Tenn. Comp. R. & Regs. 1200-03-16-.03 - ELECTRIC UTILITY STEAM GENERATING UNITS FOR WHICH CONSTRUCTION COMMENCED AFTER SEPTEMBER 18, 1978

(1) Applicability.
(a) The affected facility to which this rule applies is each electric utility steam generating unit:
1. That is capable of combusting more than 73 megawatts (250 million Btu/hour) heat input of fossil fuel (either alone or in combination with any other fuel); and
2. For which construction or modification is commenced after September 18, 1978.
(b) This rule applies to electric utility combined cycle gas turbines that are capable of combusting more than 73 megawatts (250 million Btu/hour) heat input of fossil fuel in the steam generator. Only emissions resulting from combustion of fuels in the steam generating unit are subject to this rule. (The gas turbine emissions are subject to rule 1200-3-16-.31.)
(c) Any change to an existing fossil fuel fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, shall not bring that unit under the applicability of this rule.
(d) Any change to an existing steam generating unit originally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fossil or nonfossil) shall not bring that unit under the applicability of this rule.
(2) Definitions.
(a) "Steam generating unit" means any furnace, boiler, or other device used for combusting fuel for the purpose of producing steam (including fossil fuel fired steam generators associated with combined cycle gas turbines; nuclear steam generators are not included).
(b) "Electric utility steam generating unit" means any steam electric generating unit that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam supplied to a steam distribution system for the purpose of providing steam to a steam-electric generator that would produce electrical energy for sale is also considered in determining the electrical energy output capacity of the affected facility.
(c) "Fossil fuel" means natural gas, petroleum, coal, and any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
(d) "Subbituminous coal" means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials' (ASTM) Standard Specification for Classification of Coals by Rank D388-77.
(e) "Coal refuse" means waste products of coal mining, physical coal cleaning, and coal preparation operations (e.g. culm, gob, etc.) containing coal, matrix material, clay, and other organic and inorganic material.
(f) "Potential combustion concentration" means the theoretical emissions (ng/J, lb/million Btu heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems and:
1. For particulate matter is:
(i) 3,000 ng/J (7.0 lb/million Btu) heat input for solid fuel; and
(ii) 75 ng/J (0.17 lb/million Btu) heat input for liquid fuels.
2. For sulfur dioxide is determined under 1200-3-16-.03 -(9)(b).
3. For nitrogen oxides is:
(i) 290 ng/J (0.67 lb/million Btu) heat input for gaseous fuels;
(ii) 310 ng/J (0.72 lb/million Btu) heat input for liquid fuels; and
(iii) 990 ng/J (2.30 lb/million Btu) heat input for solid fuels.
(g) "Combined cycle gas turbine" means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit.
(h) "Interconnected" means that two or more electric generating units are electrically tied together by a network of power transmission lines and other power transmission equipment.
(i) "Electric utility company" means the largest interconnected organization, business, or governmental entity that generates electric power for sale (e.g., a holding company with operating subsidiary companies).
(j) "Principal company" means the electric utility company or companies which own the affected facility.
(k) "Neighboring company" means any one of those electric utility companies with one or more electric power interconnections to the principal company and which have geographically adjoining service areas.
(l) "Net system capacity" means the sum of the net electric generating capability (not necessarily equal to rated capacity) of all electric generating equipment owned by an electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) plus firm contractural purchases that are interconnected to the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractural arrangement.
(m) "System load" means the entire electric demand of an electric utility company's service area interconnected with the affected facility that has the malfunctioning flue gas desulfurization system plus firm contractural sales to other electric utility companies. Sales to other electric utility companies (e.g., emergency power) not on a firm contractural basis may also be included in the system load when no available system capacity exists in the electric utility company to which the power is supplied for sale.
(n) "System emergency reserves" means an amount of electric generating capacity equivalent to the rated capacity of the single largest electric generating unit in the electric utility company (including steam generating units, internal combustion engines, gas turbines, nuclear units, hydroelectric units, and all other electric generating equipment) which is interconnected with the affected facility that has the malfunctioning flue gas desulfurization system. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractural arrangement.
(o) "Available system capacity" means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.
(p) "Spinning reserve" means the sum of the unutilized net generating capability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional load. The electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output is otherwise established by contractural arrangement.
(q) "Available purchase power" means the lesser of the following:
1. The sum of available system capacity in all neighboring companies.
2. The sum of the rated capacities of the power interconnection devices between the principal company and all neighboring companies, minus the sum of the electric power load on these interconnections.
3. The rated capacity of the power transmission lines between the power interconnection devices and the electric generating units (the unit in the principal company that has the malfunctioning flue gas desulfurization system and the unit(s) in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines.
(r) "Spare flue gas desulfurization system module" means a separate system of sulfur dioxide emission control equipment capable of treating an amount of flue gas equal to the total amount of flue gas generated by an affected facility when operated at maximum capacity divided by the total number of nonspare flue gas desulfurization modules in the system.
(s) "Emergency condition" means that period of time when:
1. The electric generation output of an affected facility with a malfunctioning flue gas desulfurization system cannot be reduced or electrical output must be increased because:
(i) All available system capacity in the principal company interconnected with the affected facility is being operated, and
(ii) All available purchase power interconnected with the affected facility is being obtained, or
2. The electric generation demand is being shifted as quickly as possible from an affected facility with a malfunctioning flue gas desulfurization system to one or more electrical generating units held in reserve by the principal company or by a neighboring company, or
3. An affected facility with a malfunctioning flue gas desulfurization system becomes the only available unit to maintain a part or all of the principal company's system emergency reserves, and the unit is operated in spinning reserve at the lowest practical electric generation load consistent with not causing significant physical damage to the unit. If the unit is operated at a higher load to meet load demand, an emergency condition would not exist unless the conditions under part 1. of this definition apply.
(t) "Electric utility combined cycle gas turbine" means any combined cycle gas turbine used for electric generation that is constructed for the purpose of supplying more than one-third of its potential electric output capacity and more than 25 MW electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the purpose of providing steam to a steam electric generator that would produce electrical power for sale is also considered in determining the electrical energy output capacity of the affected facility.
(u) "Potential electrical output capacity" is defined as 33 percent of the maximum design heat input capacity of the steam generating unit (e.g., a steam generating unit with a 100-MW (340 million Btu/hr) fossil fuel heat input capacity would have a 33-MW potential electrical output capacity). For electric utility combined cycle gas turbines, the potential electrical output capacity is determined on the basis of fossil fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.
(v) "Anthracite" means coal that is classified as anthracite according to the American Society of Testing and Materials' (ASTM) Standard Specification for Classification of Coals by Rank D388-77.
(w) "Solid-derived fuel" means any solid, liquid, or gaseous fuel derived from solid fuel for the purpose of creating useful heat and includes, but is not limited to, solvent refined coal, liquified coal, and gasified coal.
(x) "24-hour period" means the period of time between 12:01 a.m. and 12:00 midnight.
(y) "Resource recovery unit" means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis.
(z) "Noncontinental area" means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.
(aa) "Boiler operating day" means a 24-hour period during which fossil fuel is combusted in a steam generating unit for the entire 24 hours.
(3) Standard for Particulate Matter.
(a) On and after the date on which the performance test required to be conducted under paragraph 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter in excess of:
1. 13 ng/J (0.03 lb/million Btu) heat input derived from the combustion of solid, liquid, or gaseous fuel;
2. 1 percent of the potential combustion concentration (99 percent reduction) when combusting solid fuel; and
3. 30 percent of potential combustion concentration (70 percent reduction) when combusting liquid fuel.
(b) On and after the date the particulate matter performance test required to be conducted under 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20 percent opacity (6-minute average), except for one 6-minute period per hour of not more than 27 percent opacity.
(4) Standard for Sulfur Dioxide.
(a) On and after the date on which the initial performance test required to be conducted under 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid-derived fuel, except as provided under subparagraphs (c), (d), (f), or (h) of this paragraph, any gases which contain sulfur dioxide in excess of:
1. 520 ng/J (1.20 lb/million Btu) heat input and 10 percent of the potential combustion concentration (90 percent reduction), or
2. 30 percent of the potential combustion concentration (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/million Btu) heat input.
(b) On and after the date on which the initial performance test required to be conducted under 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall cause to be from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under subparagraphs (e) or (h) of this paragraph), any gases which contain sulfur dioxide in excess of:
1. 340 ng/J (0.80 lb/million Btu) heat input and 10 percent of the potential combustion concentration (90 percent reduction), or
2. 100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/million Btu) heat input.
(c) On and after the date on which the initial performance test required to be conducted under 1200-3-16-.01(5) is complete, no owner or operator subject to the provisions of this rule shall cause to be discharged into the atmosphere from any affected facility which combusts solid solvent refined coal (SRC-I) any gases which contain sulfur dioxide in excess of 520 ng/J (1.20 lb/million Btu) heat input and 15 percent of the potential combustion concentration (85 percent reduction) except as provided under subparagraph (f) of this paragraph; compliance with the emission limitation is determined on a 30-day rolling average basis and compliance with the percent reduction requirement is determined on a 24-hour basis.
(d) Sulfur dioxide emissions are limited to 520 ng/J (1.20 lb/million Btu) heat input from any affected facility which:
1. Combusts 100 percent anthracite, or
2. Is classified as a resource recovery facility, or
3. Is located in a noncontinental area and combusts solid fuel or solid-derived fuel.
(e) Sulfur dioxide emissions are limited to 340 ng/J (0.80 lb/million Btu) heat input from any affected facility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solid-derived fuels).
(f) The emission reduction requirements under this paragraph do not apply to any affected facility that is operated under an SO2 commercial demonstration permit issued in accordance with the provisions of 1200-3-16-.03(6).
(g) Compliance with the emission limitation and percent reduction requirements under this paragraph are both determined on a 30-day rolling average basis except as provided under subparagraph (c) of this paragraph.
(h) When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:
1. If emissions of sulfur dioxide to the atmosphere are greater than 260 ng/J (0.60 lb/million Btu) heat input:

ESO2 = (340 x + 520 y)/100 and

PSO2 = 10 percent

2. If emissions of sulfur dioxide to the atmosphere are equal to or less than 260 ng/J (0.60 lb/million Btu) heat input:

ESO2 = (340 x + 520 y)/100 and

PSO2 = (90 x + 70 y)/100

where:

ESO2= is the prorated sulfur dioxide emission limit (ng/J heat input).

PSO2 = is the percentage of potential sulfur dioxide emission allowed (percent reduction required = 100 - PSO2).

x is the percentage of total heat input derived from the combustion of liquid or gaseous fuels (excluding solid- derived fuels )

y is the percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels)

(5) Standard for Nitrogen Oxides.
(a) On and after the date on which the initial performance test required to be conducted under 1200-3-16-.01(5) is completed, no owner or operator subject to the provisions of this rule shall cause to be discharged into the atmosphere from any affected facility, except as provided under subparagraph (b) of this paragraph, any gases which contain nitrogen oxides in excess of the following emission limits, based on a 30-day rolling average.
1. NOx Emission Limits -

Fuel type Emission limit ng/J Heat input (lb/M Btu)
Gaseous Fuels:
Coal-derived fuels 210 (0.50)
All other fuels 86 (0.20)
Liquid Fuels:
Coal derived fuels 210 (0.50)
Shale oil 210 (0.50)
All other fuels 130 (0.30)
Solid Fuels:
Coal derived fuels 210 (0.50)
Any fuel containing more than 25%, by weight, coal refuse requirements Exempt from NOx standards and NOx monitoring
Any fuel containing more than 25%, by weight, lignite if the lignite is mined in North Dakota, South Dakota, or Montana and is combusted in a slag tap furnace 340 (0.80)
Lignite not subject to the ng/J heat input emission limit 260 (0.60)
Subbituminous coal 210 (0.50)
Bituminous coal 260 (0.60)
Anthracite coal 260 (0.60)
All other fuels 260 (0.60)
2. NOx reduction requirements -

Fuel type

Percent reduction of potential combustion concentration

Gaseous fuels

25%

Liquid fuels

30%

Solid fuels

65%

(b) The emission limitations under subparagraph (a) of this paragraph do not apply to any affected facility which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit issued in accordance with the provisions of 1200-3- 16-.03(6).
(c) When two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

ENOX = (86 w + 130 x + 210 y + 260 z)/ 100

where:

ENOx is the applicable standard for nitrogen oxides when multiple fuels are combusted simultaneously (ng/J heat input);

w is the percentage of total heat input derived from the combustion of fuels subject to the 86 ng/J heat input standard;

x is the percentage of total heat input derived from the combustion of fuels subject to the 130 ng/J heat input standard;

y is the percentage of total heat input derived from the combustion of fuels subject to the 210 ng/J heat input standard; and

z is the percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard.

(6) Commercial demonstration permit.
(a) An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the EPA Administrator for a commercial demonstration permit in accordance with section 60.45a, "Commerical demonstration permit," as specified in the Federal Register, Vol. 44, No. 113, June 11, 1979.
(b) An owner or operator of an affected facility that combusts solid solvent refined coal (SRC-I) and who is issued a commercial demonstration permit is not subject to the SO2 emission reduction requirements under 1200-3-16-.03(4)(c) but must, as a minimum, reduce SO2 emissions to 20 percent of the potential combustion concentration (80 percent reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.20 lb/million Btu) heat input on a 30-day rolling average basis.
(c) An owner or operator of a fluidized bed combustion electric utility steam generator (atmospheric or pressurized) who is issued a commercial demonstration permit is not subject to the SO2 emissions reduction requirements under 1200-3-16-.03(4)(a) but must, as a minimum, reduce SO2 emissions to 15 percent of the potential combustion concentration (85 percent reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.20 lb/million Btu) heat input on a 30-day rolling average basis.
(d) The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit is not subject to the applicable NOx emission limitation and percent reduction under 1200-3-16-.03(5)(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/million Btu) heat input on a 30-day rolling average basis.
(e) Commerical demonstration permits may not exceed the following equivalent MW electrical generation capacity for any one technology category, and the total equivalent MW electrical generation capacity for all commercial demonstration plants may not exceed 15,000 MW.

Technology Pollutant Equivalent electrical capacity (MW electrical output)
Solid solvent refined coal (SRC-I) SO2 6,000 10,000
Fluidized bed combustion (atmospheric) SO2 400-3,000
Fluidized bed combustion (pressurized) SO2 400-1,200
Coal liquification NOx 750-10,000
Total allowable for all technologies 15,000
(7) Compliance provisions.
(a) Compliance with the particulate matter emission limitation under 1200-3-16 - .03(3)(a)1. constitutes compliance with the percent reduction requirements for particulate matter under 1200-3-16-.03(2) and (3).
(b) Compliance with the nitrogen oxides emission limitation under 1200-3-16-.03 -(5)(a) constitutes compliance with the percent reduction requirements under 1200-3-16 - .03(5)(a)2.
(c) The particulate matter emission standards under 1200-3-16-.03(3) and the nitrogen oxides emission standards under 1200-3-16-.03(5) apply at all times except during periods of startup, shutdown, or malfunction. The sulfur dioxide emission standards under 1200-3-16-.03(4) apply at all times except during periods of start-up, shutdown, or when both emergency conditions exist and the procedures under subparagraph (d) of this paragraph are implemented.
(d) During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if sulfur dioxide emissions are minimized by:
1. Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed,
2. Bypassing flue gases around only those flue gas desulfurization system modules that have been taken out of operation because they were incapable of any sulfur dioxide emission reduction or which would have suffered significant physical damage if they had remained in operation, and
3. Designing, constructing, and operating a spare flue gas desulfurization system module for an affected facility larger than 365 MW (1,250 million Btu/hr) heat input (approximately 125 MW electrical output capacity). The Technical Secretary may at his discretion require the owner or operator within 60 days of notification to demonstrate spare module capability. To demonstrate this capability, the owner or operator must demonstrate compliance with the appropriate requirements under subparagraphs (a), (b), (d), (e), and (i) under 1200-3-16-.03 - (4) for any period of operation lasting from 24 hours to 30 days when:
(i) Any one flue gas desulfurization module is not operated,
(ii) The affected facility is operating at the maximum heat input rate,
(iii) The fuel fired during the 24-hour to 30-day period is representative of the type and average sulfur content of fuel used over a typical 30-day period, and
(iv) The owner or operator has given the Technical Secretary at least 30 days notice of the date and period of time over which the demonstration will be performed.
(e) After the initial performance test required under 1200-3-16-.01(5) compliance with the sulfur dioxide emission limitations and percentage reduction requirements under 1200- 3-16-.03(4) and the nitrogen oxides emission limitations under 1200-3-16-.03(5) is based on the average emission rate for 30 successive boiler operating days. A separate performance test is completed at the end of each boiler operating day after the initial performance test, and a new 30 day average emission rate for both sulfur dioxide and nitrogen oxides and a new percent reduction for sulfur dioxide are calculated to show compliance with the standards.
(f) For the initial performance test required under 1200-3-16-.01(5), compliance with the sulfur dioxide emission limitations and percent reduction requirements under 1200-3- 16-.03(4) and the nitrogen oxides emission limitation under 1200-3-16-.03(5) is based on the average emission rates for sulfur dioxide, nitrogen oxides, and percent reduction for sulfur dioxide for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days prior notice is required unless otherwise specified by the Technical Secretary. The initial performance test is to be scheduled so that the first boiler operating day of the 30 successive boiler operating days is completed within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility.
(g) Compliance is determined by calculating the arithmetic average of all hourly emission rates for SO2 and NOx for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NOx only), or emergency conditions (SO2 only). Compliance with the percentage reduction requirement for SO2 is determined based on the average inlet and average outlet SO2 emission rates for the 30 successive boiler operating days.
(h) If an owner or operator has not obtained the minimum quantity of emission data as required under 1200-3-16-.03(8) of this rule, compliance of the affected facility with the emission requirements under 1200-3-16-.03(4) and (5) of this rule for the day on which the 30-day period ends may be determined by the Technical Secretary by following the applicable procedures in sections 6.0 and 7.0 of Reference Method 19 as specified in 1200-3-16-.01(5)(g) 19.
(8) Emission monitoring.
(a) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous montoring system, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere, except where gaseous fuel is the only fuel combusted. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored upstream of the interference (at the inlet to the FGD system). If opacity interference is experienced at all locations (both at the inlet and outlet of the sulfur dioxide control system), alternate parameters indicative of the particulate matter control system's performance are monitored (subject to the approval of the Technical Secretary).
(b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous monitoring system, and record the output of the system, for measuring sulfur dioxide emissions, except where natural gas is the only fuel combusted, as follows:
1. Sulfur dioxide emissions are monitored at both the inlet and outlet of the sulfur dioxide control device.
2. For a facility which qualifies under the provisions of 1200-3-16-.03(4)(d), sulfur dioxide emissions are only monitored as discharged to the atmosphere.
3. An "as fired" fuel monitoring system (upstream of coal pulverizers) meeting the requirements of Method 19 may be used to determine potential sulfur dioxide emissions in place of a continuous sulfur dioxide emission monitor at the inlet to the sulfur dioxide control device as required under part (b)1. of this paragraph.
(c) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous monitoring system, and record the output of the system, for measuring nitrogen oxides emissions discharged to the atmosphere.
(d) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a continuous monitoring system, and record the output of the system, for measuring the oxygen or carbon dioxide content of the flue gases at each location where sulfur dioxide or nitrogen oxides emissions are monitored.
(e) The continuous monitoring systems under subparagraphs (b), (c), and (d) of this paragraph are operated and data recorded during all periods of operation of the affected facility including periods of startup, shutdown, malfunction, or emergency conditions, except for continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments.
(f) When emission data are not obtained because of continuous monitoring system breakdowns, repairs, calibration checks, and zero and span adjustments, emission data will be obtained by using other monitoring systems as approved by the Technical Secretary or the reference methods as described in subparagraph (h) of this paragraph to provide emission data for a minimum of 18 hours in at least 22 out of 30 successive boiler operating days.
(g) The 1-hour averages required under 1200-3-16-.01(8)(h) are expressed in ng/J (lbs/million Btu) heat input and used to calculate the average emission rates under 1200-3-16-.03(7). The 1-hour averages are calculated using the data points required under 1200-3-16-.01(8)(b). At least two data points must be used to calculate the 1hour averages.
(h) Reference methods used to supplement continuous monitoring system data to meet the minimum data requirements in 1200-3-16-.03(8)(f) will be used as specified below or otherwise approved by the Technical Secretary.
1. Reference Methods 3, 6, and 7, as specified in 1200-3-16-.01(5)(g) 3., 6., and 7., as applicable are used. The sampling location(s) are the same as those used for the continuous monitoring system.
2. For Method 6, the minimum sampling time is 20 minutes and the minimum sampling volume is 0.02 dscm (0.71 dscf) for each sample. Samples are taken at approximately 60-minute intervals. Each sample represents a 1-hour average.
3. For Method 7, samples are taken at approximately 30-minute intervals. The arithmetic average of these two consecutive samples represents a 1-hour average.
4. For Method 3, the oxygen or carbon dioxide sample is to be taken for each hour when continuous SO2 and NOx data are taken or when Methods 6 and 7 are required. Each sample shall be taken for a minimum of 30 minutes in each hour using the integrated bag method specified in Method 3. Each sample represents a 1-hour average.
5. For each 1-hour average, the emissions expressed in ng/J (lb/million Btu) heat input are determined and used as needed to achieve the minimum data requirements of subparagraph (f) of this paragraph.
(i) The following procedures are used to conduct monitoring system performance evaluations under 1200-3-16-.01(8)(c) and calibration checks under 1200-3-16 - .01(8)(d).
1. Reference Method 6 or 7, as applicable, is used for conducting performance evaluations of sulfur dioxide and nitrogen oxides continuous monitoring systems.
2.

(Reserved)

3. For affected facilities burning only fossil fuel, the span value for a continuous monitoring system for measuring opacity is between 60 and 80 percent and for a continuous monitoring system measuring nitrogen oxides is determined as follows:

Fossil fuel Span value for nitrogen oxides (ppm)
Gas 500
Liquid 500
Solid 1,000
Combination 500 (x+y)+1,000z

where:

x is the fraction of total heat input derived from gaseous fossil fuel,

y is the fraction of total heat input derived from liquid fossil fuel, and

z is the fraction of total heat input derived from solid fossil fuel.

4. All span values computed under subparagraph (b)3. of this paragraph for burning combinations of fossil fuels are rounded to the nearest 500 ppm.
5. For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel, the span value of the sulfur monitoring system at the inlet to the sulfur dioxide control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the sulfur dioxide control device is 50 percent of maximum estimated hourly potential emissions of the fuel fired.
(9) Compliance determination procedures and methods.
(a) The following procedures and reference methods are used to determine compliance with the standards for particulate matter under 1200-3- 16-.03(3).
1. Method 3 is used for gas analysis when applying Method 5, 5B, or 17.
2. Method 5, 5B, or 17 is used for determining particulate matter emissions and associated moisture content as follows: Method 5 is to be used at affected facilities without wet FGD systems; Method 5B is to be used only after wet FGD systems; and Method 17 may be used at facilities with or without wet FGD systems provided that the stack gas temperature at the sampling location does not exceed a temperature of 160° C (320° F). The procedures of sections 2.1 and 2.3 of Method 5B may be used in Method 17 only if it is used after wet FGD systems. Do not use Method 17 after wet FGD systems if the effluent is saturated or laden with water droplets.
3. For Method 5, 5B, or 17, Method 1 is used to select the sampling site and the number of traverse sampling points. The sampling time for each run is at least 120 minutes and the minimum sampling volume is 1.7 dscm (60 dscf) except that small sampling times or volumes, when necessitated by process variables or other factors, may be approved by the Technical Secretary.
4. For Method 5 or 5B the probe and filter holder heating system in the sampling train is set to provide an average gas temperature of 160°C (320°F).
5. For determination of particulate emissions, the oxygen or carbon dioxide sample is obtained simultaneously with each run of Method 5, 5B, or 17 by traversing the duct at the same sampling location. Method 1 is used for selection of the number of oxygen or carbon dioxide traverse points except that no more than 12 sample points are required.
6. For each run using Method 5, 5B, or 17, the emission rate expressed in ng/J heat input is determined using the oxygen or carbon-dioxide measurement and particulate matter measurements obtained under this section, the dry basis Fc-factor and the dry basis emission rate calculation procedure contained in Method 19 (1200-3-16-.01(5)(g) 19).
7. Prior to the Technical Secretary's issuance of a particulate matter reference method that does not experience sulfuric acid mist interference problems, particulate matter emissions may be sampled prior to a wet flue gas desulfurization system.
(b) The following procedures and methods are used to determine compliance with the sulfur dioxide standards under 1200-3-16-.03(4).
1. Determine the percent of potential combustion concentration (percent PCC) emitted to the atmosphere as follows:
(i) Fuel Pretreatment (%Rf): Determine the percent reduction achieved by any fuel pretreatment using the procedures in Method 19. Calculate the average percent reduction for fuel pretreatment on a quarterly basis using fuel analysis data. The determination of percent Rf to calculate the percent of potential combustion concentration emitted to the atmosphere is optional. For purposes of determining compliance with any percent reduction requirements under 1200-3-16-.03(4), any reduction in potential SO2 emissions resulting from the following processes may be credited:
(I) Fuel pretreatment (physical coal cleaning), hydrodesulfurization of fuel oil, etc.).
(II) Coal pulverizers, and
(III) Bottom and flyash interactions.
(ii) Sulfur Dioxide Control System (%Rg): Determine the percent sulfur dioxide reduction achieved by any sulfur dioxide control system using emission rates measured before and after the control system, following the procedures in Method 19 or, a combination of an "as fired" fuel monitor and emission rates measured after the control system, following the procedures in Method 19. When the 'as fired" fuel monitor is used, the percent reduction is calculated using the average emission rate from the sulfur dioxide control device and the average SO2 input rate from the "as fired" fuel analysis for 30 successive boiler operating days.
(iii) Overall percent reduction (% Ro): Determine the overall percent reduction using the results obtained in subparts (b)1.
(i) and
(ii) of this paragraph following the procedures in Method 19. Results are calculated for each 30-day period using the quarterly average percent sulfur reduction determined for fuel pretreatment from the previous quarter and the sulfur dioxide reduction achieved by a sulfur dioxide control system for each 30-day period in the current quarter.
(iv) Percent emitted (% PCC): Calculate the percent of potential combustion concentration emitted to the atmosphere using the following equation: Percent PCC = 100-Percent Ro.
2. Determine the sulfur dioxide emission rates following the procedures in Method 19.
(c) The procedures and methods outlined in Method 19 are used in conjunction with the 30-day nitrogen-oxides emission data collected under 1200-3-16-.03(8) to determine compliance with the applicable nitrogen oxides standard under 1200-3-16-.03(5).
(d) Electric utility combined cycle gas turbines are performance tested for particulate matter, sulfur dioxide, and nitrogen oxides using Method 19. The sulfur dioxide and nitrogen oxides emission rates from the gas turbine used in Method 19 calculations are determined when the gas turbine is performance tested under 1200-3-16-.31. The potential uncontrolled particulate matter emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/million Btu) heat input.
(10) Reporting Requirements.
(a) For sulfur dioxide, nitrogen oxides, and particulate matter emissions, the performance test data from the initial performance test and from the performance evaluation of the continuous monitors (including the transmissometer) are submitted to the Technical Secretary.
(b) For sulfur dioxide and nitrogen oxides the following information is reported to the Technical Secretary for each 24-hour period.
1. Calendar date.
2. The average sulfur dioxide and nitrogen oxide emission rates (ng/J or lb/million Btu) for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the emission standards; and description of corrective actions taken.
3. Percent reduction of the potential combustion concentration of sulfur dioxide for each 30 successive boiler operating days, ending with the last 30-day period in the quarter; reasons for non-compliance with the standard; and description of corrective actions taken.
4. Identification of the boiler operating days for which pollutant or dilutent data have not been obtained by an approved method for at least 18 hours of operation of the facility; justification for not obtaining sufficient data; and description of corrective actions taken.
5. Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NOx only), emergency conditions (SO2 only), or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction, or emergency conditions.
6. Identification of "F" factor used for calculations, method of determination, and type of fuel combusted.
7. Identification of times when hourly averages have been obtained based on manual sampling methods.
8. Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system.
9. Description of any modifications to the continuous monitoring system which could affect the ability of the continuous monitoring system to comply with Performance Specifications 2 or 3.
(c) If the minimum quantity of emission data as required by 1200-3-16-.03(8) is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of 1200-3-16-.03(7)(h) is reported to the Technical Secretary for that 30-day period:
1. The number of hourly averages available for outlet emission rates (no) and inlet emission rates (ni) as applicable.
2. The standard deviation of hourly averages for outlet emission rates (so) and inlet emission rates (si) as applicable.
3. The lower confidence limit for the mean outlet emission rate (Eo*) and the upper confidence limit for the mean inlet emission rate (Ei*) as applicable.
4. The applicable potential combustion concentration.
5. The ratio of the upper confidence limit for the mean outlet emission rate (Eo*) and the allowable emission rate (Estd) as applicable.
(d) If any standards under 1200-3-16-.03(4) are exceeded during emergency conditions because of control system malfunction, the owner or operator of the affected facility shall submit a signed statement:
1. Indicating if emergency conditions existed and requirements under 1200-3-16 - .03(7)(d) were met during each period and
2. Listing the following information:
(i) Time periods the emergency condition existed;
(ii) Electrical output and demand on the owner or operator's electric utility system and the affected facility;
(iii) Amount of power purchased from interconnected neighboring utility companies during the emergency period;
(iv) Percent reduction in emissions achieved;
(v) Atmospheric emission rate (ng/J) of the pollutant discharged; and
(vi) Actions taken to correct control system malfunction.
(e) If fuel pretreatment credit toward the sulfur dioxide emission standard under 1200-3- 16-.03(4) is claimed, the owner or operator of the affected facility shall submit a signed statement:
1. Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of 1200-3- 16-.03(9) and Method 19; and
2. Listing the quantity, heat content, and date each pretreated fuel shipment was received during the previous quarter; the name and location of the fuel pretreatment facility; and the total quantity and total heat content of all fuels received at the affected facility during the previous quarter.
(f) For any periods for which opacity, sulfur dioxide, or nitrogen oxides emissions data are not available, the owner or operator of the affected facility shall submit a signed statement indicating if any changes were made in operation of the emission control system during the period of data unavailability. Operations of the control system and affected facility during periods of data unavailability are to be compared with operation of the control system and affected facility before and following the period of data unavailability.
(g) The owner or operator of the affected facility shall submit a signed statement indicating whether:
1. The required continuous monitoring system calibration, span, and drift checks or other periodic audits have or have not been performed as specified.
2. The data used to show compliance was or was not obtained in accordance with approved methods and procedures of this part and is representative of plant performance.
3. The minimum data requirements have or have not been met; or the minimum data requirements have not been met for errors that were unavoidable.
4. Compliance with the standards has or has not been achieved during the reporting period.
(h) For the purposes of the reports required under 1200-3-16-.01(7), periods of excess emissions are defined as all 6-minute periods during which the average opacity exceeds the applicable opacity standards under 1200-3-16-.03(3)(b). Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Technical Secretary each calendar quarter.
(i) The owner or operator of an affected facility shall submit the written reports required under this paragraph and rule 1200-3-16-.01 to the Technical Secretary for every calendar quarter. All quarterly reports shall be postmarked by the 30th day following the end of each calendar quarter.

Notes

Tenn. Comp. R. & Regs. 1200-03-16-.03
Original rule filed July 21, 1980; effective September 8, 1980. Amendment filed September 21, 1988; effective November 6, 1988.

Authority: T.C.A. §§ 68-25-105 and 4-5-202.

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