to market DEF, can continue to sell diesel to classes of customers not affected by this rule.

2.4.6 Can TNRCC Mandate Retailers Offer this Fuel?

BCCA asks TNRCC to provide their legal basis for requiring that retailers offer this fuel.

2.4.7 Alternatives to the Proposed Texas Diesel Emulsion Fuel Mandate

While the proposed Texas DEF is still being evaluated, it is premature to include it as a mandatory fuel control measure in the SIP. Rather, DEF more properly belong to that group of potential emission reduction measures for use in a market based incentives program.

3.1 On-Road Control Strategies

As a general principle, the BCCA encourages the use of technologically-based programs whenever possible over use-restrictive strategies.

3.1.1 Speed Limit Reduction

The BCCA supports a speed limit reduction for those roadways where it has been demonstrated that emission reductions could be expected to occur due to reduced speeds. 3.1.2 Federal On-Road Vehicle Emissions Standards

The BCCA supports these new emission standards and encourages their early introduction into the Texas market. The BCCA suggests that TNRCC and EPA work with automakers and other

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interested parties on a voluntary agreement to introduce Tier II vehicles into the Texas market prior to national introduction.

3.1.3 Vehicle Inspection and Maintenance

The BCCA supports the program as proposed for the region, and further supports the phased-in implementation period. The BCCA believes that careful design and implementation of the program will be essential to its success in the region, and encourages the TNRCC to design flexibility into the final program for citizens and test facilities.

3.1.4 Vehicle Idling Standards

The BCCA supports a modification to the rule which would allow fleet owners and operators the flexibility to achieve equivalent or greater reductions from an emission reduction plan in lieu of compliance with the rule.

3.1.5 Voluntary Mobile Source Emissions Reduction Program (VMEP)

The BCCA believes that the emulsion and retrofit programs should be removed as mandatory measures from the SIP, and placed back into the VMEP category. Furthermore, the VMEP program should be closely tied to a voluntary incentive program (See Section 9 on Market-Based Incentives).

3.1.6 Transportation Control Measures

The BCCA supports these transportation control measures, and encourages the identification of others, especially in time for the mid-course correction.

3.2 Non-Road Mobile Source Control Strategies

3.2.1 Construction Hour Shift

The TNRCC lacks statutory authority to impose the workday shift on all the equipment covered by the rule. The residual air quality benefit does not pass the practical and economically feasible test that TNRCC rules must meet.

There is no specific statutory authority for imposition of the workday shift.

The TNRCC can only regulate emissions from engines that propel land vehicles.

The conclusion drawn is that any attempted regulation by TNRCC of equipment the movement of which is an incidental result of its engine is outside the authority of TNRCC. Adoption of such a regulation would exceed the authority of TNRCC.

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The remaining ozone reduction benefit is neither a practical nor economically feasible one. Whether the benefit is one, ½ or1/10 ppb of ozone reduction in modeled benefit, compared with the costs of the workday shift which is estimated at 450 million dollars annually (discussed below) neither passes the “practical and economically feasible” test required by Section 382.011(b).

A shift in the construction workday to commence at 12:00 noon or later will have adverse health and safety implications.

The adoption, as a matter of policy, of a rule that systematically exposes 458, 000 construction workers in this state to a risk that the balance of the population is encouraged to avoid is an unsupportable policy. It is an expression of preference for the health and safety of part of the population at the expense of the rest and inconsistent with the TNRCC’s mission to protect (all) public health and the environment.

The workday shift will have a great and adverse quality of life impact impact on workers in the construction industry who are significantly minority.

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If, as evidence discussed therein suggests, the construction workforce is predominately minority, additional burdens like a disruption in family life will disproportionately affect the minority community.

The proposed rule and the rulemaking process is procedurally defective because TNRCC erroneously concluded that adoption of the workday shift does not a regulatory impact analysis (RIA). This conclusion is erroneous because the workday shift exceeds express requirements of state law, is not specifically required by federal law and is adopted solely under the general powers of the agency.

The rule cannot be the subject of SIP credit for NOx reduction because it is a dispersion technique that is contrary to CAA Section 123.

The rule is preempted by the CAA Section 209. The CAA section 209 reserves to the EPA imposition of “...any standard or other requirement relating to the control of emissions...” of new or used nonroad engines. The workday shift is such an “other requirement” which is not available to a state except under the limited circumstance where California adopts such a requirement which is not the case.

The BCCA strongly supports, as a substitute for the workday shift (and the accelerated Tier II/Tier III purchase rule) an incentive-based program that will produce more cost-effective NOX reductions.

3.2.2 Accelerated Turnover of Tier II/Tier III Equipment

The Federal Clean Air Act Section 209(e)(1) and (2) in effect prohibits states from imposing standards and other requirements relating to the control of emissions on vehicles and engines.

The proposed TNRCC rule imposes a duty on owners and operators to have in place, engines that meet the Tier II/III standards on a schedule that is earlier that the federal standard. This imposes, effectively, a standard on those engines for the period in which the advanced engine would not be required under federal law and the accelerated schedule is clearly an “other requirement”. Therefore, the BCCA opposes this rule, and supports the formation of an emissions incentive reduction program, as described in Section 3.2.1 above, to achieve equal or greater reductions in this source category. The BCCA also urges EPA to accelerate the penetration of new engines into the Texas market.

3.2.3 Airport Ground Support Equipment

The BCCA supports the consensus agreement that has been reached on airport ground support equipment by Continental Airlines, the City of Houston, and the TNRCC. Furthermore, the BCCA encourages the TNRCC and EPA to use this agreement as a model of providing for significant emission reductions while allowing businesses needed flexibility.

3.2.4 California Spark Ignition Engine Standards

The BCCA supports this rule, and supports the listed exemptions for smaller agricultural and construction equipment, recreational equipment, stationary engines, marine vessels and equipment on tracks.

3.2.5 NOx Reduction Systems

The BCCA believes that a well-crafted voluntary mobile emission reduction program (VMEP) in conjunction with a market-based incentive program, could provide equal or greater emission reductions at a lower cost and with minimal disruption to the affected businesses. The BCCA recommends that the TNRCC adopt as a contingency rule a mass-cap emission limit for the non-road mobile source sector, and a similar limit for fleets as appropriate.

3.2.5 Lawn Service Equipment Operating Restrictions

The BCCA recommends that this rule be replaced by programs to achieve equal or greater reductions from this sector. First, the TNRCC should aggressively work with the EPA to develop and implement the next generation of lower-emitting lawn service equipment, and press for its early introduction into the Texas market. Second, because the primary ozone reduction benefits of this rule occur due to VOC reductions, the TNRCC should consider implementing a California rule which requires the sale of only low-spillage and evaporation gasoline cans in the state. Finally, the TNRCC should develop a program which provides for voluntary emission reduction incentives.

4.4 Other Control Measures

4.5 Residential and Commercial Air Conditioner Catalyst System

The BCCA believes that results to date show promise for the catalyst system, and that this verification process should continue. If the technology is proven to significantly reduce ambient ozone, the BCCA supports this control strategy.

The BCCA urges the TNRCC and the EPA to work with both the catalyst and air conditioner manufacturers, and to grant flexibility to both parties to achieve emission reductions.

Furthermore, should either of these two new technologies prove effective, the BCCA recommends that a voluntary retrofit or replacement program for residential and commercial air conditioners be included in an economic incentive program to encourage earlier penetration of these technologies into the eight-county region.

4.6 Energy Efficiencies

The BCCA encourages other municipalities in the eight-county region to enact similar ordinances. The BCCA also encourages the EPA and the TNRCC to provide technical guidance to smaller municipalities to facilitate the adoption and implementation of these ordinances.

4.7 City of Houston, Harris County, and Houston-Galveston Area Council Initiatives

The BCCA has been pleased to work as partners with the City, County, and HGAC, and encourages the EPA and the TNRCC to facilitate and allow local decision-making about SIP strategies to the greatest extent possible.

5.0 Federally Preempted Control Measures

5.1 Federal NOX Reductions should be Fully Incorporated

TNRCC should incorporate an appropriate level of federal reductions into the Plan, to restore its balance and to address the Plan's undue reliance on state-regulated sources.

The delays in effectively regulating federally preempted sources have prompted the TNRCC to propose technically and economically infeasible emission reductions from those sources in HGA that the state has authority to regulate, including point sources, to make up for the missing reductions. Additionally, these delays have forced the TNRCC to propose expensive regional fuels and significant "use restriction" regulations on the public and businesses in the terms of mandatory speed limit reductions, and a prohibition on the use of non-road heavy-duty diesel equipment and lawn service equipment in the morning hours.

HGA's situation warrants a flexible approach, due to both the uncertainties in acknowledging the role of NOX reductions, and EPA's delays in adequately controlling the federally preempted sources as required by the Act. TNRCC and EPA can ensure an equitable distribution of the compliance burdens necessary to achieve the mandated air quality improvement in HGA only by allowing the Plan to capture the anticipated emission reductions from federally preempted sources.

7.0 Proposed Cap and Trade Program

The cap and trade program should be strengthened.

6.1 A Viable Cap-and-Trade Depends on Feasible Reduction Levels

In order for the proposed cap-and-trade to function, NOX reductions required by the HGA SIP must be set at technologically and economically feasible levels for each source category, both new and retrofit.

6.2 The Cap-and-Trade should Afford a Five-Year Phase-in Period In other words, the necessary controls must be in place by year-end 2004 in order to meet the target allocations under the Proposal. This timeframe is neither practical nor feasible. The Proposal should be amended to incorporate a five-year phase-in period, beginning in 2002 and ending in 2007.

6.3 The Cap Allocation Methodology should be Strengthened

The proposal contains a number of ambiguities and inequities that would threaten its viability.

(a) The Baseline Activity Level Should be Derived from a 12-Month Average

BCCA believes that a consecutive 12-month period approach will more accurately reflect activity levels, and as a result will dramatically reduce the number and complexity of petitions for case-by-case review.

(b) Cap Reductions Should be Weighted Toward the Target Year

Instead, reductions from the initial to the target year should be weighted toward the target year.

(c) Allowances should be Allocated for 30 Future Years, not Year-by-Year

The proposed rule should be revised to provide for Cap Accounts to be credited their 2002 through 2032 vintage allowances at program inception.

(d) The Additional Definitions "Account" and "NOX Cap Plant" should be Incorporated

To eliminate ambiguity, the existing term "Account" (as defined in Section 101.1(1)) can be used in the applicability provision to define a covered location. BCCA recommends that existing terminology be avoided, and a flexible new definition be established. BCCA suggests, "NOX Cap Plant" to clearly distinguish its purpose and effect.

(e) Allocations Should be Fixed Despite Equipment Shutdowns or Changes

The Proposal suggests that allowances derived from baseline activity levels from 1997-1999 will be allocated to a NOX Cap Account, that this target allocation will be permanent, and that this target a llocation will not change, despite shutdowns, replacements or changes to the equipment whose baseline activity level and rates formed the basis for the target allocation. TNRCC should insert clarifying language in the final rule establishing this concept with more certainty.

(f) An Opt-in Mechanism Should be Incorporated for Non-ESAD Sources

In order to provide an effective incentive to accomplish these reductions, an opt-in provision should be incorporated into the Proposal.

(g) Modified, as well as New, Sources should be Granted Allocations at Permitted Levels.

The Proposal provides for sources not operating, but newly authorized by permit applications or permits-by-rule, to receive allocations at their permitted or actual activity levels. BCCA supports this approach. However, the current language ignores newly-modified sources. These sources should receive the same treatment as new sources in the allocation process. TNRCC should revise the language to harmonize the treatment of new and modified sources.

(h) The Allocation Methodology should be Simplified

The allocation methodology language in proposed Section 101.353 is overly complicated and confusing. The methodology is based on a complete re-allocation in each of the initial four years, and is structured to revisit allocations for new sources several times. As noted above, the methodology should allow all allocations for 2002 through 2032 to be issued in a single action before program commencement.

6.4 Open-Market Credits should be Fully Incorporated

Any cap-and-trade program must preserve the investment in existing emission credits.

(a) ERCs should be Creditable to Allowances

BCCA supports the ability to convert all types of recognized emission credits to allowances..

(b) The 10% Assessment should be Dropped for Credit Use in the Cap-and-Trade

The existing DERC trading rules require that a 10% environmental contribution and 5% compliance margin be added to each trade. BCCA believes that these deductions no longer add value for NOX trading intended to meet a fixed area-wide cap. Accordingly, the percentage reductions should be removed for DERCs used in lieu of cap-and-trade allowances.

6.5 Daily and 30-Day Limits should be Dropped for Sources Participating in the Cap-and-Trade

BCCA objects to the retention of daily and monthly NOX limits for utility sources in addition to the annual cap. TNRCC should adhere to the cap-and-trade as the sole compliance mechanism for covered stationary sources, and abandon the mandatory application of individual rate-based system caps.

6.6 Plantwide Applicability Limits should be Incorporated

BCCA believes that the cap-and-trade program should integrate with NSR by incorporating a Plantwide Applicability Limit ("PAL") in lieu of netting for changes under the cap.

6.7 The True-Up Period should be Extended to April 1

BCCA believes that one month is not sufficient time to calculate the past year's emissions, locate and contract for needed allowance trades, and have such trades registered with TNRCC. No environmental goal is served by advancing the true-up period. The true-up should be extended so that compliance is required by April 1 of the succeeding year, to conform to the annual Emission Inventory deadline.

6.8 Allowances Should be Divisible in Tenth Tons

Whole-ton rounding is also inconsistent with the existing open-market rules, under which ERCs are traded in tenth-ton increments. Like ERCs, allowances should be tradable in tenth-tons.

6.9 Enhanced Monitoring Should Await the Target Year

The new monitoring equipment should be installed by the year in which the target allocations begin under the cap-and-trade program ( i.e., 2007).

6.10 VOC Credits Should be Creditable Against NOX Allocations upon an Appropriate Demonstration

BCCA supports the inclusion of such a provision. The toxics, environmental "hotspot" and justice concerns typically associated with VOC/NOX trades are absent where VOC reductions are being traded against NOX requirements. BCCA supports a general provision allowing the use of VOC reductions in lieu of NOX allocations, upon an application demonstrating equivalency of ozone reductions.

6.11 The Economic Incentive Program should be Expanded and Strengthened

BCCA supports an incentive program designed to provide funds on a competitive basis to assist in the cost of emission reductions on the broadest range of source categories. If such a program relies on a private source of funding, it should provide appropriate credit or benefit to the parties providing the funding. In addition, BCCA supports an incentive program whereby any party could obtain appropriate credit for identifying and developing innovative emission reduction measures outside the framework of the existing incentive programs. The Plan should incorporate the broadest authority for the Executive Director to approve and credit such initiatives on a case-by-case basis.

7.0 SIP Implementation Issues 7.1 Background

TNRCC is not expected to have final control regulations promulgated until year end 2000, at which time facility operators will need 12-18 months to scope and design equipment, secure permits, perform detailed engineering, secure funding and begin the installation of controls. It will therefore, not be until 2002 that many companies will be in a position to begin control installation. This will leave only 3 years for some 180 companies to begin retrofitting over 2,000 individual pieces of equipment with the proposed control technology.

7.2 Impact of Proposed Deadline on Plant Maintenance

TNRCC must consider the impact of these unscheduled equipment shutdowns associated with the proposed SIP on the overall economy of the region.

7.3 Impact of Proposed Deadline on Permitting

It is expected that the use of ammonia in such controls will trigger more complex permitting requirements due to increased ammonia emissions, and will likely increase the pre-construction lead-time. This, in turn, shortens the total amount of time available to install the controls, resulting in more unscheduled equipment downtimes and economic burden to the region that must be considered in the selection of controls. TNRCC is encouraged to consider and authorized these more complex permitting activities through the rule-making process and not on a case-by-case basis.

7.4 Project Design and Engineering Considerations

There are many engineering challenges associated with the retrofit of existing combustion devices with flue-gas (Tier II) treatment technologies that add significantly to the cost of a NOx control project. Many of these challenges are identified in the engineering design phase of a project. The TNRCC must make every attempt to quantify these additional costs and include them in the economic analysis associated with the proposed SIP.

The availability of plot space for large flue-gas treatment catalyst beds in retrofit applications is a significant cost factor. In other words, in many retrofit applications, Tier II technology cannot simply be placed at the end of the flue-gas handling system, but must be designed and constructed to operate at the optimum point within the heat recovery system. Such equipment reconstruction adds significantly to the TIC and to the production downtime necessary to install the project.

In other retrofit applications, large flue-gas conveyance fans and associated equipment must be added or expanded to compensate for the increased pressure drop, significantly increasing the TIC of the project.

The heat input replacement cost or production loss associated with this control technology will significantly increase the overall cost of the NOx reduction project and should be included in the overall regional cost impact assessment.

TNRCC must assess and consider these potential project implementation constraints before determining regulatory standards and deadlines.

7.5 Projected Demand for Manpower and Material Resources

It is not known, at this time, if there are sufficient engineering resources to design Tier III retrofits for some 1,000 units in the HGA over this short time-period.

The increased demand in the HGA for Tier I control burners and Tier II flue-gas treatment catalyst will likely exceed current manufacturing capacity. The TNRCC should assure the supply availability of mandated technology when determining compliance deadlines.

Given the very compressed 3 year implementation window for these controls, it is likely that scores of plants could be planning to undergo NOx retrofit turnarounds simultaneously but not

be able to due to specialty labor and material shortages. Such resource supply constraints can add significantly to the overall construction period needed for region-wide NOx technology retrofits.

The general construction labor necessary to accommodate the major turnaround of some 180 plants over a 3 year period versus a more typical 5 year period may also add to the overall construction period needed for region-wide retrofits.

8.0 Emissions Incentives Reduction Programs

The BCCA supports the development of programs that provide incentives to reduce emissions from all sources that contribute to the region's NOx emissions.

8.1 Point Sources

8.1.1 Emissions Trading Program

Emission trading programs should be developed for all source categories (stationary, mobile, and non-road sources) that establish emission caps, emission rights, and a system of trading in those rights throughout the non-attainment area. However, the TNRCC must go further and establish similar programs for federally preempted mobile and non-road sources in order to achieve the emission reductions necessary for ozone attainment.

8.1.2 Shutdown Management Program

TNRCC should pursue agency/industrial partnerships to initiate the development of voluntary industrial standards for the scheduling of major industrial maintenance activities so that ozone precursor emissions are minimized during the ozone formation season.

8.1.3 Upset and Maintenance Emission Standards

TNRCC should pursue agency/industrial partnerships to develop a voluntary program to reduce upset and maintenance emissions.

8.2 On-Road Mobile Sources

8.2.1 Vehicle Retirement Program

The BCCA supports a voluntary vehicle scrappage program for the HGA that is based on the actual emissions of the retired vehicle, purchased for retirement at market-based prices.

8.2.2 Vehicle Repair and Retrofit Program

The TNRCC should pursue a voluntary program by which emission reduction credits would be generated from the repair or retrofit of high-emission vehicles.

8.2.3 Fleet Vehicle Repair and Replacement Program

The TNRCC should pursue a voluntary program with government and private owners of fleet vehicles (e.g., school buses, garbage trucks, police cars, and delivery trucks) for repair or replacement of engines to reduce emissions.

8.3 Non-Road and Equipment Programs

8.3.1 Vehicle and Equipment Scrappage Program

Similar to the on-road program described above, the BCCA encourages the TNRCC to pursue programs that generate voluntary credits, based on actual emissions and market prices, for the scrappage of non-road vehicles, engines, and equipment.

8.3.2 Vehicle and Equipment Repair, Replacement, and Retrofit Program

Similar to the on-road program described above, the TNRCC is encouraged to pursue programs that generate voluntary credits, based on actual emissions and market prices, for the repair, replacement and retrofit of non-road vehicles and equipment.

8.4 Implementation Issues

Therefore, the BCCA supports the establishment of a grant fund to cover the incremental cost, on a competitive basis, of projects that achieve the most cost-effective NOx reductions. The BCCA supports the policy recommendations of the “Incentive Fund for Early Smog Reduction” developed by the Texas Clean Air Working Group, of which it is a member. The BCCA encourages the TNRCC and EPA to use this program as a mechanism to obtain early, cost effective reductions in place of those proposed rules that are not technologically feasible or have unintended negative social and economic consequences.

10.0 Mid Course Evaluation

The BCCA supports a mid-course evaluation of the SIP to take place no later than the end of the year, 2003. This evaluation and adjustment should provide for a comprehensive scientific review of the model and other decision-making tools; should take into account new data collected from the TxAQS 2000 study; and evaluate new and emerging technologies.

The BCCA encourages the TNRCC to work closely with the recently announced "Texas Council on Environmental Technology" to ensure that new technologies developed by the program are incorporated in the SIP at the mid-course evaluation.

10.0 Cost of Controls and Implementation

10.2 Utility and ICI Combustion Units

TNRCC has estimated the total capital cost for affected sources in the HGA at approximately $2.7 billion. We believe this estimate is low by more than a factor of two. TNRCC has likely based most of the cost estimates for the proposed SIP on new, grass roots facilities that have been specifically designed for low NOx performance technology, as opposed to cost estimates for the retrofitting of equipment already in operation.


In summary, BCCA believes the TNRCC has underestimated the capital cost for point source Utility and ICI combustion unit NOx control technology retrofits by at least 2.5 billion dollars.

10.3 Turbines

10.3.1 General Information

The TNRCC Gas Turbine cost estimate of $2.1 million dollars per Turbine / HRSG ($403 million total for the HGA) underestimate retrofit costs for the region. We believe the EPA reference guide used does not adequately represent retrofit costs, but instead is more representative of the cost of new, grassroots SCR installations as noted in the reference document itself.

Based on the best engineering data available from BCCA member companies, it is estimated that the capital cost to achieve the desired NOx reduction target will be in the 800 - 1,200 Million dollar range, depending on the turbine design, power output and use.

10.5 Emission Monitoring Systems

Industry experience with installed retrofit costs under the TNRCC RACT I program was in the $350K - $400k range. We believe the number of new CEMS will be closer to 700, not 300. Based on industry experience of $350 thousand per installation, and 700 new instruments required, BCCA estimates the cost of new emission monitoring systems required by the proposed SIP to be $245 million dollars.

10.6 On-Road and Off-Road Fuels

BCCA estimates the capital cost to produce 522,000 B/D of proposed Texas LS gasoline for east/central Texas, with a 15 ppm sulfur cap, at approximately $2 billion.

10.6.2 Proposed Texas LED Costs

However, learning from the CARB diesel experience and recent estimates made by EPA and Charles Rivers Associates for very low sulfur diesel, it is estimated that the capital cost for state-wide 2002 LED will be $500 million. The estimated capital cost to produce the ultra-low 2006 LED for east/central Texas is $700 million.

12.0 Modeling of Attainment Control Strategies

The BCCA is very concerned about the model’s base case accuracy for this episode and its inability to quantitatively predict the emission reductions needed to attain the ozone NAAQS. Foremost of our concerns is the fact that the modeled peak ozone levels that are driving the extreme breadth and depth of TNRCC’s proposed control strategy are just an aberration of poor model performance that occurred in a relatively small area of the modeling domain.

11.2 Concerns about Model Performance on September 8, 1993

As the following paragraphs show, the predicted ozone maximum that TNRCC’s control strategy struggles to abate, in reality, never occurred in the time and place the model said it did.

In the August 2000 proposal, however, TNRCC simply cites the performance statistics in Table 3.3-4 as the basis for acceptable model performance and fails to acknowledge or take account of the unacceptable model performance in precisely the area that is requiring the most emission reductions needed to demonstrate modeled attainment.

However, TNRCC has not taken appropriate account of the graphical performance methods, such as the surface level isopleths and time series plots (as shown in Figures 1, 3, and 4), that its December 1998 modeling protocol says would be considered.

Therefore, a model that cannot accurately predict the location of the ozone peak probably will not accurately predict the benefits of future emission reductions.

If TNRCC and EPA Region VI have worked to address this concern, their efforts are not described in the August 2000 proposal and the latest model simulations show no evidence that they were successful.

Whether due to a poor representation of some component of the emissions inventory or due to poor performance of the meteorological model (as TNRCC suggested), the model’s inability to accurately simulate ozone levels in southern Harris County on September 8 cannot be ignored. The modeled peak that is driving the immensity of the proposed control strategy, in reality, never occurred in the place and time the model said it did.

11.2 Alternate “Controlling Days”

Due to the model’s gross inability to replicate the location of the ozone peak on September 8, the BCCA recommends that TNRCC choose an alternate day for estimating the magnitude of emission reductions needed to demonstrate modeled attainment. Therefore, we recommend that TNRCC estimate the magnitude of emission reductions needed for attainment from the modeling results for September 10 and 11.

11.2 Discussion

Despite model performance statistics that fall within EPA’s acceptance criteria, the model was unable to replicate the measured ozone levels in the areas where it counts the most – where the

highest levels were either modeled or monitored.

On three of the four episode days (September 8 – 10), the base case model underestimated ozone levels near the shores of Galveston Bay but overestimated ozone levels further inland, in south-central and southwestern Harris County. Yet, TNRCC has provided no explanation for this poor spatial representation nor has it provided any discussion of its impacts on the uncertainties of the proposed control strategy.

The TNRCC has presented no evidence that the model is accurately simulating NOx or VOC levels, or other intermediate chemical species in the vicinity of the modeled peaks.

The TNRCC and its contractors have worked commendably to develop what may be, in many respects, the most accurate emissions inventory ever used in photochemical modeling. But major uncertainties still exist in other respects and in the model’s representation of the chemical reactions and meteorological processes that determine the location, time, and magnitude of high ozone levels in Houston – Galveston.

These doubts regarding the accuracy of the model predictions support the BCCA’s recommendations that new emission controls be based on proven cost-effective technology and that stakeholders be given as much time to implement controls as the Clean Air Act allows.. The model simulations and basic science that are the foundations of TNRCC’s control strategy are currently not strong enough to support the unproven, technically infeasible, or economically – challenging measures in the proposal.

11.4 Recommendations

However, we believe that TNRCC must address the risk that the modeling uncertainties have led them to a wrong estimate of the magnitude of emission reductions needed to attain the ozone NAAQS.

The BCCA supports the recent contract commissioned by Harris County with Environ. This work will re-run the model with an alternate meteorological simulation model, in a final attempt to address the non-performance of the grid cells in question.

The BCCA believes the best way to manage the risks of making a wrong decision on the magnitude of the needed controls is to base Houston – Galveston’s control strategy on the modeling simulations that have the least uncertainty. Though all four days of the September 8 – 11, 1993 base case simulation are characterized by poor graphical performance, by far, the greatest uncertainties exist for September 8 and 9. Therefore, the BCCA believes that the control strategy should be based on modeling results for either September 10 or 11.

Evaluating Equations (3) and (4) for OC = 124.5 yields NOx attainment targets of 374 tons per day and 358 tons per day for September 10 and 11, respectively. This results in gaps of 21 tons per day and 37 tons per day, respectively, for September 10 and 11, which could be filled (with surplus) from the list of gap measures given in Table 6.1-2 of the proposal.

11.5 Supplemental Modeling

Note that the 91 tons per day increase in point source NOx emissions produced daily maximum ozone increases ranging from 1.5 ppb (on September 10) to 6.1 ppb (on September 11). Also, note that the 91 tons per day decrease in on road mobile and nonroad mobile source NOx

emissions produced ozone decreases, relative to HRM Strategy 1, ranging from 6.9 ppb (on September 11) to 10.8 ppb (on September 8). From this, we see relatively small benefits from TNRCC’s 90% point source control proposal relative to a 75% point control level but we see greater benefits if the same amount of incremental emissions was reduced from mobile sources.

Note that mobile source emission reductions ranged from 1.1 to 7.0 times more effective than point source NOx reductions at reducing ozone levels (given by the ratio of mobile source to point source NOx effectiveness). From this, it follows that mobile source NOx emission reductions are on average 3 times more effective at reducing ozone levels than are point source emission reductions.

12.0 Administrative Considerations of the Proposal

12.1 The Plan was Proposed without Adequate Notice and without Adequate Impacts AnalysesThere appear to be a number of impact analyses, public disclosures, and other administrative requirements that have not been adequately addressed in proposing the Plan.

12.1.1 The Plan was Proposed without Adequate Notice

In proposing the Plan, TNRCC failed to provide interested parties with sufficient information to constitute adequate notice.

(a) Data Gaps in the Proposal Hindered Effective Comment

A number of critical gaps have been identified in the underlying factual data, methodology and analysis made available to date by TNRCC in support of the Plan. TNRCC has not adequately responded to requests for additional information from stakeholders regarding these gaps.

(b) Inaccurate Cost Estimates Misled the Public

Aside from its data gaps, the proposed rule preamble also appears short of adequate notice due to the fundamental inaccuracy of the Plan's cost estimates.

In proposing the Plan, TNRCC published insufficient information and analysis regarding costs and impacts. The agency has not been completely responsive to stakeholder requests for information necessary to comment effectively.

12.1.2 The Plan was Proposed without a Regulatory Impact Analysis

In proposing the Plan, TNRCC asserted that the rules are exempt from the RIA requirement because federal law mandates the rules. TNRCC's effort to avoid an RIA is legally flawed, and may render the rules invalid. Under Section 2001.0225 of the APA, an RIA must be performed and offered for public comment before the Plan can be finally adopted.

12.1.3 The Plan was Proposed without an Adequate Takings Impact Assessment

In the proposed rule preamble, TNRCC acknowledged that some of the rules may "burden" private real property ( e.g. LED fuel, LSG fuel, DEF fuel, GSE, point sources), but asserted an exemption from performing a TIA based on the assertion that the Plan does not impose a greater burden than necessary to advance a health and safety purpose and that the Plan "reasonably" fulfills a federal mandate. TNRCC provided the public no basis to infer that a cost/benefit analysis or a reasonableness determination was, in fact, performed as necessary to support the agency's exemption claim. The preamble contains only the bare assertions. In fact, the Plan, if adopted as proposed, will impose a greater burden than is necessary, and is not "reasonably" taken to fulfill a federal mandate, as noted above. Therefore, pursuant to the AG Guidelines, a full TIA was required to be completed with the Plan's proposal. Failure to perform a TIA could invalidate the Plan.

12.1.4 The Plan was Proposed without an Adequate Small and Micro-Business Assessment

The Plan's assessments fall short of what Texas law requires. It is not sufficient for the agency merely to state that the costs for small and large businesses will be the same. Furthermore, the agency cannot merely conclude that the costs to small businesses "cannot be determined." TNRCC is obliged to include in the notice "some basis" for its conclusion so that interested parties can "confront that basis in a meaningful way in their comments."

In proposing the Plan, TNRCC did not publish the information mandated by Texas law. As a result, it is impossible for the public to comment on whether the agency adequately considered the effect of the rule on small businesses.

12.1.5 The Plan was Proposed without a Local Employment Impact Statement

TNRCC failed to make the required initial determination, apparently ignoring that there is a great potential for the Plan to adversely affect the local economy. A local employment impact statement should have been requested and prepared in advance of the Plan's proposal.

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