7 Del. Admin. Code § 1120-9.0

Current through Register Vol. 28, No. 1, July 1, 2024

Section 1120-9.0 - Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced after September 18, 1978

9.1 Applicability and Designation of Affected Facility

9.1.1 Any facility covered under 9.0 of this regulation is not subject to the provisions of 2.0 of this regulation. The affected facility to which 9.0 of this regulation applies is each electric utility steam generating unit:

9.1.1.1 That is capable of combusting more than 73 megawatts (250 million BTU/hr) heat input of fossil fuel (either alone or in combination with any other fuel); and

9.1.1.2 For which construction or modification is commenced after September 18, 1978.

9.1.2 The 9.0 of this regulation 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 9.0 of this regulation. (The gas turbine emissions are subject to Subpart GG, 40 CFR Part 60 ).

9.1.3 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 the unit under the applicability of 9.0 of this regulation.

9.1.4 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 9.0 of this regulation.

9.2 [Reserved]

9.3 [Reserved]

9.4 [Reserved]

9.5 [Reserved]

9.6 [Reserved]

9.7 [Reserved]

9.8 [Reserved]

9.9 [Reserved]

9.10 [Reserved]

9.11 Definitions

As used in 9.0 of this regulation, all terms not defined herein shall have the meaning given them in the Clean Air Act and in 7DE Admin. Code1101.

"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 D388-66.

"Available purchase power" means the lesser of the following:

(a) The sum of available system capacity in all neighboring companies.

(b) 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.

(c) 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 or units in the neighboring company supplying replacement electrical power) less the electric power load on these transmission lines.

"Available system capacity" means the capacity determined by subtracting the system load and the system emergency reserves from the net system capacity.

"Boiler operating day" means a 24-hour period during which fossil fuel is combusted in a steam generating unit for the entire 24 hours.

"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.

"Combined cycle gas turbine" means a stationary turbine combustion system where heat from the turbine exhaust gases is recovered by a steam generating unit.

"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.

"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).

"Emergency condition" means that period of time when:

(a) 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:

(1) All available system capacity in the principal company interconnected with the affected facility is being operated, and

(2) All available purchase power interconnected with the affected facility is being obtained, or

(b) 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

(c) 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 (a) of this definition apply.

"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.

"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.

"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.

"Lignite" means coal that is classified as lignite A or B according to the American Society of Testing and Materials' (ASTM) Standard Specification for Classification of Coals by Rank D388-66.

"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.

"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 contractual 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 contractual arrangement.

"Potential combustion concentration" means the theoretical emissions (nanograms per joule, ng/J or lb/million BTU heat input) that would result from combustion of a fuel in an uncleaned state without emission control systems) and:

(a) For particulate matter, is:

(1) 3,000 ng/J (7.0 lb/million BTU) heat input for solid fuel; and

(2) 75 ng/J (0.17 lb./million BTU) heat input for liquid fuels.

(b) For sulfur dioxide, is determined under 9.18.2 of this regulation.

(c) For nitrogen oxides, is:

(1) 290 ng/J (0.67 lb/million BTU) heat input for gaseous fuels;

(2) 310 ng/J (0.72 lb/million BTU) heat input for liquid fuels; and

(3) 990 ng/J (2.30 lb/million BTU) heat input for solid fuels.

"Potential electrical output capacity" is defined as 33% 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 the fossil-fuel firing capacity of the steam generator exclusive of the heat input and electrical power contribution by the gas turbine.

"Principal company"means the electric utility company or companies which own the affected facility.

"Resource recovery unit" means a facility that combusts more than 75% non-fossil fuel on a quarterly (calendar) heat input basis.

"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. "24-hour period" means the period of time between 12:01 a.m. and 12:00 midnight.

"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.

"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 contractual arrangement.

"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).

"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 D388-66.

"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 contractual sales to other electric utility companies. Sales to other electric utility companies (e.g., emergency power) not on a firm contractual 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.

"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 contractual arrangement.

9.12 Standard for Particulate Matter

9.12.1 On and after the date on which the performance test required to be conducted under 1.4 of this regulation is completed, no owner or operator subject to the provisions of 9.0 of this regulation shall cause to be discharged into the atmosphere from any affected facility any gases which contain particulate matter in excess of:

9.12.1.1 13 ng/J (0.03 lb/million BTU) heat input derived from the combustion of solid, liquid, or gaseous fuel;

9.12.1.2 1% of the potential combustion concentration (99% reduction) when combusting solid fuel; and

9.12.1.3 30% of potential combustion concentration (70% reduction) when combusting liquid fuel.

9.12.2 On and after the date the particulate matter performance test required to be conducted under 1.4 of this regulation is completed, no owner or operator subject to the provisions of 9.0 of this regulation shall cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20% opacity except for one six-minute period per hour of not more than 27% opacity.

9.13 Standard for Sulfur Dioxide

9.13.1 On and after the date on which the initial performance test required to be conducted under 1.4 of this regulation is completed, no owner or operator subject to the provisions of 9.0 of this regulation shall cause to be discharged into the atmosphere from any affected facility which combusts solid fuel or solid -derived fuel, except as provided under 9.13.3, 9.13.4, 9.13.5 or 9.13.7 of this regulation, any gases which contain sulfur dioxide in excess of:

9.13.1.1 520 ng/J (1.2 lb/million BTU) heat input and 10% of the potential combustion concentration (90% reduction), or

9.13.1.2 30% of the potential combustion concentration (70% reduction), when emissions are less than 260 ng/J (0.60 lb/million BTU) heat input.

9.13.2 On and after the date on which the initial performance test required to be conducted under 1.4 of this regulation is completed, no owner or operator subject to the provisions of 9.0 of this regulation shall cause to be discharged into the atmosphere from any affected facility which combusts liquid or gaseous fuels (except for liquid or gaseous fuels derived from solid fuels and as provided under 9.13.7 of this regulation), any gases which contain sulfur dioxide in excess of:

9.13.2.1 340 ng/J (0.8 lb/million BTU) heat input and 10% of the potential combustion concentration (90 percent reduction), or

9.13.2.2 100% of the potential combustion concentration (0% reduction) when emissions are less than 86 ng/J (0.20 lb/million BTU) heat input.

9.13.3 On and after the date on which the initial performance test required to be conducted under 1.4 of this regulation is complete, no owner or operator subject to the provisions of 9.0 of this regulation 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 (1.2 lb/million BTU) heat input and 15% of the potential combustion concentration (85% reduction) except as provided under 9.13.5 of this regulation; 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.

9.13.4 Sulfur dioxide emissions are limited to 520 ng/J (1.2 lb/million BTU) heat input from any affected facility which:

9.13.4.1 Combusts 100% anthracite,

9.13.4.2 Is classified as a resource recovery facility.

9.13.5 The emission reduction requirements under 9.0 of this regulation do not apply to any affected facility that is operated under an SO₂ commercial demonstration permit issued by the Administrator of the U.S. Environmental Protection Agency in accordance with the provisions of 9.15 of this regulation.

9.13.6 Compliance with the emission limitation and percent reduction requirements under 9.0 of this regulation are both determined on a 30 day rolling average basis except as provided under 9.13.3 of this regulation.

9.13.7 When different fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

9.13.7.1 If emissions of sulfur dioxide to the atmosphere are greater than 260 ng/J (0.60 lb/million BTU) heat input:

Click here to view Image

(9-1)

Click here to view Image

(9-2)

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

Click here to view Image

(9-3)

Click here to view Image

(9-4)

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).

9.14 Standard for Nitrogen Oxides

9.14.1 On and after the date on which the initial performance test required to be conducted under 1.4 of this regulation is completed, no owner or operator subject to the provisions of 9.0 of this regulation shall cause to be discharged into the atmosphere from any affected facility, except as provided under 9.14.2 of this regulation, any gases which contain nitrogen oxides in excess of the following emission limits, based on a 30-day rolling average.

9.14.1.1 NO_x Emission Limits

Emission Limit
Fuel Type	ng/JHeat Input	(lb/million BTUHeat Input)
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	210	(0.50)
Lignite not subject to the 340 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)
Any fuel containing more than 25% by weight coal refuse is exempt from NO_x standards and NO_x monitoring requirements.

9.14.1.2 NO_x reduction requirements

Fuel Type	Percent Reductionof PotentialCombustionConcentration
Gaseous Fuels	25%
Liquid Fuels	30%
Solid Fuels	65%

9.14.2 The emission limitations under 9.14.1 of this regulation do not apply to any affected facility which is combusting coal-derived liquid fuel and is operating under a commercial demonstration permit issued by the Secretary in accordance with the provisions of 9.15 of this regulation.

9.14.3 When two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

Click here to view Image

(9-5)

where:

^ENO₂ 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.

9.15 Commercial Demonstration Permit

9.15.1 An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the Administrator of the U.S. Environmental Protection Agency for a commercial demonstration permit. Commercial demonstration permits may be issued only by the Administrator of the U.S. Environmental Protection Agency.

9.15.2 An owner or operator of an affected facility that combusts solid solvent refined coal (SRC-I) and who is issued a commercial demonstration permit by the Administrator of the U.S. Environmental Protection Agency is not subject to the SO₂ emission reduction requirements under 9.13.3 of this regulation but must, as a minimum, reduce SO₂ emissions to 20% of the potential combustion concentration (80% reduction) for each 24-hour period of steam generator operation and to less than 520 ng/J (1.2 lb/million BTU) heat input on a 30-day rolling average basis.

9.15.3 An owner or operator of a fluidized bed combustion electric utility steam generator (atmospheric or pressurized) who is issued a commercial demonstration permit by the Administrator of the U.S. Environmental Protection Agency is not subject to the SO₂ emissions reduction requirements under 9.13 of this regulation but must, as a minimum, reduce SO₂ emissions to 15% of the potential combustion concentration (85% reduction) on a 30-day rolling average basis and to less than 520 ng/J (1.2 lb/million BTU) heat input on a 30-day rolling average basis.

9.15.4 The owner or operator of an affected facility that combusts coal-derived liquid fuel and who is issued a commercial demonstration permit by the Administrator of the U.S. Environmental Protection Agency is not subject to the applicable NO_x emission limitation and percent reduction under 9.14 of this regulation 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.

9.16 Compliance Provisions

9.16.1 Compliance with the particulate matter emission limitation under 9.12.1.1 of this regulation constitutes compliance with the percent reduction requirements for particulate matter under 9.12.1.2 and 9.12.1.3 of this regulation.

9.16.2 Compliance with the nitrogen oxides emission limitation under 9.14.1 of this regulation constitutes compliance with the percent reduction requirements under 9.14 of this regulation.

9.16.3 The particulate matter emission standards under 9.12 of this regulation and the nitrogen oxides emission standards under 9.14 of this regulation apply at all times except during periods of startup, shutdown, or malfunction. The sulfur dioxide emission standards under 9.13 of this regulation apply at all times except during periods of startup, shutdown, or when both emergency conditions exist and the procedures under 9.16.4 of this regulation are implemented.

9.16.4 During emergency conditions in the principal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated pursuant to a variance, issued under the provisions of 7 Del.C., Ch 60, § 6011 or § 6012, which requires that sulfur dioxide emissions be minimized by at least the following actions:

9.16.4.1 Operating all operable flue gas desulfurization system modules, and bringing back into operation any malfunctioned module as soon as repairs are completed.

9.16.4.2 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

9.16.4.3 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 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 9.13.1, 9.13.2, 9.13.4 and 9.13.7 of this regulation for any period of operation lasting from 24 hours to 30 days when:

9.16.4.3.1 Any one flue gas desulfurization module is not operated.

9.16.4.3.2 The affected facility is operating at the maximum heat input rate,

9.16.4.3.3 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

9.16.4.3.4 The owner or operator has given the Secretary at least 30 days notice of the date and period of time over which the demonstration will be performed.

9.16.5 After the initial performance test required under 1.4 of this regulation, compliance with the sulfur dioxide emission limitations and percentage reduction requirements under 9.13 of this regulation and the nitrogen oxides emission limitations under 9.14 of this regulation 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 in 9.0 of this regulation.

9.16.6 For the initial performance test required under 1.4 of this regulation, compliance with the sulfur dioxide emission limitations and percent reduction requirements under 9.13.1 of this regulation and the nitrogen oxides emission limitation under 9.14.1 of this regulation 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 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.

9.16.7 Compliance is determined by calculating the arithmetic average of all hourly emission rates for SO₂ and NO_x for the 30 successive boiler operating days, except for data obtained during startup, shutdown, malfunction (NO_x 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.

9.16.8 If an owner or operator has not obtained the minimum quantity of emission data as required under 9.17 of this regulation, compliance of the affected facility with the emission requirements under 9.13 and 9.14 of this regulation for the day on which the 30-day period ends may be determined by the Secretary by following the applicable procedures in sections 6.0 and 7.0 of Reference Method 19.

9.17 Emission monitoring

9.17.1 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 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 Secretary).

9.17.2 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:

9.17.2.1 Sulfur dioxide emissions are monitored at both the inlet and outlet of the sulfur dioxide control device.

9.17.2.2 For a facility which qualifies under the provisions of 9.13 of this regulation, sulfur dioxide emissions are only monitored as discharged to the atmosphere.

9.17.2.3 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 emissions monitor at the inlet to the sulfur dioxide control device as required under 9.17.2.1 of this regulation.

9.17.3 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.

9.17.4 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.

9.17.5 The continuous monitoring systems under 9.17.2, 9.17.3 and 9.17.4 of this regulation 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.

9.17.6 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 Secretary of the reference methods as described in 9.17.8 of this regulation to provide emission data for a minimum of 18 hours in at least 22 out of 30 successive boiler operating days.

9.17.7 The one-hour averages required under 1.3.11 of this regulation are expressed in ng/J (lbs/million BTU) heat input and used to calculate the average emission rates under 9.16 of this regulation. The one-hour averages are calculated using the data points required under 1.3.11 of this regulation.

9.17.8 Reference methods used to supplement continuous monitoring system data to meet the minimum data requirements in 9.17 of this regulation will be used as specified below or otherwise approved by the Secretary.

9.17.8.1 Reference Methods 3, 6, and 7, as applicable, are used. The sampling location or locations are the same as those used for the continuous monitoring systems.

9.17.8.2 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 one-hour average.

9.17.8.3 For Method 7, samples are taken at approximately 30-minute intervals. The arithmetic average of these two consecutive samples represent a one-hour average.

9.17.8.4 For Method 3, the oxygen or carbon dioxide sample is to be taken for each hour when continuous SO₂ and NO_x 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 one-hour average.

9.17.8.5 For each one-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 9.17.6 of this regulation.

9.17.9 The following procedures are used to conduct monitoring system performance evaluations under 1.4 of this regulation and calibration checks under 1.3 of this regulation.

9.17.9.1 Reference method 6 or 7, as applicable, is used for conducting performance evaluations of sulfur dioxide and nitrogen oxides continuous monitoring systems.

9.17.9.2 Sulfur dioxide or nitrogen oxides, as applicable, is used for preparing calibration gas mixtures under Performance Specification 2 of Appendix B as specified in 1.3.4 of this regulation.

9.17.9.3 For affected facilities burning only fossil fuel, the span value for a continuous monitoring system for measuring opacity is between 60% and 80% 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.

9.17.9.4 All span values computed under 9.17.2.3 of this regulation for burning combinations of fossil fuels are rounded to the nearest 500 ppm.

9.17.9.5 For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel, the span value of the sulfur dioxide continuous monitoring system at the inlet to the sulfur dioxide control device is 125% of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the sulfur dioxide control device is 50% of maximum estimated hourly potential emissions of the fuel fired.

9.18 Compliance determination procedures and methods.

9.18.1 The following procedures and reference methods are used to determine compliance with the standards for particulate matter under 9.12 of this regulation.

9.18.1.1 Method 3 is used for gas analysis when applying Method 5 or Method 17.

9.18.1.2 Method 5 is used for determining particulate matter emissions and associated moisture content. Method 17 may be used for stack gas temperatures less than 160^oC (320^oF).

9.18.1.3 For Methods 5 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 smaller sampling times or volumes, when necessitated by process variables or other factors, may be approved by the Secretary.

9.18.1.4 For Method 5, the probe and filter holder heating system in the sampling train is set to provide a gas temperature no greater than 160^oC (320^oF).

9.18.1.5 For determination of particulate emissions, the oxygen or carbon dioxide sample is obtained simultaneously with each run of Methods 5 or 17 by traversing the duct at the same sampling locations. Method 1 is used for selection of the number of traverse points except that no more than 12 sample points are required.

9.18.1.6 For each run using Methods 5 or 17, the emission rate expressed in ng/J input is determined using the oxygen or carbon dioxide measurements and particulate matter measurements obtained under 9.18 of this regulation, the dry basis F^c factor and the dry basis emission rate calculation procedure contained in Method 19.

9.18.1.7 Prior to the 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.

9.18.2 The following procedures and methods are used to determine compliance with the sulfur dioxide standards under 9.13 of this regulation.

9.18.2.1 Determine the percentage of potential combustion concentration (% PCC) emitted to the atmosphere as follows:

9.18.2.1.1 Fuel Pretreatment (%R_f):

Determine the present 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 % R_f 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 9.13 of this regulation, any reduction in potential SO₂ emissions resulting from the following processes may be credited:

9.18.2.1.1.1 Fuel pretreatment (physical coal cleaning, hydrodesulfurization of fuel, oil, etc.);

9.18.2.1.1.2 Coal pulverizers; and

9.18.2.1.1.3 Bottom and flyash interactions.

9.18.2.1.2 Sulfur Dioxide Control System (%R_g):

Determine the percent sulfur dioxide reduction achieved by any sulfur dioxide control system using emissions 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.

9.18.2.1.3 Overall percent reduction (%R_o):

Determine the overall percent reduction using the results obtained in 9.18.2.1.1 and 9.18.2.1.2 of this regulation 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.

9.18.2.1.4 Percent emitted (% PCC):

Calculate the percent of potential combustion concentration emitted to the atmosphere using the following equation:

% PCC = 100 - % R_o (9-6)

9.18.2.2 Determine the sulfur dioxide emission rates following the procedures in Method 19.

9.18.3 The procedures and methods outlined in Method 19 are used in conjunction with the 30-day nitrogen-oxides emission data collected under 9.17 of this regulation to determine compliance with the applicable nitrogen oxides standard under 9.14 of this regulation.

9.18.4 Electric utility combined cycle gas turbines are performance tested for particulate matter, sulfur dioxide, and nitrogen oxides using the procedures of 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 subpart GG, 40 CFR, Part 60 . The potential uncontrolled particulate matter emission rate from a gas turbine is defined as 17 ng/J (0.04 lb/million BTU) heat input.

9.19 Reporting requirements

9.19.1 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 Secretary.

9.19.2 For sulfur dioxide and nitrogen oxides the following information is reported to the Secretary for each 24-hour period:

9.19.2.1 Calendar date;

9.19.2.2 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 noncompliance with the emission standards; and, description of corrective actions taken;

9.19.2.3 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;

9.19.2.4 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;

9.19.2.5 Identification of the times when emissions data have been excluded from the calculation of average emission rates because of startup, shutdown, malfunction (NO_x only), emergency conditions (SO₂ only), or other reasons, and justification for excluding data for reasons other than startup, shutdown, malfunction, or emergency conditions;

9.19.2.6 Identification of "F" factor used for calculations, methods of determination, and type of fuel combusted;

9.19.2.7 Identification of times when hourly averages have been obtained based on manual sampling methods;

9.19.2.8 Identification of the times when the pollutant concentration exceeded full span of the continuous monitoring system;

9.19.2.9 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.

9.19.3 If the minimum quantity of emission data as required by 9.17 of this regulation is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of 9.16 of this regulation is reported to the Secretary for that 30-day period:

9.19.3.1 The number of hourly averages available for outlet emission rates (N_o) and inlet emission rates (N_i) as applicable.

9.19.3.2 The standard deviation of hourly averages for outlet emission rates (S_o) and inlet emission rates (S_i) as applicable.

9.19.3.3 The lower confidence limit for the mean outlet emission rate (E_o*) and the upper confidence limit for the mean inlet emission rate (E_i*) as applicable.

9.19.3.4 The applicable potential combustion concentration.

9.19.3.5 The ratio of the upper confidence limit for the mean outlet emission rate (E_o*) and the allowable emission rate (Estd) as applicable.

9.19.4 If any standards under 9.13 of this regulation are exceeded during emergency conditions because of control system malfunction, the owner or operator of the affected facility shall submit a signed statement:

9.19.4.1 Indicating if emergency conditions existed and requirements under 9.16 of this regulation were met during each period, and

9.19.4.2 Listing the following information:

9.19.4.2.1 Time periods the emergency condition existed;

9.19.4.2.2 Electrical output and demand on the owner or operator's electric utility system and the affected facility;

9.19.4.2.3 Amount of power purchased from interconnected neighboring utility companies during the emergency period;

9.19.4.2.4 Percent reduction in emission achieved;

9.19.4.2.5 Atmospheric emission rate (ng/J) of the pollutant discharged; and

9.19.4.2.6 Actions taken to correct control system malfunction.

9.19.5 If fuel pretreatment credit toward the sulfur dioxide emission standard under 9.13 of this regulation is claimed, the owner or operator of the affected facility shall submit a signed statement:

9.19.5.1 Indicating what percentage cleaning credit was taken for the calendar quarter, and whether the credit was determined in accordance with the provisions of 9.18 of this regulation and Method 19, and

9.19.5.2 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.

9.19.6 For any period for which opacity, sulfur dioxide or nitrogen oxides emission 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.

9.19.7 The owner or operator of the affected facility shall submit a signed statement indicating whether:

9.19.7.1 The required continuous monitoring system calibration, span, and drift checks or other periodic audits have or have not been performed as specified.

9.19.7.2 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.

9.19.7.3 The minimum data requirements have or have not been met; or, the minimum data requirements have not been met for errors that were unavoidable.

9.19.7.4 Compliance with the standards has or has not been achieved during the reporting period.

9.19.8 For the purposes of the reports required under 1.2 of this regulation, periods of excess emissions are defined as all six-minute periods during which the average opacity exceeds the applicable opacity standards under 9.12 of this regulation. Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Secretary each calendar quarter.

9.19.9 The owner or operator of an affected facility shall submit the written reports required under 9.19 of this regulation and subpart A as described in 1.7 of this regulation to the Secretary for every calendar quarter. All quarterly reports shall be postmarked by the 30^th day following the end of each calendar quarter.

9.19.10 As used in this regulation, Method 19 is the reference method described in Appendix A of 40 CFR Part 60, dated July 1, 1982.

NOTE:

1. Whenever the word "Administrator" is found in a federal document, it shall be replaced by the word "Secretary" and whenever the words "Act" and "Subpart A" are found in a federal document, they shall be replaced by the words "7 DE Admin. Code 1101 - DEFINITIONS AND ADMINISTRATIVE PRINCIPLES."

2. Any subsections, from Title 40 of the Code of Federal Regulations, which are referenced in the text of the following 10.0 through 28.0 of this regulation are also adopted as part of this regulation.

11/27/1985

7 Del. Admin. Code § 1120-9.0