La. Admin. Code tit. 33 § III-2201

Current through Register Vol. 50, No. 11, November 20, 2024

Section III-2201 - Affected Facilities in the Baton Rouge Nonattainment Area and the Region of Influence

A. Applicability

1. The provisions of this Chapter shall apply to any affected facility in the Baton Rouge area (i.e., the entire parishes of Ascension, East Baton Rouge, Iberville, Livingston, and West Baton Rouge) and the region of influence (i.e., affected facilities in the attainment parishes of East Feliciana, Pointe Coupee, St. Helena, and West Feliciana).

2. The provisions of this Chapter shall apply during the ozone season, as defined in Subsection B of this Section, of each year.

3. All affected facilities shall be in compliance as expeditiously as possible, but by no later than the dates specified in Subsection J of this Section.

B. Definitions. Unless specifically defined in this Subsection or in LAC 33:III.111 or 502, the words, terms, and abbreviations in this Chapter shall have the meanings commonly used in the field of air pollution control.For purposes of this Chapter only, the following definitions shall supersede any definitions in LAC 33:III.111 or 502.

Administrative Authority-the secretary of the Department of Environmental Quality or his designee or the appropriate assistant secretary or his designee.

Administrator-the administrator, or an authorized representative, of the U. S. Environmental Protection Agency (EPA).

Affected Facility- any facility within the Baton Rouge nonattainment area with one or more affected point sources that collectively emit or have the potential to emit 25 tons or more per year of NO_x, unless exempted in Subsection C of this Section, or any facility within the region of influence with one or more affected point sources that collectively emit or have the potential to emit 50 tons or more per year of NO_x, unless exempted in Subsection C of this Section. Exempt sources in a facility shall not be included in the determination of whether it is an affected facility.

Affected Point Source-any point source located at an affected facility and subject to an emission factor listed in Paragraph D.1 of this Section or used as part of an alternative plan in accordance with Subsection E of this Section, unless exempted in Subsection C of this Section.

Ammonia Reformer-a type of process heater/furnace located in an ammonia production plant that is designed to heat a mixture of natural gas and steam to produce hydrogen and carbon oxides.

Averaging Capacity-the average actual heat input rate in million British thermal units per hour (MMBtu/hour) at which an affected point source operated during the ozone season of the two calendar years of 2000 and 2001 (e.g., the total heat input for the period divided by the actual hours of operation for the same period). Another period may be used to calculate the averaging capacity if approved by the department. For units with permit revisions that legally curtailed capacity or that were permanently shut down after 1997, the averaging capacity is the average actual heat input during the last two ozone seasons of operation before the curtailment or shutdown.

Baton Rouge Nonattainment Area-the entire parishes of Ascension, East Baton Rouge, Iberville, Livingston, and West Baton Rouge.

Biomass-defined as bagasse, rice-husks, wood, or other combustible, vegetation-derived material that is suitable for use as fuel.

Boiler-any combustion equipment fired with any solid, liquid, and/or gaseous fuel that is primarily used to produce steam, or heat water, or any other heat transfer medium for power generation or for heat to an industrial, institutional, or commercial operation. Equipment that is operated primarily for waste treatment and that incidentally produces steam shall not be regulated under this Chapter as a boiler.

Cap-a system for demonstrating compliance whereby an affected facility, a subset of affected sources at an affected facility, or a group of affected facilities under common control are operated to stay below a mass emission rate expressed as mass per unit of time. The allowable mass emission rate is calculated by adding the allowable emissions for each affected point source. The allowable emission is the product of the source's average hourly heat input in MMBtu/hour (not to exceed any applicable permit limitations) based on the highest consecutive 30-day period during the ozone seasons of 2000 and 2001 and the applicable factor in Paragraph D.1 of this Section.

Chemical Processing Gas Turbine-a gas turbine that vents its exhaust gases into the operating stream of a chemical process.

Coal-all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society for Testing and Materials, Designation D388-77. For the purposes of this Chapter, coal shall also include petroleum coke, solid carbon residues from the processing of petroleum products and coal-derived synthetic fuels, including but not limited to, solvent refined coal, coal-oil mixtures, and coal-water mixtures.

Combined Cycle-a combustion equipment configuration that generates electrical or mechanical power with a stationary gas or liquid-fired turbine and/or a stationary internal combustion engine and that recovers heat from the discharge within equipment to heat water or generate steam.

Continuous Emissions Monitoring System (CEMS)-the total equipment that may be required to meet the data acquisition and availability requirements, used to sample, condition, if applicable, analyze, and provide a record of emissions.

Daily Average-an average of the hourly data for one calendar day starting at 12-midnight and continuing until the following 12-midnight.

Department-the Louisiana Department of Environmental Quality.

Elapsed Run-Time Meter-an instrument designed to measure and record the time that an affected point source has run during a designated period.

Electric Power Generating System-all boilers, stationary internal combustion engines, stationary gas turbines, and other combustion equipment within an affected facility that are used to generate electric power and that are owned or operated by a municipality, an electric cooperative, an independent power producer, a public utility, or a Louisiana Public Service Commission regulated utility company, or any of its successors.

Emergency Standby Gas Turbine or Engine-a gas turbine or engine operated as an electrical or a mechanical power source for an affected facility when the primary source has been disrupted or discontinued during an emergency due to circumstances beyond the control of the owner or operator of the affected facility and that is operated only during such an emergency or when normal testing procedures, as recommended by the manufacturer, are being performed. The definition includes a stationary gas turbine or a stationary internal combustion engine that is used at a nuclear power plant as an emergency generator that is subject to Nuclear Regulatory Commission (NRC) regulations and a stationary internal combustion engine that is used for the emergency pumping of water for either fire protection or flood relief. This term does not include an electric generating unit in peaking service.

F Factor-the ratio of the gas volume of the products of combustion to the heat content of the fuel, typically expressed in dry standard cubic feet (dscf) per MMBtu.

Facility-a contiguous area under common control that contains various types of equipment that emit or have the potential to emit NO_x.

Facility-Wide Averaging Plan-an alternative emission plan whereby an affected facility (or affected facilities with a common owner or operator) with multiple affected point sources of NO_x emissions achieves the required reduction by a different mix of controls from that mandated by Subsection D of this Section. Some affected point sources may be over-controlled (more restrictive than the regulation) or shut down in order to offset other affected point sources that are under-controlled (less restrictive than the regulation) or not controlled, provided the required overall NO_x reduction is met.

Facility-Wide Emission Factor-the total average allowable NO_x emission factor in pound NO_x/MMBtu for affected point sources when firing at their averaging capacities.

Flare-a type of equipment specifically designed for combusting gaseous vents at an above-ground location.

Fluid Catalytic Cracking Unit Regenerator-a unit in a refinery where catalyst is recovered (regenerated) by burning off coke and other deposits with hot air. The term includes the associated equipment for controlling air pollutant emissions and for heat recovery.

Gas-any gaseous substance that can be used as a fuel to create heat and/or mechanical energy including natural gas, synthetically produced gas from coal or oil, gaseous substances from the decomposition of organic matter, and gas streams that are by-products of a manufacturing process.

Heat Input-the heat released due to fuel combustion in an affected point source, using the higher heating value of the fuel, excluding the sensible heat of the incoming combustion air.

Higher Heating Value-a measurement of the heat evolved during the complete combustion of a substance, including the latent heat of condensation of any water that is produced.

Horsepower Rating-the engine manufacturer's maximum continuous load rating at the lesser of the engine or driven equipment's maximum published continuous speed.

Incinerator-same as defined in LAC 33:III.111.

International Standards Organization (ISO) Conditions-standard conditions of 59°F, 1.0 atmosphere, and 60 percent relative humidity.

Kilns and Ovens-combustion equipment used for drying, baking, cooking, and calcining. Kilns can also be used for the treatment of solid wastes.

Lean-Burn Engine-a spark-ignited or compression-ignited, Otto cycle, diesel cycle, or two-stroke engine that is not capable of being operated with an exhaust stream oxygen concentration equal to or less than 1.0 percent, by volume on a dry basis, as originally designed by the manufacturer. The exhaust gas oxygen concentration shall be determined from the uncontrolled exhaust stream.

Liquid Fuel-any substance in a liquid state that can be used as a fuel to create heat and/or mechanical energy including:

a. crude oil, petroleum oil, fuel oil, residual oil, distillate, or other liquid fuel derived from crude oil or petroleum;

b. liquid by-products of a manufacturing process or a petroleum refinery; and

c. any other liquid fuel.

Low Ozone Season Capacity Factor Boiler or Process Heater/Furnace- a boiler or process heater/furnace in the Baton Rouge nonattainment area with a maximum rated capacity greater than or equal to 40 MMBtu/hour and an ozone season average heat input less than or equal to 12.5 MMBtu/hour, using a 30-day rolling average; or in the region of influence with a maximum rated capacity greater than or equal to 80 MMBtu/hour and an ozone season average heat input less than or equal to 25 MMBtu/hour, using a 30-day rolling average.

Malfunction-any sudden and unavoidable failure, as defined in LAC 33:III.111.

Maximum Rated Capacity-the maximum annual design capacity, as determined by the equipment manufacturer or as proven by actual maximum annual performance in the field, unless the affected point source is limited by permit condition to a lesser annual capacity, in which case the limiting condition shall be used as the maximum rated capacity. Where the capacity of a point source is limited by an operating cap applicable to a group of point sources (e.g., several units capped to a combined total firing rate), the total firing rate cap shall be divided by the number of point sources in the cap to arrive at an equivalent maximum rated capacity. This equivalent maximum rated capacity shall be used only to determine the applicability of the emission factors and monitoring provisions of this Chapter.

Megawatt (MW) Rating-the continuous power rating or mechanical equivalent by a stationary gas turbine manufacturer at ISO conditions, without consideration to the increase in turbine shaft output and/or decrease in turbine fuel consumption by the addition of energy recovered from exhaust heat.

Nitric Acid Production Unit-a facility that produces nitric acid by any process.

Nitrogen Oxides (NO_x)-the sum of the nitric oxide and nitrogen dioxide in a stream measured in accordance with Subsection G of this Section.

Number 6 Fuel Oil-fuel oil of the grade that is classified number 6, according to ASTM standard specification for classification of fuel oil by ASTM D396-84.

Ozone Season- except as provided in LAC 33:III.2202, the period May 1 to September 30, inclusive, of each year.

Peaking Service-a stationary gas turbine that is operated intermittently to produce energy. To be in peaking service, the annual electric output (MW-hour) for the affected point source shall be less than the product of 2500 hours and the MW rating of the turbine.

Permanent Shutdown-a shutdown of an affected point source where the owner or operator has filed a notice of permanent shutdown with the department or where the department, through a permit revision or final permit, has removed the affected point source from the applicable permit. (To maintain temporary shutdown status, a source must be maintained in good working order and not dismantled or cannibalized, must still be listed in the applicable permit, must still be listed on the department's emission inventory, and must continue to pay appropriate fees.)

Predictive Emissions Monitoring System (PEMS)-a system that uses process and other parameters as inputs to a computer program or other data reduction system to produce values in terms of the applicable emission limitation or standard.

Process Heater/Furnace-any combustion equipment fired with solid, liquid, and/or gaseous fuel that is used to transfer heat to a process fluid, superheated steam, or water for the purpose of heating the process fluid or causing a chemical reaction. The term process heater/furnace does not apply to any unfired waste heat recovery boiler that is used to recover sensible heat from the exhaust of any combustion equipment, or to boilers as defined in this Subsection.

Pulp Liquor Recovery Furnace-either a straight Kraft recovery furnace or a cross recovery furnace as defined in 40 CFR 60 Subpart BB.

Region of Influence-an area to the north of the Baton Rouge nonattainment area that encompasses affected facilities in the attainment parishes of East Feliciana, Pointe Coupee, St. Helena, and West Feliciana.

Rich-Burn Engine-all stationary reciprocating engines that do not fit the definition of lean-burn.

Sensible Heat-the heat energy stored in a substance as a result of an increase in its temperature.

Stationary Gas Turbine-any turbine system that is gas and/or liquid fuel fired and that is either attached to a foundation at an affected facility or is portable equipment operated at a specific affected facility for more than 60 days in any ozone season.

Stationary Internal Combustion Engine-a reciprocating engine that is either gas and/or liquid fuel fired and that is either attached to a foundation or is portable equipment operated at a specific affected facility for more than six months at a time. This term does not include locomotive engines or self-propelled construction engines.

Supplemental Firing Unit-a unit with burners that is installed in the exhaust duct of a stationary gas turbine or internal combustion engine for the purpose of supplying supplemental heat to a downstream heat recovery unit.

Thirty-Day (30-Day) Rolling Average- an average, calculated daily, of all hourly data for the last 30 days for an affected point source. At the beginning of each ozone season, use one of the following methods to calculate the initial 30-day averages:

a. calculate and record the average of all hourly readings taken during the first day of the ozone season for day one, then the average of all hourly readings taken during the first and second days for day two, and so on until the first full 30-day average falling entirely within the ozone season is reached;

b. calculate and record a 30-day rolling average for day one of the ozone season using the hourly readings from that day and the previous 29 calendar days, for the second day of the ozone season using the readings from the first two ozone season days and the preceding 28 calendar days, and so on until the first full 30-day average falling entirely within the current ozone season is reached; or

c. calculate and record a 30-day rolling average for day one of the ozone season using the hourly readings from that day and the last 29 days of the previous ozone season, for the second day of the ozone season using the readings from the first two current ozone season days and the last 28 days of the previous ozone season, and so on until the first full 30-day average falling entirely within the current ozone season is reached.

Totalizing Fuel Meter-a meter or metering system that provides a cumulative measure of fuel consumption.

Trading Allowances-the tons of NO_x emissions that result from over-controlling, permanently reducing the operating rate of, or permanently shutting down, an affected point source located within the Baton Rouge nonattainment area or the region of influence. The allowances are determined in accordance with LAC 33:III.607.C and from the emission factors required by Subsection D of this Section for the affected point source and the enforceable emission factor assigned by the owner or operator in accordance with Subsection E of this Section. Baseline emissions shall be the lower of actual emissions or adjusted allowable emissions, as defined in LAC 33:III.605. Trading allowances will be granted only for reductions that are real, quantifiable, permanent, and federally enforceable. NO_x reductions that are used in a facility-wide averaging plan cannot also be used in a trading plan.

Wood-wood, wood residue, bark, or any derivative fuel or residue thereof in any form, including but not limited to, sawdust, sander dust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues.

C. Exemptions. The following categories of equipment or processes located at an affected facility within the Baton Rouge nonattainment area or the region of influence are exempted from the provisions of this Chapter:

1. boilers and process heater/furnaces with a maximum rated capacity of less than 40 MMBtu/hour in the Baton Rouge nonattainment area or less than 80 MMBtu/hour in the region of influence;

2. stationary gas turbines with a megawatt rating based on heat input of less than 5 MW in the Baton Rouge nonattainment area or less than 10 MW in the region of influence;

3. stationary internal combustion engines as follows:

a. rich-burn engines with a rating of less than 150 horsepower (Hp) in the Baton Rouge nonattainment area or less than 300 Hp in the region of influence; and

b. lean-burn engines with a rating of less than 150 Hp in the Baton Rouge nonattainment area or less than 1500 Hp in the region of influence;

4. low ozone season capacity factor boilers and process heater/furnaces, as defined in Subsection B of this Section, in accordance with Paragraph H.11 of this Section;

5. stationary gas turbines and stationary internal combustion engines, that are:

a. used in research and testing;

b. used for performance verification and testing;

c. used solely to power other engines or turbines during start-ups;

d. operated exclusively for fire fighting or training and/or flood control;

e. used in response to and during the existence of any officially declared disaster or state of emergency;

f. used directly and exclusively for agricultural operations necessary for the growing of crops or the raising of fowl or animals; or

g. used as chemical processing gas turbines;

6. any point source, in accordance with Paragraph H.12 of this Section, that operates less than 3 hours per day, using a 30-day rolling average, during the ozone season;

7.flares, incinerators, and kilns and ovens, as defined in Subsection B of this Section;

8. Reserved.

9. any point source used solely to start up a process;

10. any point source firing biomass fuel that supplies greater than 50 percent of the heat input on a monthly basis;

11. any point source at a sugar mill;

12. fluid catalytic cracking unit regenerators;

13. pulp liquor recovery furnaces;

14. diesel-fired stationary internal combustion engines;

15. any affected point source that is required to meet a more stringent state or federal NO_x emission limitation, whether by regulation or permit. In this case, the monitoring, reporting, and recordkeeping requirements shall be in accordance with the more stringent regulation or permit and not this Chapter. If the applicable regulation or permit does not specify monitoring, reporting and recordkeeping requirements, the provisions of Subsections H and I of this Section shall apply;

16. wood-fired boilers that are subject to 40 CFR 60, Subpart Db;

17. nitric acid production units that are subject to 40 CFR 60, Subpart G or LAC 33:III.2307;

18. any affected point source firing fuel oil during a period of emergency and approved by the administrative authority;

19. boilers and industrial furnaces treating hazardous waste and regulated under LAC 33:V.Chapter 30 or 40 CFR Part 264, 265, or 266, including halogen acid furnaces and sulfuric acid regeneration furnaces; and

20. high efficiency boilers or other combustion devices regulated under the Toxic Substance Control Act PCB rules under 40 CFR Part 761.

D. Emission Factors

1. The following tables list NO_x emission factors that shall apply to affected point sources located at affected facilities in the Baton Rouge nonattainment area or the region of influence.

Table D-1A NOx Emission Factors for Sources in the Baton Rouge Nonattainment Area
Category	Maximum Rated Capacity	NOx Emission Factora
Electric Power Generating System Boilers
Coal-fired	>/=40 to<80 MMBtu/Hour	0.50 pound/MMBtu
	>/=80 MMBtu/Hour	0.21 pound/MMBtu
Number 6 Fuel Oil-fired	>/=40 to <80 MMBtu/Hour	0.30 pound/MMBtu
	>/=80 MMBtu/Hour	0.18 pound/MMBtu
All Others (gaseous or liquid)	>/=40 to <80 MMBtu/Hour	0.20 pound/MMBtu
	>/=80 MMBtu/Hour	0.10 pound/MMBtu
Industrial Boilers
All Fuels	>/=40 to <80 MMBtu/Hour	0.20 pound/MMBtu
	>/=80 MMBtu/Hour	0.10 pound/MMBtu
Process Heater/Furnaces
Ammonia Reformers	>/=40 to <80 MMBtu/Hour	0.30 pound/MMBtu
	>/=80 MMBtu/Hour	0.23 pound/MMBtu
All Others	>/=40 to <80 MMBtu/Hour	0.18 pound/MMBtu
	>/=80 MMBtu/Hour	0.08 pound/MMBtu
Stationary Gas Turbines
Peaking Service, Fuel Oil-fired	>/=5 to <10 MW	0.37 pound/MMBtu
	>/=10 MW	0.30 pound/MMBtu
Peaking Service, Gas-fired	>/=5 to <10 MW	0.27 pound/MMBtu
	>/=10 MW	0.20 pound/MMBtu
All Others	>/=5 to <10 MW	0.24 pound/MMBtub
	>/=10 MW	0.16 pound/MMBtuc
Stationary Internal Combustion Engines
Lean-burn	>/=150 to < Hp	10 g/Hp-hour
	>/=320 Hp	4 g/Hp-hour
Rich-burn	>/=150 to <300 Hp	2 g/Hp-hour
	>/=300 Hp	2 g/Hp-hour

^a based on the higher heating value of the fuel

^b equivalent to 65 ppmv (15 percent O2, dry basis) with an F factor of 8710 dscf/MMBtu

^c equivalent to 43 ppmv (15 percent O2, dry basis) with an F factor of 8710 dscf/MMBtu

Table D-1B NOx Emission Factors for Sources in the Region of Influence
Category	Maximum Rated Capacity		NOx Emission Factor a
Electric Power Generating System Boilers
Coal-fired	/=80 MMBtu/Hour		0.21 pound/MMBtu
Number 6 Fuel Oil-fired	/=80 MMBtu/Hour		0.18 pound/MMBtu
All Others (gaseous or liquid)	/=80 MMBtu/Hour		0.10 pound/MMBtu
Industrial Boilers
All Fuels	/=80 MMBtu/Hour	0.10 pound/MMBtu
Process Heater/Furnaces:
Ammonia Reformers	/=80 MMBtu/Hour	0.23 pound/MMBtu
All Others	/=80 MMBtu/Hour	0.08 pound/MMBtu
Stationary Gas Turbines
Peaking Service, Fuel Oil-fired	/=10 MW	0.30 pound/MMBtu
Peaking Service, Gas-fired	/=10 MW	0.20 pound/MMBtu
All Others	/=10 MW	0.16 pound/MMBtub
Stationary Internal Combustion Engines
Lean-burn	/=1500 Hp	4 g/Hp-hour
Rich-burn	/=300 Hp	2 g/Hp-hour

^a all factors are based on the higher heating value of the fuel

^b equivalent to 43 ppmv (15 percent O2, dry basis) with an F factor of 8710 dscf/MMBtu

2. Any electric power generating system boiler that operates with a combination of fuels shall comply with an adjusted emission factor calculated as follows:

a. if a combination of fuels is used normally, the emission factor from Paragraph D.1 of this Section shall be adjusted by the weighted average heat input of the fuels based on the ozone season average usage in 2000 and 2001, or another period if approved by the department;

b. if the boiler is normally fired with a primary fuel and a secondary fuel is available for back-up, the unit shall comply with the emission factor for the primary fuel while firing the primary fuel and with the emission factor for the secondary fuel while firing the secondary fuel. In addition, the usage of the secondary fuel shall be limited to the ozone season average usage of the secondary fuel in 2000 and 2001, or another period if approved by the department; and

c. in either case, if the secondary fuel is less than 10 percent of the weighted average, the owner or operator may choose to comply with the unadjusted limit for the primary fuel.

3. For affected point sources in an electric power generating system, the emission factors from Subsection D of this Section shall apply as the mass of NO_x emitted per unit of heat input (pound NO_x per MMBtu), on a 30-day rolling average basis. Alternatively, a facility may choose to comply with a ton per day or a pound per hour cap provided that monitoring is installed, calibrated, maintained, and operated to demonstrate compliance with the cap. The cap for a facility or for multiple facilities under common control is calculated by adding the products of the factor from Paragraph D.1 of this Section and the average hourly heat input in MMBtu/hour (not to exceed any applicable permit limitations) based on the highest consecutive 30-day period during the ozone seasons of 2000 and 2001 for each affected point source as follows.

Equation D-1

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where:

HI_i = the average hourly heat input based on the highest consecutive 30-day period during the ozone seasons of 2000 and 2001 of each point source (MMBtu/hour)

i = each point source included in the cap

N = the total number of point sources included in the cap

R_li = the limit for each point source from Subsection D of this Section (pound NO_x/MMBtu)

4. For all other affected point sources, the emission factors from Subsection D of this Section shall apply as the mass of NO_x emitted per unit of heat input (pounds NO_x per MMBtu or grams NO_x per Hp-hour), on a 30-day rolling average basis. Alternatively, a facility may choose to comply with a cap as detailed in Paragraph D.3 of this Section, provided that a system, approved by the department, is installed, calibrated, maintained, and operated to demonstrate compliance.

5. If one affected point source discharges in part or in whole to another affected point source, the portion discharging into the second point source shall be treated as emanating from the second point source and shall be controlled to the same limit as that specified for the second point source, while the portion discharging directly to the atmosphere from the first point source shall be controlled to the limit of the first point source. This term shall not include a combined cycle unit that discharges into a supplemental firing unit or other type of combustion equipment. For this type of point source, the emissions shall be controlled as follows:

a. for the turbines and/or engines, at the appropriate limits for the turbines and/or engines alone; and

b. for the supplemental firing unit or other type of combustion equipment, at the appropriate limit for the supplemental firing or combustion equipment with the measured emission values adjusted for the emissions coming from the turbines and/or engines.

6. Where a common stack is used to collect vents from affected point sources or affected point sources and exempt point sources and monitoring and/or testing of individual units is not feasible, the department, upon application from the owner or operator, shall specify alternative methods to demonstrate compliance with the emission factors of this Subsection.

7. Any affected point source firing gaseous fuel that contains hydrogen and/or carbon monoxide may apply a multiplier, as calculated below, to the appropriate emission factor given in Paragraph D.1 of this Section. The total hydrogen and/or carbon monoxide volume in the gaseous fuel stream is divided by the total gaseous fuel flow volume to determine the volume percent of hydrogen and/or carbon monoxide in the fuel supply. In order to apply this multiplier, the owner or operator of the affected point source shall sample and analyze the fuel gas composition for hydrogen and/or carbon monoxide in accordance with Paragraph G.5 of this Section.

Equation D-2

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8. The owner or operator of a stationary gas turbine using a fuel that has an F factor different than 8710 dscf/MMBtu may adjust the allowable emission factor shown in Paragraph D.1 of this Section. The adjustment is made by dividing the actual F factor (dscf/MMBtu) of the fuel by 8710 and multiplying the result by 0.16 to get the adjusted allowable emission factor. The use of this option shall be detailed in the permit application or in the optional compliance plan described in Paragraph F.7 of this Section.

9. On a day that is designated as an Ozone Action Day by the department, a facility shall not fire an affected point source with Number 6 fuel oil or perform testing of emergency and training combustion units without prior approval of the administrative authority. If a facility has received approval from the administrative authority for a plan to use Number 6 fuel oil, this is considered prior approval for purposes of this Paragraph.

E. Alternative Plans

1. Facility-Wide Averaging Plan. A facility-wide averaging plan is established in this Chapter for single affected facilities and multiple affected facilities that are owned or operated by the same entity. For sources located within the Baton Rouge nonattainment area or the region of influence, an owner or operator of one or more affected facilities may use the facility-wide averaging plan as an alternative means of compliance with the emission factors from Subsection D of this Section. A request for approval to use a facility-wide averaging plan, that includes the details of the plan, shall be submitted to the department either separately or with the permit application or in the optional compliance plan described in Paragraph F.7 of this Section. A facility-wide averaging plan submitted under this provision shall be approved if the department determines that it will provide emission reductions equivalent to or more than that required by the emission factors in Subsection D of this Section and the plan establishes satisfactory means for determining initial and continuous compliance, including appropriate monitoring and recordkeeping requirements. Approval of the alternative plans by the administrative authority does not necessarily indicate automatic approval by the administrator.

a. An owner or operator who elects to use a facility-wide averaging plan for compliance shall establish an emission factor for each applicable affected point source such that if each affected point source was operated at its averaging capacity, the cumulative emission factor in pounds NO_x/MMBtu from all point sources in the averaging group would not exceed the facility-wide emission factor, as shown in Equation E-3. The equations below shall be used to calculate the cumulative emission rate and the facility-wide emission factor.

Click Here To View Image

where:

Click Here To View Image

Click Here To View Image

where:

f_i = fraction of total system averaging capacity for point source i

HI_i = the averaging capacity of each point source (MMBtu/hour)

i = each point source in the averaging group

N = the total number of point sources in the averaging group

R_ai = the limit assigned by the owner to each point source in the averaging plan (pound NO_x/MMBtu)

R_li = the limit for each point source from Subsection D of this Section (pound NO_x/MMBtu)

FL = facility-wide emission factor (pound NO_x/MMBtu) of all point sources included in the averaging plan

b. An owner or operator of an electric power generating system that chooses to use an averaging plan shall demonstrate compliance by either of the following methods:

i. operating such that each affected point source does not exceed its assigned individual limit in pound NO_x/MMBtu on a 30-day rolling average basis; or

ii. complying with a cap as described in Paragraph D.3 of this Section, provided that a monitoring system is installed, calibrated, maintained, and operated to demonstrate compliance with the cap.

c. Owners or operators of all other affected point sources that choose to use an averaging plan shall demonstrate compliance by either of the following methods:

i. operating such that each affected point source does not exceed its assigned individual limit in pound NO_x/MMBtu on a 30-day rolling average basis; or

ii. complying with a cap as described in Paragraph D.3 of this Section, provided a system, approved by the department, is installed, calibrated, maintained, and operated to demonstrate compliance with the cap.

d. An owner or operator that chooses to use the provisions of Clause E.1.b.i or E.1.c.i of this Section to demonstrate compliance in an averaging plan shall include in the submitted plan a description of the actions that will be taken if any under-controlled unit is operated at more than 10 percent above its averaging capacity (HI_i in Subparagraph E.1.a of this Section). Such actions may include a comparison of the total current emissions from all units in the averaging plan to the total emissions that would result if the units in the plan were operated in accordance with Subsection D of this Section, other reviews, reporting, and/or mitigation actions. If the department determines that the actions are not adequate to prevent an increase of emissions over the total emissions that would result if the units were operated in accordance with Subsection D of this Section, the department shall require that the averaging plan and/or the action plan be revised or shall disallow the use of the averaging plan.

e. The owner or operator of affected point sources complying with the requirements of this Subsection can include in the plan either all of the affected point sources at the facility or select only certain sources to be included.

f. NO_x reductions accomplished after 1997 through curtailments in capacity of a point source with a permit revision or by permanently shutting down the point source may be included in the averaging plan. In order to include a unit with curtailed capacity or that has been permanently shut down in the averaging plan, the old averaging capacity, determined from the average of the two ozone seasons prior to the capacity curtailment or shutdown, or such other two-year period as the department may approve, shall be used to calculate the unit's contribution to the term FL. The new averaging capacity, determined from the enforceable permit revision, shall be multiplied by the owner-assigned limit to calculate the contribution of the curtailed unit to the cumulative emission factor for the averaging group. For a shut down source, the contribution to the cumulative emission factor shall be zero.

g. NO_x reductions from post 1997 modifications to exempted point sources, as defined in Subsection C of this Section, may be used in a facility-wide averaging plan. If a unit exempted in Subsection C of this Section is included in an averaging plan, the term R_li in Equation E-1 shall be established, in accordance with Subsection G of this Section, from a stack test or other determination of emissions approved by the department that was performed before the NO_x reduction project was implemented, and the term R_ai shall be established from the owner-assigned emission factor in accordance with Subparagraph E.1.a of this Section. For the case of a point source exempted by Paragraph C.15 of this Section, if the permit limits were established after 1997 and were not required by a state or federal regulation, the source may be included in an averaging plan, with the term R_li taken from Table D-1A or D-1B in Paragraph D.1 of this Section.

h. Solely for the purpose of calculating the facility-wide emission factor, the allowable emission factor (pound NO_x/MMBtu) for each affected stationary internal combustion engine is the applicable NO_x emission factor from Subsection D of this Section (g/Hp-hour) divided by the product of the engine manufacturer's rated heat rate (expressed in Btu/Hp-hour) at the engine's Hp rating and 454 x10^-6.

i. The owner or operator of affected point sources complying with the requirements of this Subsection in accordance with an emissions averaging plan shall carry out recordkeeping that includes, but is not limited to, a record of the data on which the determination of each point source's hourly, daily, or 30-day, as appropriate, compliance with the facility-wide averaging plan is based.

2. Trading Plan. Trading is established in this Chapter as an alternate means of compliance with the emission factors from Subsection D of this Section. Within the Baton Rouge nonattainment area and the region of influence, trading allowances, as defined in Subsection B of this Section, may be traded between affected facilities owned by different companies in a manner consistent with LAC 33:III.617.C.3. The approval to use trading shall be requested in the permit application or in the optional compliance plan described in Paragraph F.7 of this Section. A trading plan submitted under this provision shall be approved if the department determines that it will provide NO_x emission reductions equivalent to or more than that required by the emission factors of Subsection D of this Section and the plan establishes satisfactory means for determining ongoing compliance, including appropriate monitoring and recordkeeping requirements. Approval of trading plans by the administrative authority does not necessarily indicate automatic approval of the administrator.

F. Permits

1. Authorization to Install and Operate NO_x Control Equipment

a. An owner or operator may obtain approval to install and operate NO_x control equipment that does not result in ammonia emissions above the minimum emission rate (MER) in LAC 33:III.Chapter 51 by submitting documentation in accordance with LAC 33:III.511. This documentation shall include an estimate of any carbon monoxide (CO), sulfur dioxide (SO₂), particulate matter (PM₁₀), and/or volatile organic compound (VOC) emission increases associated with the NO_x control technology. If approved, the administrative authority shall grant an authorization to construct and operate in accordance with LAC 33:III.501.C.3. Any appropriate permit application reflecting the emission reduction shall be submitted to the department and deemed administratively complete no later than 180 days after commencement of operation and in accordance with the procedures of LAC 33:III.Chapter 5.

b. In accordance with LAC 33:III.5111.C, installation of NO_x control equipment that results in ammonia emissions above the MER in LAC 33:III.Chapter 51 shall not commence until a permit or permit modification has been approved by the administrative authority. In accordance with LAC 33:III.5107.D.1, the administrative authority shall provide at least 30 days for public comment before issuing any such permit.

2. Alternatively to Subparagraph F.1.a of this Section, an owner or operator of an affected facility that is operating with a Louisiana air permit may submit a completed permit modification application for the changes proposed to comply with this Chapter.

3. Any owner or operator with an affected facility that has retained grandfathered status, as described in LAC 33:III.501.B.6, shall submit an application in accordance with LAC 33:III.501.C.1 for the changes proposed to comply with this Chapter.

4. Duty to Supplement. In accordance with LAC 33:III.517.C, if an owner or operator has a permit application on file with the department, but the department has not released the proposed permit, the applicant shall supplement the application as necessary to address this Chapter.

5. Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NNSR) Considerations. A significant net emissions increase in NO_x, CO, SO₂, PM₁₀, and/or VOC in accordance with LAC 33:III.504 or 509, that is a direct result of, and incidental to, the installation of NO_x control equipment or implementation of a NO_x control technique required to comply with the provisions of this Chapter shall be exempt from the requirements of LAC 33:III.509 and/or 504, as appropriate, provided the following conditions are met:

a. the project shall not:

i. cause or contribute to a violation of the national ambient air quality standard (NAAQS); or

ii. adversely affect visibility or other air quality related value (AQRV) in a class I area;

b. any increase in CO, SO₂, PM₁₀, and/or VOC emissions shall be:

i. quantified in the submittal required by Paragraphs F.1-4 of this Section; and

ii. tested in accordance with Subsection G of this Section, as applicable;

c. notwithstanding the requirements of LAC 33:III.504, Table 1, a significant net increase of VOC emissions at an affected facility located in the Baton Rouge nonattainment area shall be offset at a ratio of at least 1:1. Offsets shall be surplus, permanent, quantifiable, and federally enforceable and calculated in accordance with LAC 33:III.Chapter 6; and

d. a 30-day public comment period shall be provided in accordance with LAC 33:III.519.C prior to issuance of a permit or permit modification.

6. Increases above the MER in toxic air pollutant (TAP) emissions shall be subject to the applicable requirements of LAC 33:III.Chapter 51.

7. When pre-permit application approval of plans is desired by an owner or operator, a compliance plan may be submitted in accordance with this Subsection. The administrative authority shall approve the plan if it contains all of the required information to determine that the affected sources will be in compliance with this Chapter and is accurate. The compliance plan may address individual point sources, groups of point sources, or all point sources at the facility, as determined by the owner. The following information shall be submitted as appropriate:

a. the facility designation, as indicated by the identification number, submitted to the Office of Environmental Services;

b. a list of all units in the compliance plan, the emission point number as designated on the emission inventory questionnaire, the averaging capacity, and the maximum rated capacity;

c. identification of all combustion units with a claimed exemption in accordance with Subsection C of this Section, and the rule basis for the claimed exemption;

d. a list of any units that have been, or will be, curtailed or permanently shut down;

e. for each unit, the actual emission factor that will be used to achieve compliance;

f. the control technology to be applied for each unit subject to control, and an anticipated construction schedule for each control device including the dates for completion of engineering, submission of permit applications, start and finish of construction, and initial start-up; and

g. the calculations to demonstrate that each unit will achieve the required NO_x emission rate.

G. Initial Demonstration of Compliance

1. Emissions testing to demonstrate initial compliance with the NO_x emission factors of Subsection D of this Section, or with emission limits that are part of an alternative plan under Subsection E of this Section, for affected point sources operating with a CEMS or PEMS that has been certified in accordance with Subsection H of this Section is not required. The certification of the CEMS or PEMS shall be considered demonstration of initial compliance. Testing for initial compliance is not required for an existing CEMS or PEMS that meets the requirements of Subsection H of this Section.

2. Emissions testing is required for all point sources that are subject to the emission limitations of Subsection D of this Section or used in one of the alternative plans of Subsection E of this Section. Test results must demonstrate that actual NO_x emissions are in compliance with the appropriate limits of this Chapter. As applicable, CO, SO₂, PM₁₀, and VOC shall also be measured if modifications, done to comply with this Chapter, could cause an increase in emissions of any of these compounds. Performance testing of these point sources shall be performed in accordance with the schedule specified in Subsection J of this Section.

3. The tests required by Paragraph G.2 of this Section shall be performed by the test methods referenced in Paragraph G.5 of this Section, except as approved by the administrative authority in accordance with Paragraph G.7 of this Section. Test results shall be reported in the units of the applicable emission factors and for the corresponding averaging periods.

4. Emission testing conducted in the three years prior to the initial demonstration of compliance date may be used to demonstrate compliance with the limits of Subsection D or E of this Section, if the owner or operator demonstrates to the department that the prior testing meets the requirements of this Subsection. The request to waive emissions testing according to this Paragraph shall be included in the permit application. The department reserves the right to request performance testing or CEMS performance evaluation upon 60 days notice.

5. Compliance with the emission specifications of Subsection D or E of this Section for affected point sources operating without CEMS or PEMS shall be demonstrated while operating at the maximum rated capacity, or as near thereto as practicable. The stack tests shall be performed according to emissions testing guidelines located on the department website under Air Quality Assessment/Emission Testing Program. Three minimum 1-hour tests, or three minimum 20-minute tests for turbines, shall be performed and the following methods from 40 CFR Part 60, Appendix A shall be used:

a. Methods 1, 2, 3, and 4 or 19, with prior approval, for exhaust gas flow;

b. Method 3A or 20 for O₂ ;

c. Method 5 for PM;

d. Method 6C for SO₂;

e. Method 7E or 20 for NO_x;

f. Method 10 or 10A for CO;

g. Method 18 or 25A for VOC;

h. modified Method 5, or a department-approved equivalent, for NH₃; and/or

i. American Society of Testing and Materials (ASTM) Method D1945-96 or ASTM Method D2650-99 for fuel composition; ASTM Method D1826-94 or ASTM Method D3588-98 for calorific value.

6. All alternative or equivalent test methods, waivers, monitoring methods, testing and monitoring procedures, customized or correction factors, and alternatives to any design, equipment, work practices, or operational standards must be approved by both the administrative authority and the administrator, if applicable, before they become effective.

7. An owner or operator may request approval from the department for minor modifications to the test methods listed in Paragraph G.5 of this Section, including alternative sampling locations and testing a subset of similar affected sources, prior to actual stack testing.

8. The information required in this Subsection shall be provided in accordance with the effective dates in Subsection J of this Section.

H. Continuous Demonstration of Compliance. After the initial demonstration of compliance required by Subsection G of this Section, continuous compliance with the emission factors of Subsection D or E of this Section, as applicable, shall be demonstrated by the methods described in this Subsection. For any alternative method, the department's approval does not necessarily constitute compliance with all federal requirements nor eliminate the need for approval by the administrator.

1. The owner or operator of boilers that are subject to this Chapter shall demonstrate continuous compliance as follows:

a. for boilers with a maximum rated capacity less than 250 MMBtu/hour:

i. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage;

ii. install, calibrate, maintain, and operate an oxygen monitor to measure oxygen concentration; and

iii. in order to continuously demonstrate compliance with the NO_x limits of Subsection D or E of this Section, implement procedures to operate the boiler within the fuel and oxygen limits established during the initial compliance run in accordance with Subsection G of this Section; and

b. for boilers with a maximum rated capacity equal to or greater than 250 MMBtu/hour:

i. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure gas and/or liquid fuel usage. For coal-fired boilers, belt scales or an equivalent device shall be provided;

ii. install, calibrate, maintain, and operate a diluent (either oxygen or carbon dioxide) monitor. The monitor shall meet all of the requirements of Performance Specification 3 of 40 CFR 60, Appendix B;

iii. install, calibrate, maintain, and operate a NO_x CEMS to demonstrate continuous compliance with the NO_x emission factors of Subsection D or E of this Section, as applicable. The CEMS shall meet all of the requirements of 40 CFR Part 60.13 and Performance Specification 2 of 40 CFR 60, Appendix B, or the requirements of 40 CFR Part 75 for units regulated under the Acid Rain Program; and

iv. install, calibrate, maintain, and operate a CO monitor. The monitor shall meet all of the requirements of Performance Specification 4 of 40 CFR 60, Appendix B; or

v. alternatively to Clauses H.1.b.ii-iv of this Section, for demonstration of continuous compliance, the owner or operator may install, calibrate, certify, maintain, and operate a PEMS to predict NO_x, diluent (O₂ or CO₂), and CO emissions for each affected point source. As an alternative to using the PEMS to monitor diluent (O₂ or CO₂), a monitor for diluent according to Clause H.1.b.ii of this Section or similar alternative method approved by the department may be used. The PEMS shall be certified while operating on primary boiler fuel and, separately, on any alternative fuel. The certification shall be in accordance with EPA documents, "Example Specifications and Test Procedures for Predictive Emission Monitoring Systems" and "Predictive Emission Monitoring System to Determine NO_x and CO Emissions from an Industrial Furnace" that are located on the EPA website in the emission monitoring section, both with posting dates of July 31, 1997; or

vi. alternatively to Clauses H.1.b.ii-iv of this Section, the owner or operator may request approval from the administrator for an alternative monitoring plan that uses a fuel-oxygen operating window to demonstrate continuous compliance of NO_x and CO. In order to continuously demonstrate compliance with the NO_x limits of Subsection D or E of this Section, the owner or operator shall implement procedures to operate the boiler on or inside the fuel and oxygen lines that define the operating window. The corners of the window shall be established during the initial compliance test required by Subsection G of this Section or similar testing at another time. The details for use of an alternative monitoring plan shall be submitted in the permit application or in the optional compliance plan described in Paragraph F.7 of this Section. The plan shall become part of the facility permit and shall be federally enforceable.

2. The owner or operator of process heater/furnaces that are subject to this Chapter shall demonstrate continuous compliance as follows:

a. for process heater/furnaces with a maximum rated capacity less than 250 MMBtu/hour:

i. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage;

ii. install, calibrate, maintain, and operate an oxygen monitor to measure oxygen concentration; and

iii. in order to continuously demonstrate compliance with the NO_x limits of Subsection D or E of this Section, implement procedures to operate the process heater/furnace within the fuel and oxygen limits established during the initial compliance run in accordance with Subsection G of this Section; and

b. for process heater/furnaces with a maximum rated capacity equal to or greater than 250 MMBtu/hour:

i. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage;

ii. install, certify, maintain, and operate an oxygen or carbon dioxide diluent monitor in accordance with the requirements of Clause H.1.b.ii of this Section;

iii. install, certify, maintain, and operate a NO_x CEMS in accordance with the requirements of Clause H.1.b.iii of this Section; and

iv. install, certify, maintain, and operate a CO monitor in accordance with the requirements of Clause H.1.b.iv of this Section; or

v. alternatively to Clauses H.2.b.ii-iv of this Section, the owner or operator may install, calibrate, certify, maintain, and operate a PEMS in accordance with the requirements of Clause H.1.b.v of this Section; or

vi. alternatively to Clauses H.2.b.ii-iv of this Section, the owner or operator may request approval from the department for an alternative monitoring plan that uses a fuel-oxygen operating window, or other system, to demonstrate continuous compliance of NO_x and CO. In order to continuously demonstrate compliance with the NO_x limits of Subsection D or E of this Section, the owner or operator shall implement procedures to operate the process heater/furnace on or inside the fuel and oxygen lines that define the operating window. The corners of the window shall be established during the initial compliance test required by Subsection G of this Section or similar testing at another time. The details for use of an alternative monitoring plan shall be submitted in the permit application or in the optional compliance plan described in Paragraph F.7 of this Section. The plan shall become part of the facility permit and shall be federally enforceable.

3. The owner or operator of stationary gas turbines that are subject to this Chapter shall demonstrate continuous compliance as follows:

a. for stationary gas turbines with a megawatt rating based on heat input less than 30 MW:

i. if the stationary gas turbine uses steam or water injection to comply with the NO_x emission factors, install, calibrate, maintain, and operate a continuous system to monitor and record the average hourly fuel and steam or water consumption and the water or steam to fuel ratio. To demonstrate continuous compliance with the appropriate emission factor, the stationary gas turbine shall be operated at the required steam-to-fuel or water-to-fuel ratio as determined during the initial compliance test; and

ii. for other stationary gas turbines, install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage. Compliance with the emission factors of Subsection D or E of this Section shall be demonstrated by operating the turbine within the fuel limits established during the initial compliance run in accordance with Subsection G of this Section and by annual testing for NO_x and CO with an approved portable analyzer; or

iii. alternatively to Clause H.3.a.i or ii of this Section, an owner or operator may choose to comply with the requirements of Clauses H.3.b.i-iv or v of this Section to demonstrate continuous compliance with the limits of Subsection D or E of this Section; and

b. for stationary gas turbines with a megawatt rating based on heat input of 30 MW or greater:

i. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage;

ii. install, certify, maintain, and operate an oxygen or carbon dioxide diluent monitor in accordance with the requirements of Clause H.1.b.ii of this Section;

iii. install, certify, maintain, and operate a NO_x CEMS in accordance with the requirements of Clause H.1.b.iii of this Section; and

iv. install, certify, maintain, and operate a CO monitor in accordance with the requirements of Clause H.1.b.iv of this Section; or

v. alternatively to Clauses H.3.b.ii-iv of this Section, the owner or operator may install, calibrate, certify, maintain, and operate a PEMS in accordance with the requirements of Clause H.1.b.v of this Section; or

vi. alternatively to Clauses H.3.b.ii-iv of this Section, the owner or operator may request approval from the department for an alternative monitoring plan that complies with the provisions of Clause H.3.a.i of this Section, if the turbine uses steam or water injection for compliance, or Clause H.3.a.ii of this Section for other turbines. The alternative plan shall also require annual testing for NO_x and CO with an approved portable analyzer and triennial stack testing for NO_x and CO in accordance with the methods specified in Paragraph G.5 of this Section. The details for use of an alternative monitoring plan shall be submitted in the permit application or in the optional compliance plan described in Paragraph F.7 of this Section. The plan shall become part of the facility permit and shall be federally enforceable.

4. The owner or operator of stationary internal combustion engines that are subject to this Chapter shall demonstrate continuous compliance as follows:

a. install, calibrate, maintain, and operate a totalizing fuel meter to continuously measure fuel usage and demonstrate continuous compliance by operating the engine within the fuel limits established during the initial compliance run and by annual testing for NO_x and CO with an approved portable analyzer and by triennial stack testing for NO_x and CO in accordance with the methods specified in Paragraph G.5 of this Section; or

b. alternatively to Subparagraph H.4.a of this Section, an owner or operator may choose to comply with the requirements of Clauses H.3.b.i-iv or v of this Section to demonstrate continuous compliance with the limits of Subsection D or E of this Section.

5. A CEMS unit may be used to monitor multiple point sources provided that each source is sampled at least once every 15 minutes and the arrangement is approved by the department.

6. Existing instrumentation for any requirement in this Subsection shall be acceptable upon approval of the department.

7. For any affected point source that uses a chemical reagent for reduction of NO_x, a NO_x CEMS, in accordance with Clause H.1.b.iii of this Section, and a CO monitor, in accordance with Clause H.1.b.iv of this Section, shall be provided.

8. Boilers or process heater/furnaces covered by this Chapter that discharge through a common stack shall meet the appropriate continuous monitoring requirements of Paragraph H.1 or 2 of this Section, or an alternative approved by the department.

9. The owner or operator of any affected point source firing gaseous fuel for which a fuel multiplier from Paragraph D.7 of this Section is used shall sample, analyze, and record the fuel gas composition on a daily basis or on an alternative schedule approved by the administrative authority. If an owner or operator desires to use an alternative sampling schedule, he shall specify a sampling frequency in his permit application and provide an explanation for the alternative schedule. Fuel gas analysis shall be performed according to the methods listed in Subparagraph G.5.g of this Section, or other methods that are approved by the department. A gaseous fuel stream containing 99 percent H₂ and/or CO by volume or greater may use the following procedure to be exempted from the sampling and analysis requirements of this Subsection:

a. a fuel gas analysis shall be performed initially using the test methods in Subparagraph G.5.g of this Section to demonstrate that the gaseous fuel stream is 99 percent H₂ and/or CO by volume or greater; and

b. the owner or operator shall certify that the fuel composition will continuously remain at 99 percent H₂ and/or CO by volume or greater during its use as a fuel to the point source.

10. All affected point sources that rely on periodic stack testing to demonstrate continuous compliance and use a catalyst to control NO_x emissions shall be tested to show compliance with the emission factors of Subsection D or E of this Section after each occurrence of catalyst replacement. Portable analyzers shall be acceptable for this check. Documentation shall be maintained on-site, if practical, of the date, the person doing the test, and the test results. Documentation shall be made available for inspection upon request.

11. The owner or operator of any low ozone season capacity factor boiler or process heater/furnace, as defined in Subsection B of this Section, for which an exemption is granted shall install, calibrate, and maintain a totalizing fuel meter, with instrumentation approved by the department, and keep a record of the fuel input for each affected point source during each ozone season. If the average Btu-per-ozone season-hour limit is exceeded, the owner or operator of any boiler or process heater/furnace covered under this exemption shall include the noncompliance in the written report that is due in accordance with Paragraph I.2 of this Section. If the average Btu-per-ozone season-hour limit is exceeded, the exemption shall be permanently withdrawn. Within 90 days after receipt of notification from the administrative authority of the loss of the exemption, the owner or operator shall submit a permit modification detailing how the facility will meet the applicable emission factor as soon as possible, but no later than 24 months, after exceeding the ozone season limit. Included with this permit modification, the owner or operator shall submit a schedule of increments of progress for the installation of the required control equipment.This schedule shall be subject to the review and approval of the department.

12. The owner or operator of any affected point source that is granted an exemption in accordance with Paragraph C.6 of this Section shall install, calibrate, and maintain a nonresettable, elapsed run-time meter to record the operating time in order to demonstrate compliance during the ozone season. If the average operating hours-per-day limit is exceeded the owner or operator shall include the noncompliance in the written report that is due in accordance with Paragraph I.2 of this Section. If the average operating hours-per-day limit is exceeded, the exemption shall be permanently withdrawn. Within 90 days after receipt of notification from the administrative authority of the loss of the exemption, the owner or operator shall submit a permit modification detailing how the facility will meet the applicable emission factor as soon as possible, but no later than 24 months, after exceeding the limit. Included with this permit modification, the owner or operator shall submit a schedule of increments of progress for the installation and operation of the required control equipment. This schedule shall be subject to the review and approval of the department.

13. Elapsed run-time and fuel meters, oxygen, diluents, and CO monitors, and other such instrumentation required by this Section shall be calibrated according to the manufacturer's recommendations, but not less frequently than once per year. Records shall be maintained according to Paragraph I.3 of this Section.

14. Any unit with a permit requirement or applicable regulation that requires more stringent testing than this Chapter requires shall comply with the permit requirements or applicable regulation rather than this Chapter.

15. Continuous demonstration of compliance with fuel, oxygen concentration, and other parameter limits shall be on a 30-day rolling average basis.

I. Notification, Recordkeeping, and Reporting Requirements

1. The owner or operator of an affected point source shall notify the department at least 30 days prior to any compliance testing conducted under Subsection G of this Section and any CEMS or PEMS performance evaluation conducted under Subsection H of this Section in order to give the department an opportunity to conduct a pretest meeting and observe the emission testing. All necessary sampling ports and such other safe and proper sampling and testing facilities as required by LAC 33:III.913, or alternatives approved by the department, shall be provided for the testing. The test report shall be submitted to the department within 60 days after completing the testing.

2. The owner or operator of an affected point source granted an exemption in accordance with any part of Subsection C of this Section or required to demonstrate continuous compliance in accordance with Subsection H of this Section shall submit a written report within 90 days of the end of each ozone season to the administrative authority of any noncompliance with the applicable limitations of Subsection D or E of this Section or with the applicable work practice standards of Paragraph K.3 of this Section. The required information may be included in reports provided to the administrative authority to meet other requirements, so long as the report meets the deadlines and content requirements of this Paragraph. The report shall include the following information:

a. a description of the noncompliance;

b. a statement of the cause of the noncompliance;

c. the anticipated time that the noncompliance is expected to continue or, if it has been corrected, the duration of the period of noncompliance; and

d. the steps taken to prevent recurrence of the noncompliance.

3. The owner or operator of an affected point source shall maintain records of all continuous monitoring, performance test results, hours of operation, and fuel usage rates for each affected point source. Such records shall be kept for a period of at least five years and shall be made available upon request by authorized representatives of the department. The emission monitoring (as applicable) and fuel usage records for each affected point source shall be recorded and maintained:

a. hourly for affected point sources complying with an emission factor on an hourly basis;

b. daily for affected point sources complying with an emission factor enforced on a daily average basis or on a 30-day rolling average basis; and

c. monthly for affected point sources exempt from the emission specifications based on ozone season heat input or hours of operation per ozone season.

4. The owner or operator shall maintain the following records:

a. records for a facility-wide averaging plan in accordance with Subparagraph E.1.i of this Section;

b. records approved for a trading plan in accordance with Paragraph E.2 of this Section; and

c. records in accordance with Paragraphs H.7, 8, 9, 10, 11, and 12 of this Section.

5. Ammonia emissions resulting from the operation of a NO_x control equipment system shall be reported annually in accordance with LAC 33:III.5107.A.

J. Effective Dates

1. Except as provided in LAC 33:III.2202, the owner or operator of an affected facility shall modify and/or install and bring into normal operation NO_x control equipment and/or NO_x monitoring systems in accordance with this Chapter as expeditiously as possible, but by no later than May 1, 2005.

2. The owner or operator shall complete all initial compliance testing, specified by Subsection G of this Section, for equipment modified with NO_x reduction controls or a NO_x monitoring system to meet the provisions of this Chapter within 60 days of achieving normal production rate or after the end of the shake down period, but in no event later than 180 days after initial start-up. Required testing to demonstrate the performance of existing, unmodified equipment shall be completed in a timely manner, but by no later than November 1, 2005.

K. Start-up and Shutdown

1. For affected point sources that are shut down intentionally more than once per month, the owner or operator shall include NOx emitted during periods of start-up and shutdown for purposes of determining compliance with the emission factors set forth in Subsection D of this Section, or with an alternative plan approved in accordance with Paragraph E.1 or 2 of this Section.

2. For all other affected point sources, effective May 1, 2017, the owner or operator shall either comply with Paragraph K.1 of this Section or the work practice standards described in Paragraph K.3 of this Section during periods of start-up and shutdown. If the owner or operator chooses to comply with work practices standards, the emission factors set forth in Subsection D of this Section shall not apply during periods of start-up and shutdown.

3. Work Practice Standards

a. The owner or operator shall operate and maintain each affected point source, including any associated air pollution control equipment and monitoring equipment, in a manner consistent with safety and good air pollution control practices for minimizing emissions.

b. Coal-fired and fuel oil-fired electric power generating system boilers and fuel oil-fired stationary gas turbines shall use natural gas during start-up. Start-up ends when any of the steam from the boiler or steam turbine is used to generate electricity for sale over the grid, or for any other purpose (including on-site use). If another fuel must be used to support the shutdown process, natural gas shall be utilized.

c. Engage control devices such as selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) as expeditiously as possible, considering safety and manufacturer recommendations. The department shall incorporate into the applicable permit for each affected facility appropriate requirements describing the source-specific conditions or parameters identifying when operation of the control device shall commence.

d. Minimize the start-up time of stationary internal combustion engines to a period needed for the appropriate and safe loading of the engine, not to exceed 30 minutes.

e. Maintain records of the calendar date, time, and duration of each start-up and shutdown.

f. Maintain records of the type(s) and amount(s) of fuels used during each start-up and shutdown.

g. The records required by Subparagraphs K.3.e and f of this Section shall be kept for a period of at least five years and shall be made available upon request by authorized representatives of the department.

4. On or before May 1, 2017, the owner or operator shall notify the Office of Environmental Services whether each affected point source will comply with Paragraph K.1 or K.3 of this Section during periods of start-up and shutdown.

a. The owner or operator does not have to select the same option for every affected point source.

b. The department shall incorporate into the applicable permit for each affected facility the provisions of Paragraph K.1 and/or K.3 of this Section, as appropriate. The owner or operator may elect to revise the method of compliance with Subsection K of this Section for one or more affected point sources by means of a permit modification.

La. Admin. Code tit. 33, § III-2201

Promulgated by the Department of Environmental Quality, Office of Environmental Assessment, Environmental Planning Division, LR 28:290 (February 2002), repromulgated LR 28:451 (March 2002), amended LR 28:1578 (July 2002), LR 30:748 (April 2004), LR 30:1170 (June 2004), amended by the Office of the Secretary, Legal Affairs Division, LR 31:2441 (October 2005), LR 33:2088 (October 2007), LR 34:71 (January 2008), LR 36:60 (January 2010), Amended by the Office of the Secretary, Legal Division, LR 43521 (3/1/2017).

AUTHORITY NOTE: Promulgated in accordance with R.S. 30:2054.