1 Subpart Da—Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978

§60.40Da Applicability and designation of affected facility.

(a) Except as specified in paragraph (e) of this secti on, the affected facility to which this subpart applies is each electric utility steam generating unit:

(1) That is capable of combusting more than 73 me gawatts (MW) (250 million British thermal units per hour (MMBtu/ hr h )) heat input of fossil fuel (either alone or in combination with any other fuel); and

(2) For which construction, modification, or rec onstruction is commenced after September 18, 1978.

(b) An IGCC electric utility steam generating unit (both the stationary combustion turbine and any associated duct burners) is subject to this part and is not subject to subpart GG or KKKK of this part if both of the conditions specified in paragraphs (b)(1) and (2) of this section are met.

(1) The IGCC electric utility steam generating unit is capable of combusting more than 73 MW (250

MMBtu/ hr h ) heat input of fossil fuel (either alone or in combination with any other fuel ); ) in the combustion turbine engine and associat ed heat recovery steam generator; and

(2) The IGCC electric utility steam generating unit commenced construction, modification, or reconstruction after February 28, 2005.

(c) Any change to an existing fossil-fuel-fired steam generating unit to accommodate the use of combustible materials, other than fossil fuels, sha ll not bring that unit under the applicability of this subpart.

(d) Any change to an existing steam generating unit or iginally designed to fire gaseous or liquid fossil fuels, to accommodate the use of any other fuel (fos sil or nonfossil) shall not bring that unit under the applicability of this subpart.

(e) Applicability of the requirement of this subpart to an electric utility combined cycle gas turbine other than an IGCC electric utility steam generating unit is as specified in paragraphs (e)(1) and (2 through (3 )

of this section.

(1) Heat Affected facilities (i.e. heat recovery steam generators used with duct burners and ) associated

with an electric utility combined cycle gas a stationary combustion turbine that are capable of combusting more than 73 MW (250 MMBtu/ hr h ) heat input of fossil fuel are subject to this subpart except in cases when the affected facility (i.e. heat recovery steam generator ) meets the applicability requirements of and is subject to subpart KKKK of this part.

(2) For heat recovery steam generators use used with duct burners subject to this subpart, only emissions resulting from the combustion of fuels in the steam ge nerating unit (i.e. duct burners) are subject to the standards under this subpart. (The emissions resulti ng from the combustion of fuels in the stationary combustion turbine engine are subject to subpart GG or KKK KKKK , as applicable, of this part).

(3) Any affected facility that meets the applicability re quirements and is subject to subpart Eb or subpart CCCC of this part is not subject to the emission standards under subpart Da.

§60.41Da Definitions.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Act and in subpart A of this part.

Affirmative defense means, in the context of an enforcement proceeding, a response or defense put Comment [CF1]: Simplify title

Comment [CF2]: Clarify heat input of an IGCC facility

Comment [CF3]: Fix typo

Comment [CF4]: Exempt owner/operators of

MWC & CISWI from the criteria pollutant standards

under subpart Da. Could have startup burners

greater than 250 MMBtu/hr that would make them
applicable to Da.

Comment [CF5]: Delete definitions not used in

Da2 forward by a defendant, regarding which the defendant has the burden of proof, and the merits of which are independently and objectively evaluated in a judicial or administrative proceeding.

Anthracite means coal that is classified as anthracite according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17).

Available purchase power means the lesser of the following:

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

(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 transmiss ion lines between the power interconnection devices and the electric generating units (the unit in the princi pal company that has the malfunctioning flue gas desulfurization system and the unit(s) in the neighboring company supplyi ng replacement electrical power) less the electric power load on these transmission lines.

Available system capacity means the capacity determined by subtracti ng the system load and the system emergency reserves from the net system capacity.

Biomass means plant materials and animal waste.

Bituminous coal means coal that is classified as bitumi nous according to the American Society of Testing and Materials in ASTM D388 (i ncorporated by reference, see §60.17).

Boiler operating day for units constructed, reconstructed, or modified on or before February 28 29 , 2005, means a 24-hour period during which fossil fuel is co mbusted in a steam-generating unit for the entire 24 hours. For units constructed, reconstructed, or modified after February 28, 2005, boiler operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the steam-generating unit. It is not necessary for fuel to be combusted the entire 24-hour period.

Coal means all solid fuels classified as anthraci te, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in AS TM D388 (incorporated by reference, see §60.17) and coal refuse. Synthetic fuels derived from coal for th e purpose of creating useful heat, including but not limited to solvent-refined coal, gasified coal ( not meeting the definition of natural gas), coal-oil mixtures, and coal-water mixtures are included in this definition for the purposes of this subpart.

Coal-fired electric utility steam generating unit means an electric utility steam generating unit that burns coal, coal refuse, or a synthetic gas derived from coal either exclusively, in any combination together, or in any combination with other fuels in any amount.

Coal refuse means waste products of coal mining, physi cal coal cleaning, and coal preparation operations ( e.g. culm, gob, etc.) containing coal, matrix mate rial, clay, and other organic and inorganic

material.

Cogeneration, also known as “combined heat and power,” means a steam

- generating unit that

simu ltaneously produces both electric (or mechanical) a nd useful thermal energy from the same primary

energy source.

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

Dry flue gas desulfurization technology or dry FGD means a sulfur dioxide control system that is located downstream of the steam generati ng unit and removes sulfur oxides (SO 2 ) from the combustion3 gases of the steam generating unit by contactin g the combustion gases with an alkaline reagent and water, whether introduced separately or as a prem ixed slurry or solution and forming a dry powder

material. This definition includes devices where the dr y powder material is subsequently converted to

anot her form. Alkaline slurries or solutions used in dry FGD technology include, but are not limited to,

lime and sodium.

Combined heat and power, also known as “cogeneration,” means a steam-generating unit that simultaneously produces both electric (or mechanical) and useful thermal energy from the same primary

energy source. Duct burner means a device that combusts fuel a nd that is placed in the exhaust duct from another source, such as a stationary gas turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases be fore the exhaust gases ente r a heat recovery steam generating unit.

Electric utility combined cycle gas turbine means any combined cycle gas turbine used for electric generation that is constructed for the purpose of suppl ying more than one-third of its potential electric output capacity and more than 25 MW net-electrical output to any utility power distribution system for sale. Any steam distribution system that is constructed for the pur pose 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.

Electric utility company means the largest interconnected organizati on, business, or governmental entity that generates electric power for sale ( e.g. , a holding company with opera ting subsidiary companies).

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 pote ntial electric output capacity and more than 25 MW net-electrical output to any utilit y power distribution system for sa le. Also, any steam supplied to a steam distribution system for the purpose of provid ing steam to a steam-elect ric generator that would produce electrical energy for sale is considered in de termining the electrical energy output capacity of the affected facility.

Electrostatic precipitator or ESP means an add-on air pollution control device used to capture particulate matter (PM) by charging the particles usi ng an electrostatic field, collecting the particles using a grounded collecting surface, and tran sporting the particles into a hopper.

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 electrica l output must be increased because:

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

(ii) All available purchase power interconnected w ith 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 malfunc tioning 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 fl ue gas desulfurization system becomes the only

avai lable unit to maintain a part or all of the prin cipal 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 un less the conditions under paragraph (1) of this definition apply.4 Emission limitation means any emissions limit or operating limit.

Emission rate period mea ns any calendar month included in a 12

- month rolling average period.

Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirement s established under 40 CFR 52.21 or under 40 CFR

51.18 and 51.24.

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.

Gaseous fuel means any fuel derived from coal or petroleum that is present as a gas at standard conditions and includes, but is not limited to, natural gas, refinery fuel gas, process gas, coke-oven gas, synthetic gas, and gasified coal.

Gross output means the gross useful work performed by the steam generated and, for an IGCC electric utility steam generating unit , the work performed by the stationary combustion turbines. For a unit generating only electricity, the gross usef ul work performed is the gross electrical output from the unit's

turbine /generator sets. For a cogeneration unit , the gross useful work performed is the gross electrical or mechanical output plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electri cal or mechanical output or to enhance the performance of the unit ( i.e. , steam delivered to an industrial process).

Gross energy output means:

(1) For facilities constructed, reco nstructed, or modified before May 4, 2011, the gross electrical or mechanical output from the affected facility plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., st eam delivered to an industrial process);

(2) For facilities constructed, re constructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility minus any electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compressor) plus 75 percent of the useful th ermal output measured re lative to ISO conditions that is not used to generate additi onal electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

(3) For combined heat and power fa cilities constructed, reconstructed, or modified after May 3, 2011, the gross electrical or mechanical output from the affected facility divided by 0.95 minus any electricity used to power the feedwater pumps and any associ ated gas compressors (air separation unit main compressor, oxygen compressor, and nitrogen compresso r) plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additional electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial process);

(4) For a IGCC electric utility generating unit that coproduces chemicals constructed, reconstructed, or modified after May 3, 2011, the gross useful work pe rformed is the gross electrical or mechanical output from the unit minus electricity used to power the feedwater pumps and any associated gas compressors (air separation unit main compressor, oxygen compre ssor, and nitrogen compressor) that are associated with power production plus 75 percent of the useful thermal output measured relative to ISO conditions that is not used to generate additi onal electrical or mechanical output or to enhance the performance of the unit (i.e., steam delivered to an industrial proce ss). Auxiliary loads that are associated with power production are determined based on the energy in the coproduced chemicals compared to the energy of Comment [CF6]: Remove condition of derived

from coal or petroleum to include natural gas and
gasified materials

Coke

‐ oven gas is not derived for the purpose of
creating useful heat. It would still be considered a

gaseous fuel is burned in an affected facility burning

natural gas.

Comment [CF7]: Amend definition of gross
output to account for primary potential difference

in gross output from otherwise similar facilities

– the feed pumps can be driven by steam or electricity.

IGCC difference in gross efficiency can be accounted

for by measuring auxiliary load of gas compressors.

CHP given 5% credit to account for transmission and

distribution benefits5 the syngas combusted in combustion turbine engine and associated duct burners.

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

Integrated gasification combined cycle electric utility steam generating unit or IGCC electric utility steam generating unit means an electric utility combined cycle gas turbine that is designed to burn fuels containing 50 percent (by heat input) or more solid- derived fuel not meeting the definition of natural

gas. The Administrator may waive the 50 percent solid-derived fuel requirement during periods of the gasification system construction, startup and commissioning, shutdown, or repair. No solid fuel is directly burned in the unit during operation

.

Interconnec ted means that two or more electric generating units are electrically tied together by a network of power transmission lines, and other power transmission equipment.

ISO conditions means a temperature of 288 Kelvin, a relative humidity of 60 percent, and a pressure of 101.3 kilopascals.

Lignite means coal that is classified as lignite A or B according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17).

Natural gas means:

(1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of wh ich the principal constituent is methane; or

(2) Liquid petroleum gas, as defined by the American Society of Testing and Materials in ASTM D1835 (incorpora ted by reference, see §60.17); or

(3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value

between 34 and 43 m egajoules (MJ) per dry standard cubic meter ( 910 and 1, 150 Btu per dry standard

cubic foot ).

Natural gas means a fluid mixture of hydrocarbons (e.g., methane, ethane, or propane), composed of at least 70 percent methane by volume or that has a gr oss calorific value between 35 and 41 megajoules (MJ) per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic foot), that maintains a gaseous state under ISO conditions. In addition, natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Finally, natural gas doe s not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating

value.

Neighboring company means any one of those electric utility companies with one or more electric power interconnections to the principal company and wh ich have geographically adjoining service areas.

Net-electric output means the gross electric sales to the utility power distribution system minus purchased power on a calendar year basis.

Net system capacity means the sum of the net electric generating capability (not necessarily equal to rated capa city) of all electric generating equipment owned by an electric utility company (including steam generating units, internal co mbustion engines, gas turbines, nu clear units, hydroelectric units, and all other electric generating e quipment) plus firm contrac tual 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 ent itlement to electric output is otherwise established by contractual arrangement. Comment [CF8]: Add in provision to allow initial
operation on natural gas/distillate oil during

construction. Might be economic to run the

combined cycle facility on natural gas during construction/repair of the gasification system.

Switch NSPS applicability could be a permitting

hassle without any environmental benefit.

Comment [CF9]: Make consistent with part 75

definition of natural gas6 Net energy output means the gross energy output minus the parasitic load associated with power production. Parasitic load includes, but is not limited to, the power required to operate the equipment used for fuel delivery systems, air pollution control systems, wastewater treatment systems, ash handling and disposal systems, and other co ntrols (i.e., pumps, fans, compresso rs, motors, instrumentation, and other ancillary equipment required to operate the affected facility).

Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands.

Out-of-control period means any period beginning with the quadrant corresponding to the completion of a daily calibration error, linearity check, or quality assurance audit that indicates that the instrument is not measuring and recording within the applicable performance specifications and ending with the quadrant corresponding to the completion of an additi onal calibration error, linear ity check, or quality assurance audit following corrective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications.

Petroleum for facilities constructed, reconstructed, or modified before May 4, 2011, means crude oil or a fuel derived from crude oil, including, but not limited to, distillate oil, and residual oil. For units constructed, reconstructed, or modified after May 3, 2011, petroleum means crude oil or a fuel derived from crude oil, including, but not limited to, di stillate oil, residual oil, and petroleum coke.

Petroleum Coke also known as petcoke means a carbonization product of high-boiling hydrocarbon fractions obtained in petroleum processing (heavy re sidues). Petroleum coke is typically derived from oil refinery coker units or other cracking processes.

Potential combustion concentration means the theoretical emissions (nanograms per joule (ng/J), lb/MMBtu heat input) that would result from com bustion of a fuel in an uncleaned state without emission control systems ) and: . For sulfur dioxide (SO 2 ) the potential combustion concentration is determined under §60.50Da(c).

(1) For particulate matter (PM) is:

(i) 3,000 ng/J (7.0 lb/MMBtu) heat input for solid fuel; and

(ii) 73 ng/J (0.17 lb/MMBtu) heat input for liquid fuels.

(2) For sulfur dioxide (SO 2 ) is determined under §60.50Da(c).

(3) For nitrogen oxides (NO X ) is:

(i) 290 ng/J (0.67 lb/MMBtu) heat inp ut for gaseous fuels;

(ii) 310 ng/J (0.72 lb/MMBtu) heat input for liquid fuels; and

(iii) 990 ng/J (2.30 lb/MMBtu) heat input for solid fuels.

Potential electrical output capacity means 33 percent of the maximum design heat input capacity of the steam generating unit, divided by 3,413 Btu/KWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr ( e.g. , a steam generating unit with a 100 MW (340 MMBtu/hr) fossil-fuel heat input capacity would have a 289,080 MWh 12 month potential el ectrical 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 i nput and electrical power contribution by the gas turbine.

Principal company means the electric utility company or companies which own the affected facility. Comment [CF10]: Add definition for optional

net output based standard

Comment [CF11]: Add petroleum coke under
petroleum to be consistent with the EGU MACT.

Included under “coal” for industrial boiler NSPS.

Comment [CF12]: Deleted % reduction
requirements so no longer need7 Resource recovery unit means a facility that combusts more than 75 percent non-fossil fuel on a quarterly (calendar) heat input basis.

Responsible of ficial means responsible official as defined in 40 CFR 70.2.

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, synthetic gas, gasified coal, gasified petroleum coke, gasifi ed biomass, and gasified tire derived fuel.

Spare flue gas desulfurization system module means a separate system of SO 2 emission control equipment capable of treating an amount of flue gas equ al to the total amount of flue gas generated by an affected facility when operated at maximum ca pacity divided by the total number of nonspare flue gas desulfurization modules in the system.

Spinning reserve means the sum of the unutilized net generating c apability of all units of the electric utility company that are synchronized to the power distribution system and that are capable of immediately accepting additional lo ad. The electric generating capability of equipment under multiple ownership is prorate d based on ownership unless the proportiona l entitlement to electric output is otherwise established by contractual arrangement.

Steam Steam generating unit for facilities constructed, reconstructed, or modified before May 4, 2011, means any furnace, boiler, or other device used fo r combusting fuel for the purpose of producing steam (including fossil-fuel-fired steam generators associat ed with combined cycle gas turbines; nuclear steam generators are not included). For units constructed, reconstructed, or modified after May 3, 2011, 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 ge nerators associated with combined cycle gas turbines; nuclear steam generators are not included ). ) plus any integrated equipment that provides either useful thermal output to the boiler or electrical output to power auxiliary equipment.

Subbituminous coal means coal that is classified as subbituminous A, B, or C according to the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17).

System emergency reserves means an amount of electric generating capacity equivalent to the rated capacity of the single larg est electric generating un it 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 th e malfunctioning flue gas desulfurization system. Th e electric generating capability of equipment under multiple ownership is prorated based on ownership unless the proportional entitlement to electric output

is otherwise establishe d by contractual arrange ment.

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 com panies. Sales to other electric utility companies ( e.g. , emergency power) not on a firm contractual basis ma y 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.

Wet flue gas desulfurization technology or wet FGD means a SO 2 control SO 2 control system that is located downstream of the steam generating unit a nd removes sulfur oxides from the combustion gases of the steam generating unit by cont acting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition applies to devices where the aqueous liquid material product of this contact is subsequently converted to other forms. Alkaline reagents used in wet FGD technology include, but are not limited to, lime, limestone, and sodium. Comment [CF13]: Modify definition to include
integrated fuel cells or combustion turbines used for

feedwater heating

. Would also include facilities

used for providing heat for CS, etc.8 §60.42Da Standard Standards for particulate matter (PM).

(a) On Except as provided in paragraph (f) of this section, on and after the date on which the initial performance test is completed or required to be co mpleted under §60.8, whichever date comes first,

no an owner or operator subject to the provisions of this subpart of an affected facility shall not cause to be discharged into the atmosphere from any affected facility for which construction, reconstruction, or

modification commenced before or on February 28 March 1 , 2005, any gases that contain PM in excess

of

: 13 ng/J (0.030 lb/MMBtu) heat input.

(1) 13 ng/J (0.03 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fu el;

(2) 1 percent of the potential combustion concentr ation (99 percent reduction) when combusting solid fuel; and

(3) 30 percent of potential combustion concentrati on (70 percent reduction) when combusting liquid

fuel

. (b) On (b) Except as provided in paragraphs (b)(1) and (b)(2) of this section, on and after the date the initial PM performance test is completed or requi red to be completed under §60.8, whichever date comes first, no an owner or operator subject to the provisions of this subpart an affected facility shall not 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. Owners and oper ators

(1) An owner or operator of an affected facility that elect elects to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart are is exempt from the opacity standard specified in this paragraph ( b ) of

this section

. (2) An owner or operator of an affected facility that combusts only natural gas is exempt from the opacity standard specified in paragraph (b) of this section.

(c) Except as provided in paragraph paragraphs (d ) and (f ) of this section, on and after the date on which the initial performance test is completed or require d to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 , but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility any ga ses that contain PM in excess of either:

(1) 18 ng/J (0.14 lb/MWh) gross energy output; or

(2) 6.4 ng/J (0.015 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel.

(d) As an alternative to meeting the requirements of pa ragraph (c) of this section, the owner or operator of an affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, but before May 4, 2011, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is comp leted or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility shall cause to be discharged into the atmosphere from that affected facility for which construction, reconstruction, or modification commenced after February 28, 2005, any gases that contain PM in excess of:

(1) 13 ng/J (0. 03 030 lb/MMBtu) heat input derived from the combustion of solid, liquid, or gaseous fuel,

and

(2) (2) For an affected facility that commenced construction or reconstruction, 0.1 percent of the combustion concentration determined according to the procedure in §60.48Da(o)(5) (99.9 percent Comment [CF14]: Remove since no longer
required as alternative to numerical limit

Comment [CF15]: Exempt owner/operators of

facilities only burning natural gas from the opacity

standard

Comment [CF16]: Fix Typo9 reduction) for an affected facility for which construction or reconstruction commenced after February 28, 2005 when combusting solid, liquid, or gaseous fuel, or

(3) (3) For an affected facility that commenced modification, 0.2 percent of the combustion concentration determined according to the procedure in §60.48Da(o)(5) (99.8 percent reduction) for an affected facility for which modification commenced after February 28, 2 005 when combusting solid, liquid, or gaseous fuel.

(e) Except as provided in paragraph (f) of this section, no owner or operator of an affected facility that commenced construction, reconstruction, or modifica tion commenced after May 3, 2011, shall meet the requirements specified in paragraphs (e)(1) and (2) of this section.

(1) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator shall cause to be discharged into the atmosphere from that affected facility at all times except during periods of startup and shutdown, any gases that contain PM in excess of the applicable emi ssions limit specified in paragraphs (e)(1)(i) or (ii)

of this section.

(i) For an affected facility which commenced constr uction or reconstruction, any gases that contain PM

in excess of either:

(A) 11 ng/J ( 0.090 lb/MWh) gross energy output; or

(B) 12 ng/J (0.097 lb/MWh) net energy output.

(ii) For an affected facility which commenced modifi cation, any gases that contain PM in excess of 13 ng/J (0.015 lb/MMBtu) heat input.

(2) During periods of startup and shutdown, the owne r or operator shall meet the work practice standards specified in Table 3 to subpart UUUUU of Part 63.

(f) An owner or operator of an affected facility that meets the conditions in either paragraphs (f)(1) or (2) of this section is exempt from the PM emissions limits in of this section.

(1) The affected facility combusts only gaseous or liquid fuels (excluding residual oil) with potential

SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less, and that does not use a post-combustion technology to reduce emissions of SO 2 or PM.

(2) The affected facility is operated under a PM commercial demonstration permit issued by the Administrator according to the provisions of §60.47Da.

§60.43Da Standard Standards for sulfur dioxide (SO 2 ).

(a) On and after the date on which the initial performa nce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the pr ovisions of this subpart shall cause to be discharged into the atmosphere fro m any affected facility which combusts solid fuel or solid-derived fuel and for which construction, recons truction, or modification commenced before or on February 28, 2005, except as provided under paragraphs (c), (d), (f) or (h) of this section, any gases that

contain SO 2 in excess of:

(1) 520 ng/J (1.20 lb/MMBtu) heat input and 10 perc ent of the potential combustion concentration (90 percent reduction); or

(2) 30 percent of the potential combustion concentra tion (70 percent reduction), when emissions are less than 260 ng/J (0.60 lb/MMBtu) heat input

. ; Comment [CF17]: Require same startup and

shutdown work practice standards as the EGU

NESHAP

Comment [CF18]: Exempt natural gas & low

sulfur oil boilers from the PM limit.

Comment [CF19]: Commercial demonstration

alternate standards10 (3) 180 ng/J (1.4 lb/MWh) gross energy output; or

(4) 65 ng/J (0.15 lb/MMBtu) heat input.

(b) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the pr ovisions of this subpart 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 paragraphs (e) or (h) of this section) and for which construction, reconstruction, or modification commenced before or on February 28, 2005, any gases that contain SO 2 in excess of:

(1) 340 ng/J (0.80 lb/MMBtu) heat input and 10 perc ent of the potential combustion concentration (90 percent reduction); or

(2) 100 percent of the potential combustion concentr ation (zero percent reduction) when emissions are less than 86 ng/J (0.20 lb/MMBtu) heat input.

(c) On and after the date on which the initial performa nce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere fro m any affected facility which combusts solid solvent refined coal (SRC

– I) any gases that contain SO 2 in excess of 520 ng/J (1.20 lb/MMBtu) heat input a nd 15 percent of the potential combustion concentrati on (85 percent reduction) except as provided under paragraph (f) of this section; compliance wi th the emission limitation is determined on a 30

- day rolling average basis and compliance with the percent r eduction requirement is determined on a 24

- hour basis.

(c) [RESERVED]

(d) Sulfur dioxide emissions are limited to 520 ng/ J (1.20 lb/MMBtu) heat input from any affected facility which:

(1) Combusts 100 percent anthracite;

(2) Is classified as a resource recovery unit; 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/MMBtu) heat input from any affectedfacility which is located in a noncontinental area and combusts liquid or gaseous fuels (excluding solidderived fuels).

(f) The emission reduction requirements SO 2 standards under this section do not apply to any an owner or operator of an affected facility that is operated under an SO 2 commercial SO 2 commercial demonstration permit issued by the Administrator in ac cordance with the provisions of §60.47Da.

(g) Compliance with the emission lim itation and percent reduction re quirements under this section are both determined on a 30-day rolling average basis except as provided under paragraph (c) of this

section.

(h) When different fuels are combusted simultaneous ly, the applicable standard is determined by proration using the following formula:

(1) If emissions of SO 2 to the atmosphere are greater than 260 ng/J (0.60 lb/MMBtu) heat input Comment [CF20]: Add option for owner/operators of facilities presently covered by

Da to comply with standard for “new” modified

sources. Might co

‐ fire with biomass and 70%

reduction on a small amount of fossil fuel could be

difficult.

Comment [CF21]: Deleting/reserving since

never used11 (2) If emissions of SO 2 to the atmosphere are equal to or less than 260 ng/J (0.60 lb/MMBtu) heat input:

Where:

E
s = Prorated SO 2 emission limit (ng/J heat input);

%P

s = Percentage of potential SO 2 emission allowed;

x = Percentage of total heat input derived from th e combustion of liquid or gaseous fuels (excluding solid-derived fuels); and

y = Percentage of total heat input derived from the combustion of solid fuel (including solid-derived fuels).

(i) Except as provided in paragraphs (j) and (k) of th is section, on and after the date on which the initial performance test is completed or required to be co mpleted under §60.8, whichever date comes first, no owner or operator of an affected facility that co mmenced construction, reconstruction, or modification commenced after February 28, 2005 , but before May 4, 2011, shall cause to be discharged into the atmosphere from that affected facility, any gases that contain SO 2 in excess of the applicable emission limitation specified in paragraphs (i)(1) through (3) of this section.

(1) For an affected facility for which commenced construction commenced after February 28, 2005 , any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ; or

(ii) 5 percent of the potential combustion concentration (95 percent reduction ) on a 30

- day rolling average basis. ).

(2) For an affected facility for which commenced reconstruction commenced after February 28, 2005

, any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30

- day rolling average basis ; or

(iii) 5 percent of the potential combustion concentration (95 percent reduction ) on a 30

- day rolling average basis. ).

(3) For an affected facility for which commenced modification commenced after February 28, 2005 , any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling avera ge basis ;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30

- day rolling average basis ; or

(iii) 10 percent of the potential combustion concentration (90 percent reduction ) on a 30

- day rolling average basis. ).

(j) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced for

which construction, reconstruction, or modification co mmenced after February 28, 2005, and that burns 75 percent or more (by heat input) coal refuse on a 12-month rolling average basis, shall caused cause to Comment [CF22]: Simplify wording by including

date only once. Don’t need “30

‐ day rolling average
basis” since stated elsewhere.12 be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the applicable emission limitation specified in para graphs (j)(1) through (3) of this section.

(1) For an affected facility for which commenced construction commenced after February 28, 2005 , any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day r olling average basis ; or

(ii) 6 percent of the potential combustion concentration (94 percent reduction ) on a 30

- day rolling average basis. ).

(2) For an affected facility for which commenced reconstruction commenced after February 28, 2005

, any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30

- day rolling average basis ; or

(iii) 6 percent of the potential combustion concentration (94 percent reduction ) on a 30

- day rolling average basis. ).

(3) For an affected facility for which commenced modification commenced after February 28, 2005 , any gases that contain SO 2 in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ;

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30

- day rolling average basis ; or

(iii) 10 percent of the potential combustion concentration (90 percent reduction ) on a 30

- day rolling average basis. ).

(k) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility located in a

noncontinental area that commenced for which construction, reconstruction, or modification commenced after February 28, 2005 , but before May 4, 2011 , shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the applicable emission limitation specified in paragraphs (k)(1) and (2) of this section.

(1) For an affected facility that burns solid or solid-d erived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input.

(2) For an affected facility that burns other than so lid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 230 ng/J (0.54 lb/MMBtu) heat input.

(l) Except as provided in paragraphs (j) and (m) of this section, on and after the date on which the initial performance test is completed or required to be co mpleted under §60.8, whichever date comes first, no owner or operator of an affected facility for wh ich construction, reconstruction, or modification commenced after May 3, 2011, shall cause to be disc harged into the atmosphere from that affected facility, any gases that contain SO 2 in excess of the applicable emis sions limit specifie d in paragraphs (l)(1) and (2) of this section.

(1) For an affected facility which commenced construction or reconstruction, any gases that contain SO 2 in excess of either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output; or13 (ii) 140 ng/J (1.2 lb/MWh) net energy output; or

(iii) 3 percent of the potential combustion concentration (97 percent reduction).

(2) For an affected facility which commenced modification, any gases that contain SO 2 in excess of

either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output; or

(ii) 10 percent of the potential combustion concentration (90 percent reduction).

(m) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility located in a noncontinental area for which construction, reconstr uction, or modification commenced after May 3, 2011, shall cause to be discharged into the atmosphere from that affected facility any gases that contain

SO 2 in excess of the applicable emissions limit specifie d in paragraphs (n)(1) and (2) of this section.

(1) For an affected facility that burns solid or solid-d erived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input on a 30

- day roll ing average basis

. (2) For an affected facility that burns other than so lid or solid-derived fuel, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain SO 2 in excess of if the affected facility or 230 ng/J (0.54 lb/MMBtu) heat input on a 30

- day rolling average basis

. §60.44Da Standard Standards for nitrogen oxides (NO X ).

(a) On Except as provided in paragr aph (h) of this section, on and after the date on which the initial performance test is completed or required to be co mpleted under §60.8, whichever date comes first, no owner or operator subject to the provisions of th is subpart shall cause to be discharged into the atmosphere from any affected facility , except as provided under paragraphs (b), (d), (e), and (f) o f this section, for which construction, rec onstruction, or modification commenced before July 10, 1997 any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit in paragraphs (a)(1) and (2) of this section.

(1) The owner or operator shall not cause to be disc harged into the atmosphere any gases that contain

NO X in excess of the emissions limit listed in the following emission limits, based table as applicable to the fuel type combusted and as determined on a 30-day rolling average basis , except as provided under §60.48Da(j)(1):

(1) NO X emission limits.

Fuel type Emission

limit for heat input

ng/J lb/M

MBtu

Gaseous fuels:

Coal-derived fuels 210 0.5014 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 (1) (1)

Any fuel containing more than 25%, by wei ght, lignite if the lignite is mined in

N orth Dakota, Sou t h Dakota, or Montana, and is combusted in a slag tap furnace 2 340 0.80

Any fuel containing more than 25%, by we ight, lignite not subject to the 340 ng/J heat input emission limit 2 260 0.60

Subbituminous coal 210 0.50

Bituminous coal 260 0.60

Anthracite coal 260 0.60

All other fuels 260 0.60

1 Exempt from NO X standards and NO X monitoring requirements.

2 Any fuel containing less than 25%, by weight, lignite is not prorated but its percentage is added to the percentage of the predominant fuel.

( 2 ) NO X reduc tion requirement

.

Fuel type Percent reduction of potential combustion

concentration

Gaseous fuels 25

Liquid fuels 30

Solid fuels 65

(b) The emission limitations under paragraph (a) of this section do not apply to any affected facility

which is combust ing coal

- derived liquid fuel and is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of §60.47Da. Comment [CF23]: No longer need % reduction

in addition to numerical requirement.15 (c) Except as provided under paragraphs (d ), (e), and (f) of this section, when (2) When two or more fuels are combusted simultaneously, the applicable standard is determined by proration using the following formula:

Where:

E

n = Applicable standard for NO X when multiple fuels are combusted simultaneously (ng/J heat input);

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

x = Percentage of total heat input derived from the co mbustion of fuels subject to the 130 ng/J heat input standard;

y = Percentage of total heat input derived from the co mbustion of fuels subject to the 210 ng/J heat input standard;

z = Percentage of total heat input derived from the combustion of fuels subject to the 260 ng/J heat input standard; and

v = Percentage of total heat input delivered from th e combustion of fuels subject to the 340 ng/J heat input standard.

(b) [Reserved]

(c) [Reserved]

(d)(1) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of a n affected facility that commenced construction after July 9, 1997, but before or on February 28, 2005 shall cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of 200 ng/J (1.6 lb/MWh) gross energy output, bas ed on a 30

- day rolling average basis, except as provided under §60.48Da(k).

(2) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of affected f acility for which reconstruction commenced after July 9, 1997, but before or on February 28, 2005 shall cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of 65 ng/J (0.15 lb/MMBtu) heat input, based on a 30

- d ay rolling average basis.

(d) Except as provided in paragraph (h) of this s ection, on and after the date on which the initial performance test is completed or required to be co mpleted under §60.8, whichever date comes first, no owner or operator of an affected facility that co mmenced construction, reconstruction, or modification after July 9, 1997, but before March 1, 2005, shall cause to be discharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit specified in paragraphs (d)(1) and (2) of th is section as determined on a 30-day rolling average

basis.

(1) For an affected facility which commence d construction, any gases that contain NO X in excess of 200 ng/J (1.6 lb/MWh) gross energy output.16 (2) For an affected facility which commence d reconstruction, any gases that contain NO X in excess of 65 ng/J (0.15 lb/MMBtu) heat input.

(e) Except for an IGCC electric utility steam ge nerating unit meeting the requirements of as provided in paragraph s (f) and (h) of this section, on and after February 28, 2005, the owner date on which the initial performance test is completed or operator required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after February 28, 2005 but before May 4, 2011, shall not cause to be discharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) in excess of 130 ng/J ( the applicable emissions limit specified in paragraphs (e)( 1 .0 lb/MWh) gross energy output ) through (3) of this section as determined on a 30-day rolling average basis, except as provided under §60.48Da(k).

( 2 1 ) For an affected facility fo r which reconstruction commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere construction, any gases that contain

NO X (expressed as NO 2 ) in excess of 130 ng/J (1.0 lb/MWh) gross energy output.

(2) For an affected facility which commence d reconstruction, any gases that contain NO X in excess of

either:

(i) 130 ng/J (1.0 lb/MWh) gross energy output on a 30

- day rolling average basis ; or

(ii) 47 ng/J (0.11 lb/MMBtu) heat input on a 30

- day rolling average basi s

. (3) For an affected facility for which commenced modification commenced after February 28, 2005, the owner or operator shall not cause to be discharged into the atmosphere

, any gases that contain

NO X (expressed as NO 2 ) in excess of either:

(i) 180 ng/J (1.4 lb/MWh) gross energy output on a 30

- day rolling average basis ; or

(ii) 65 ng/J (0.15 lb/MMBtu) heat input on a 30

- day rolling average basis

. (f) On and after the date on which the initial perform ance test is completed or required to be completed under §60.8, whichever date comes first, the owner or operator of an IGCC electric utility steam generating unit subject to the provisions of this subp art and for which construction, reconstruction, or modification commenced after February 28, 2005 but before May 4, 2011 , shall meet the requirements specified in paragraphs (f)(1) through (3) of this section.

(1) Except as provided for in paragraphs (f)(2) and (3 ) of this section, the owner or operator shall not cause to be discharged into the at mosphere any gases that contain NO X (expressed as NO 2 ) in excess of 130 ng/J (1.0 lb/MWh) gross energy output on a 30

- day rolling average basis

. (2) When burning liquid fuel exclusively or in comb ination with solid-derived fuel such that the liquid fuel contributes 50 percent or more of the total heat input to the combined cycle combustion turbine, the owner or operator shall not cause to be discharged into the atmo sphere any gases that contain NO X (expressed as NO 2 ) in excess of 190 ng/J (1.5 lb/MWh) gross energy output on a 30

- day rolling average

basis

. (3) In cases when during a 30-day rolling average compliance period liquid fuel is burned in such a manner to meet the conditions in paragraph (f)(2) of this section for only a portion of the clock hours in the 30-day compliance period, the owner or operator shall not cause to be discharged into the atmosphere any gases that contain NO X (expressed as NO 2 ) in excess of the computed weighted-average emissions limit based on the proportion of gross energy output (in MWh) generated during the compliance period for each of emissions limits in paragraphs (f)(1) and (2) of this section.17 (g) Except as provided in paragraph (h) of this sec tion and 60.45Da, on and after the date on which the initial performance test is comple ted or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be di scharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) in excess of the applicable emissions limit specified in paragraphs (g)(1) through (3) of this section

(1) For an affected facility which commenced construction or reconstruction, any gases that contain

NO X in excess of either:

(i) 88 ng/J (0.70 lb/MWh) gross energy output; or

(ii) 95 ng/J (0.76 lb/MWh) net energy output.

(2) For an affected facility which commenced constr uction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-mont h rolling average basis, any gases that contain NO X in

excess of either:

(i) 110 ng/J (0.85 lb/MWh) gross energy output; or

(ii) 120 ng/J (0.92 lb/MWh) net energy output.

(3) For an affected facility which commenced modification, any gases that contain NO X in excess of 140 ng/J (1.1 lb/MWh) gross energy output.

(h) The NO X emissions limits under this section do not appl y to an owner or operator of an affected facility which is operating under a commercial demonstration permit issued by the Administrator in accordance with the provisions of §60.47Da.

§ 60.45Da Standard for mercury ( Hg ).

(a) For each coal

- fired electric utility steam generating unit other than an IGCC electric utility steam generating unit

, o n and after the date on which the i nitial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator subject to the provisions of this subpart shall cause to be discharged into the atmosphere from any affected facility for which

c onstruction, modification, or reconstruction commen ced after January 30, 2004, any gases that contain mercury (Hg) emissions in excess of each Hg emissi ons limit in paragraphs (a)(1) through (5) of this

section that applies to you. The Hg emission s limits in paragraphs ( a )(1) through ( 5 ) of this section are based on a 12

- month rolling average basis using the procedures in §60.50Da(h).

(1) For each coal

- fired electric utility steam generating unit that burns only bituminous coal, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of 20

× 10 − 6 pound per megawatt hour ( lb/MWh) or 0.020 lb/gigawatt

- hour (GWh) on an output basis. The International System of Units (SI) equivalent is 0.0025 ng/J.

( 2) For each c oal

- fired electric utility steam generating unit that burns only subbituminous coal:

(i) If your unit is located in a county

- level geographical area receiving greater than 25 inches per year (in/yr) mean annual precipitation, based on the most recent publi cly available U.S. Department of Agriculture 30

- year data, you must not discharge into the atmosphere any gases from a new affected

source that contain Hg in excess of 66 × 10 − 6 lb/MWh or 0.066 lb/GWh on an output basis. The SI equivalent is 0.0083 ng/J.

(ii) If your unit is located in a county

- level geographical area receiving less than or equal to 25 in/yr mean annual precipitation, based on the most recent publicly available U.S. Department of Agriculture Comment [CF24]: Delete vacated CAMR
provision18 30

- year data, you must not discharge into the atmos phere any gases from a new affected source that contain Hg in excess of 97 × 10 − 6 lb/MWh or 0.097 lb/GWh on an output basis. The SI equivalent is 0.0122 ng/J.

(3) For each c oal

- fired electric utility steam generating un it that burns only lignite, you must not discharge into the atmosphere any gases from a new af fected source that contain Hg in excess of 175 ×

10 − 6 lb/MWh or 0.175 lb/GWh on an output basis. The SI equivalent i s 0.0221 ng/J.

(4) For each coal

- burning electric utility steam generating unit that burns only coal refuse, you must not discharge into the atmosphere any gases from a new af fected source that contain Hg in excess of 16 ×

10 − 6 lb/MWh or 0.016 lb/GWh on an output basis. The SI equivalent is 0.0020 ng/J.

(5) For each coal

- fired electric utility steam generating unit th at burns a blend of coals from different coal ranks ( i.e. , bituminous coal, subbituminous coal, lignite ) or a blend of coal and coal refuse, you must not discharge into the atmosphere any gases fro m a new affected source that contain Hg in excess

of the unit

- specific Hg emissions limit estab lished according to paragraph (a)(5)(i) or (ii) of this section, as applicable to the affected unit.

(i) If you operate a coal

- fired electric utility steam generating unit that burns a blend of coals from

different coal ranks or a blend of coal and coal re fuse, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emissions limit based on the Btu, MWh, or MJ) contributed by each coal rank burned during the compliance period and its applicable Hg emissions limit in paragraphs (a )(1) through (4) of this section as determined using

E quation 1 in this section. For each affected source, you must comply with the weighted Hg emissions limit calculated using Equation 1 in this section ba sed on the total Hg emissions from the unit and the total Btu, MWh, or MJ contributed by all fuels burne d during the compliance period.

Where:

EL b = Total allowable Hg in lb/MWh that can be emit ted to the atmosphere from any affected source being averaged according to this paragraph.

EL i = Hg emissions limit for the subcategory i (coal rank) that applies to affected source, lb/MWh;

HH i = For each affected source, the Btu, MWh, or MJ contributed by the corresponding subcategory i (coal rank) burned during the compliance period; and

n = Number of subcategories (coal ranks) being averaged for an affected source.

(ii) If you operate a coal

- fired electric utility steam generating unit that burns a blend of coals from

different coal ranks or a blend of coal and coal refuse together with one or more non

- regulated, supplementary fuels, you must not discharge into the atmosphere any gases from a new affected source that contain Hg in excess of the computed weighted Hg emission limit based on the Btu, MWh, or MJ contributed by each coal rank burned during the complia nce period and its applicable Hg emissions limit in par agraphs (a)(1) through (4) of this section as determined using Equation 1 in this section. For each affected source. You must comply with the weighted Hg emissions limit calculated using Equation 1 in this section based on the total Hg emissions from the u nit contributed by both regulated and19 nonregulated fuels burned during the compliance period and the total Btu, MWh, or MJ contributed by both regulated and nonregulated fuels burned during the compliance period.

§60.45Da Alternative standards for combined nitrogen oxides (NO X ) and carbon monoxide (CO).

(a) The owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011 as alternate to meeting the applicable NO X emissions limits specified in §60.44Da may elect to meet the applicable standards for combined NO X and carbon monoxide CO specified in paragraph (b) of this section.

(b) On and after the date on which the initial performan ce test is completed or required to be completed under §60.8 no owner or operator of an affected facility that commenced construction, reconstruction, or modification after May 3, 2011, shall cause to be di scharged into the atmosphere from that affected facility any gases that contain NO X (expressed as NO 2 ) plus CO in excess of the applicable emissions limit specified in paragraphs (b)(1) through (3) of this section as determined on a 30-day rolling average

basis.

(1) For an affected facility which commenced construction or reconstruction, any gases that contain

NO X plus CO in excess of either:

(i) 140 ng/J (1.1 lb/MWh) gross energy output; or

(ii) 150 ng/J (1.2 lb/MWh) net energy output.

(2) For an affected facility which commenced constr uction or reconstruction and that burns 75 percent or more coal refuse (by heat input) on a 12-mont h rolling average basis, any gases that contain NO X plus

CO in excess of either:

(i) 160 ng/J (1.3 lb/MWh) gross energy output; or

(ii) 170 ng/J (1.4 lb/MWh) net energy output.(3) For an affected facility which commenced modification, any gases that contain NO X plus CO in excess of 190 ng/J (1.5 lb/MWh) gross energy

output.

§60.46Da [Reserved]

§60.47Da Commercial demonstration permit.

(a) An owner or operator of an affected facility proposing to demonstrate an emerging technology may apply to the Administrator for a commercial demons tration permit. The Admi nistrator will issue a commercial demonstration permit in accordance wi th paragraph (e) of this section. Commercial demonstration permits may be issued only by the Admini strator, and this authority will not be delegated.

(b) An owner or operator of an affected facility th at combusts solid solvent refined coal (SRC–I) and who is issued a commercial demonstration perm it by the Administrator is not subject to the SO 2 emission reduction requirements under §60.43Da( c) but must, as a minimum, reduce SO 2 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/MMBtu) heat input on a 30-day rolling average basis.

(c) An owner or operator of a an affected facility that uses fluidized bed combustion electric utility steam

generator (atmospheric or pressurized) and who is issued a commercial demonstration permit by the Administrator is not subject to the SO 2 emission reduction requirements under §60.43Da(a) but must, as a minimum, reduce SO 2 emissions to 15 percent of the potentia l combustion concentration (85 percent Comment [CF25]: New section to cover
combined NOx + CO standard.20 reduction) on a 30-day rolling average basis and to le ss than 520 ng/J (1.20 lb/MMBtu) 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 by the Admini strator is not subject to the applicable NO X emission limitation and percent reduction under §60.44Da(a) but must, as a minimum, reduce emissions to less than 300 ng/J (0.70 lb/MMBtu) heat input on a 30-day rolling average basis.

(e) Commercial demonstration pe rmits 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 (SCR I) SO2 6,000–10,000

Fluidized bed combustion (atmospheric) SO2 400–3,000

Fluidized bed combustion (pressurized) SO2 400–1,200

Coal liquification N OX 750–10,000

Total allowable for all technologies 15,000

(f) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercia l demonstration permit by the Administrator is not subject to the total PM emission reduction requi rements under §60.42Da but must, as a minimum,

reduce PM emissions to less than 6. 4 ng/J (0.015 lb/MMBtu) heat input.

(g) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions controls system who is issued a commercia l demonstration permit by the Administrator is not subject to the SO 2 standards or emission reduction require ments under §60.43Da but must, as a minimum, reduce SO 2 emissions to 5 percent of the potenti al combustion concentration (95 percent reduction) or to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis.

(h) An owner or operator of an affected facility that uses a pressurized fluidized bed or a multi-pollutant emissions control system who is issued a commercia l demonstration permit by the Administrator is not subject to the NO X standards or emission reduction requi rements under §60.44Da but must, as a minimum, either reduce NO X emissions to less than 130 ng/J (1.0 lb/MWh) or the combined NO X plus CO emissions to less than 180 ng/J (1.4 lb/MWh) gross energy output on a 30-day rolling average basis.

(i) Commercial demonstration permits may not ex ceed the following equivalent MW electrical generation capacity for any one technology category listed in the following table.

Technology Pollutant Equivalent Electrical Capacity (MW electrical output) Multi-pollutant Emission Control SO 2 1,000 Multi-pollutant Emission Control NO X 1,000 Comment [CF26]: New commercial

demonstration permit exemptions21 Multi-pollutant Emission Control PM 1,000

Pressurized Fluidized Bed Combustion SO 2 1,000

Pressurized Fluidized Bed Combustion NO X 1,000

Pressurized Fluidized Bed Combustion PM 1,000

§60.48Da Compliance provisions.

( a ) Compliance with t he PM emission limitation under §60.42Da(a )(1) constitutes compliance with the percent reduction requirement s for PM under §60.42Da(a)(2) and ( 3 ).

(b) Compliance with the NO X emission limitation under §60.44Da(a)(1) constitutes compliance with the percent reduction requirements under §60.44Da(a)( 2 ).

( c a ) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, T t he applicable PM emission standards and opacity standards under §60.42Da , SO 2 emission standards under §60.43Da, and the NO X emission standards under §60.44Da

, under § 60. 45Da apply at all times except during periods of startup, shutdown, or malfunction. The sulfur dioxide emission standards under §60.43Da apply at all times except during periods of startup, shutdown, or when both emergency conditions exist and the proce dures under paragraph (d) of this section are implemented. For affected facilities for which constructi on, modification, or reconstruction commenced after May 3, 2011, the applicable SO 2 emission standards under §60.43Da, NO X emission standards under §60.44Da, and NO X plus CO emission standards under §60.45Da apply at all times. The applicable PM emission standards and opacity st andards under §60.42Da apply at all times except during periods of startup and shutdown.

( d ) During emergency conditions in the pr incipal company, an affected facility with a malfunctioning flue gas desulfurization system may be operated if SO 2 emissions are minimized by:

(1) Operating all operable flue gas desulfurization sy stem modules, and bringing back into operation any

malfuncti oned module as soon as repairs are completed,

(2) Bypassing flue gases around only those flue gas desu lfurization system modules that have been taken

out of operation because they were incapable of any SO 2 emission reduction or which would have suffered sig nificant 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 MMBtu/hr) heat input (approximately 125 MW electric al output capacity). The Administrator 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 app ropriate requirements under paragraph under §60.43Da(a), (b), (d), (e), and (h) 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 m aximum 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 Administrator at least 30 days notice of the date and period of

time over which the demonstr ation will be performed.

( e b ) After the initial performance test required under §60.8, compliance with the applicable SO 2 emission standards limitations and percentage reduction requirements under §60.43Da

, and the NO X emission standards limitations under §60.44Da , and NO X plus CO emission standards under §60.45Da Comment [CF27]: Include all periods of
operation.

Removing emergency conditions for existing

facilities.

Comment [CF28]: Amended procedures for
calculating emissions rates divides total emissions by total output over a 30

‐ day period (total emissions/total output & not average of hourly rates). Minimizes periods of startup and shutdown

since less mass of emissions at lower operational

rates.

Comment [CF29]: Do not need % reduction
compliance language anymore

– deleted
requirements.

Comment [CF30]: Removed emergency
conditions and just use malfunctions22 is are based on the average emission rate for 30 succe ssive boiler operating days. A separate performance test is completed at the end of each boiler operati ng day after the initial performance test, and a new 30 day average emission rate for both SO 2 , and NO X , and NO X plus CO as applicable, and a new percent

reduction for SO 2 are calculated to show compliance with the standards.

( c f ) For the initial performance test required under §60.8, compliance with the SO 2 emission limitations and percent reduction requirements under §60.43Da

, and the NO X emission limitation under §60.44Da

, and NO X plus CO emissions limit under §60.45Da is based on the average emission rates for SO 2 , NO X , and percent reduction for SO 2 for the first 30 successive boiler operating days. The initial performance test is the only test in which at least 30 days pr ior notice is required unless otherwise specified by the Administrator. 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.

(d) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable 30-day rolling average SO 2 and NO X emissions limits is determined by calculating the arithmetic average of all hourly emission rates for SO 2 and NO X for the 30 successive boiler operating days, except for data obt ained during startup, shutdown, or malfunction. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-day rolling average SO 2 and NO X emissions limits is determined by dividing the sum of the SO 2 and NO X emissions for the 30 successive boiler operating days divided by the sum of the gross energy output or net energy out put, as applicable, for the 30 successive boiler operating days.

(e) For affected facilities for which construction, modification, or reconstruction commenced before May 4, 2011, compliance with applicable SO 2 percentage reduction requirements is determined based on the average inlet and outlet SO 2 emission rates for the 30 successive boiler operating days. For affected facilities for which construction, modification, or reconstruction commenced after May 3, 2011, compliance with applicable SO 2 percentage reduction requirements is determined based on the “as fired” total potential emissions and the total outlet SO 2 emissions for the 30 successive boiler operating days.

(f) For affected facilities for which construction, m odification, or reconstruction commenced before May 4, 2011, compliance with applicable daily average PM emissions limits is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Daily averages are only calculated for boiler operating days that have non-out-of-control data for at least 18 hours of unit operation during which the standard applies. Instead, all of the non-out-of-cont rol hourly emission rates of the operating day(s) not meeting the minimum 18 hours non-out-of-control data daily average requirement are averaged with all of the non-out-of-control hourly emission rates of the next boiler operating day with 18 hours or more of non-out-of-control PM CEMS data to determine compliance. For affected facilities for which construction, modification, or rec onstruction commenced after May 3, 2011, compliance w ith applicable daily average PM emissions limits is determined by dividing the sum of the PM emissions for the 30 successive boiler operating days by the sum of th e gross useful output or net energy output, as applicable, for the 30 successive boiler operating days.

(g) The owner or operator of an affected facility subject to emission limitations in this subpart shall

determine c ompliance as follows:

(1) Compliance with applicable 30

- day rolling ave rage SO 2 and NO X emission limitations is determined by calculating the arithmetic average of all hourly emission rates for SO 2 and NO X for the 30 successive23 boiler operating days, except for data obtaine d during startup, shutdown, malfunction (NO X only), or

eme rgency conditions (SO 2 only).

(2) Compliance with applicable SO 2 percentage reduction requirements is determined based on the average inlet and outlet SO 2 emission rates for the 30 successive boiler operating days

. (3) Compliance with applicable daily average PM emission limitations is determined by calculating the arithmetic average of all hourly emission rates for PM each boiler operating day, except for data obtained during startup, shutdown, and malfunction. Averages are only calculated for boiler operatin g days that have valid data for at least 18 hours of unit operation during which the standard applies. Instead, all of the valid hourly emission rates of the operating day(s) not meeting the minimum 18 hours

valid data daily average requirement are averag ed with all of the valid hourly emission rates of the next boiler operating day with 18 hours or more of valid PM CEMS data to determine compliance.

(g) For affected facilities for which construction, mo dification, or reconstruction commenced after May 3, 2011, compliance with applicable 30-day rolling average NO X plus CO emissions limit is determined by dividing the sum of the NO X plus CO emissions for the 30 successive boiler operating days by the sum of the gross energy output or net energy output, as applicable, 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 §60.49Da of this subpart, compliance of the affected facility with the emission requirements under §§60.43Da and 60.44Da of this subpart for the day on which the 30-day period ends may be determined by the Administrator by following the applicable proced ures in section 7 of Method 19 of appendix A of this part.

(i) Compliance provisions for source s subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), (e)(3)(i), (f), or ( f)

. g)

. The owner or operator of an affected facility subject to §60.44Da(d)(1), (e)(1), (e)(2)(i), ( e)(3)(i), or (f)

shall calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the pr ovisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provi sions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k )). )) or the average hourly net energy output, as applicable. Alternatively, for oil-fi red and gas-fired units, NO X emissions may be calculated by multiplying the hourly NO X emission rate in lb/MMBtu (measured by the CEMS required under §§60.49Da(c) and (d)), by th e hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross energy output (measured according to the provisions of §60.49Da(k )). )) or the average hourly net energy output, as applicable.

(j) Compliance provisions for duct burners subject to §60.44Da(a)(1) . To determine compliance with

the emissions limits for NO X required by §60.44Da(a) for duct burners used in combined cycle systems, either of the procedures described in paragra ph (j)(1) or (2) of this section may be used:

(1) The owner or operator of an affected duct burner shall conduct the performance test required under §60.8 using the appropriate methods in appendix A of this part. Compliance w ith the emissions limits under §60.44Da(a)(1) is determined on the average of three (nominal 1-hour) runs for the initial and subsequent performance tests. During the performanc e test, one sampling site shall be located in the exhaust of the turbine prior to the duct burner. A second sampling site shall be located at the outlet from the heat recovery steam generating unit. Measuremen ts shall be taken at both sampling sites during the performance test; or

(2) The owner or operator of an affected duct burner may elect to determine compliance by using the CEMS specified under §60.49Da for measuring NO X and oxygen (O 2 ) (or carbon dioxide (CO 2 )) and24 meet the requirements of §60.49Da. Alternatively, data from a NO X emission rate ( i.e. , NO X -diluent) CEMS certified according to the provisions of §75.20( c) of this chapter and appendix A to part 75 of this chapter, and meeting the quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used, with the fo llowing caveats. Data used to meet the requirements of §60.51Da shall not include substitute data values deri ved from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have b een bias adjusted according to the procedures of part 75 of this chapter. The sampling site shall be locat ed at the outlet from the steam generating unit. The

NO X emission rate at the outlet from the steam generating unit shall constitute the NO X emission rate from the duct burner of the combined cycle system.

(k) Compliance provisions for duct burners subject to §60.44Da(d)(1) or (e)(1) . To determine compliance with the emission limitation for NO X required by §60.44Da(d)(1) or (e)(1) for duct burners used in combined cycle systems, either of the proce dures described in paragraphs (k)(1) and (2) of this section may be used:

(1) The owner or operator of an affected duct burner used in combined cycle systems shall determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) as

follows:

(i) The emission rate (E) of NO X shall be computed using Equation 2 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;

C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf);

C te = Average hourly concentration of NO X in the turbine exhaust upstream from duct burner, ng/dscm (lb/dscf);

Q sg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr);

Q te = Average hourly volumetric flow rate of exhaust gas from combustion turbine, dscm/hr (dscf/hr);

O sg = Average hourly gross energy output from steam generating unit, J (MWh /h (MW ); and

h = Average hourly fraction of the total heat input to the steam generating unit derived from the

combustion of fuel in the affected duct burner.

(ii) Method 7E of appendix A of this part shall be used to determine the NO X concentrations (C sg and C te ). Method 2, 2F or 2G of appendix A of this part, as a ppropriate, shall be used to determine the volumetric flow rates (Q sg and Q te ) of the exhaust gases. The volumetric flow rate measurements shall be taken at

the same time as the concentration measurements.

(iii) The owner or operator shall develop, demonstrate, and provide information satisfactory to the Administrator to determine the average hourly gross energy output from the steam generating unit, and the average hourly percentage of the total heat input to the steam generating unit derived from the

combustion of fuel in the affected duct burner.

(iv) Compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) is determined by the three-run average (nominal 1-hour runs) for the initial and subsequent performance tests. Comment [CF31]: Fix typo25 (2) The owner or operator of an affected duct burner used in a combined cycle system may elect to determine compliance with the applicable NO X emission limitation in §60.44Da(d)(1) or (e)(1) on a 30- day rolling average basis as indicated in para graphs (k)(2)(i) through (iv) of this section.

(i) The emission rate (E) of NO X shall be computed using Equation 3 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;

C sg = Average hourly concentration of NO X exiting the steam generating unit, ng/dscm (lb/dscf);

Q sg = Average hourly volumetric flow rate of exhaust gas from steam generating unit, dscm/hr (dscf/hr);

and

O

cc = Average hourly gross energy output from entire combined cycle unit, J (MWh /h (MW ).

(ii) The CEMS specified under §60.49Da for measuring NO X and O 2 (or CO 2 ) shall be used to determine the average hourly NO X concentrations (C sg ). The continuous flow monitoring system specified in §60.49Da(l) or §60.49Da(m) shall be used to determine the volume tric flow rate (Q sg ) of the exhaust gas. If the option to use the flow monitoring system in §60.49Da(m) is selected, the flow rate data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this ch apter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chap ter. The sampling site shall be located at the outlet from the steam generating unit.

(iii) The continuous monitoring system specified under §60.49Da(k) for measuring and determining gross energy output shall be used to determine the average hourly gross energy output from the entire combined cycle unit (O

cc ), which is the combined output from the combustion turbine and the steam generating unit.

(iv) The owner or operator may, in lieu of installi ng, operating, and recording data from the continuous flow monitoring system specified in §60.49Da(l), determine the mass rate (lb/hr) of NO X emissions by installing, operating, and maintaining continuous fuel flowmeters following the appropriate measurements procedures specified in appendix D of part 75 of this chapter. If this compliance option is selected, the emission rate (E) of NO X shall be computed using Equation 4 in this section:

Where:

E = Emission rate of NO X from the duct burner, ng/J (lb/MWh) gross energy output;

ER sg = Average hourly emission rate of NO X exiting the steam generating unit heat input calculated using appropriate F factor as described in Method 19 of appendix A of this part, ng/J (lb/MMBtu);

H
cc = Average hourly heat input rate of entire combined cycle unit, J/hr (MMBtu/hr); and

O

cc = Average hourly gross energy output from entire combined cycle unit, J (MWh /h (MW ). Comment [CF32]: Fix typo26 (3) When an affected duct burner steam generating unit utilizes a common steam turbine with one or more affected duct burner steam generating units, the owner or operator shall either:

(i) Determine compliance with the applicable NO X emissions limits by measuring the emissions combined with the emissions from the other unit(s) utilizing the common steam turbine; or

(ii) Develop, demonstrate, and provide informati on satisfactory to the Administrator on methods for apportioning the combined gross energy output from the steam turbine for each of the affected duct burners. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions regulated under this part.

(l) Compliance provisions for s ources subject to §60.45Da. The owner or operator of an affected facility subject to §60.45Da (new sources constructed or rec onstructed after January 30, 2004) shall calculate the Hg emiss ion rate (lb/MWh) for each calendar month of the year, using hourly Hg concentrations measured according to the provisions of §60.49Da(p) in conjunction with hourly stack gas volumetric flow rates measured according to the provisions of §60.49Da(l) or (m), and hourly gross electrical outputs, determined according to the provisions in §60.49Da(k). Compliance with the applicable standard under §60.45Da is determined on a 12

- month rolling average basis

. (l) [Reserved]

(m) Compliance provisions for sources subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i),

or (j)(3)(i ). ), (l)(1)(i), (l)(1)(ii), or (l)(2). The owner or operator of an affected facility subject to §60.43Da(i)(1)(i), (i)(2)(i), (i)(3)(i), (j)(1)(i), (j)(2)(i), or (j)(3)(i) shall calculate SO 2 emissions SO 2 emissions as 1.660 × 10 –7 lb/scf-ppm times the average hourly SO 2 output SO 2 output concentration in ppm (measured according to the provisions of §60. 49Da(b)), times the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured accordi ng to the provisions of §60.49Da(k )). )) or the average hourly net energy output, as applicable. Alternatively, for oil-fired and gas-fired units, SO 2 emissions may be calculated by multiplying the hourly SO 2 emission rate (in lb/MMBtu), measured by the CEMS required under §60.49Da, by the hourly heat input rate (measured according to the provisions of §60.49Da(n)), and dividing the result by the average gross ener gy output (measured according to the provisions of §60.49Da(k )). )) or the average hourly net energy output, as applicable.

(n) Compliance provisions for sources subject to §60.42Da(c)(1) or (e) . The owner or operator of an affected facility subjec t to §60.42Da(c)(1) shall calculate PM emissions by multiplying the average hourly PM output concentration (measured according to the provisions of §60.49Da(t)), by the average hourly flow rate (measured according to the provisions of §60.49Da(l) or §60.49Da(m)), and

divided dividing by the average hourly gros s energy output (measured according to the provisions of §60.49Da(k )). Compliance with )) or the emission limit is determined by calculating the arithmetic

average of the hourly emission rates computed f or each boiler operating day. net energy output, as applicable.

(o) Compliance provisions for sources subject to §60.42Da(c)(2) or (d) . Except as provided for in paragraph (p) of this section, th e owner or operator of an affected facility for which construction, reconstruction, or modification commenced after Febr uary 28, 2005, shall dem onstrate compliance with each applicable emission limit according to the requi rements in paragraphs (o)(1) through (o)(5) of this

section.

(1) You must conduct a performance test to demons trate initial compliance wi th the applicable PM emissions limit in §60.42Da(c)(2) or (d) by the applicable date specified in §60.8(a). Thereafter, you Comment [CF33]: Delete since CAMR vacated27 must conduct each subsequent performance test with in 12 calendar months following the date the previous performance test was required to be c onducted. You must conduct each performance test according to the requirements in §60.8 using the te st methods and procedures in §60.50Da. The owner or operator of an affected facility that has not operated for 60 consecutive calendar days prior to the date that the subsequent performance test would have been required had the unit been operating is not required to perform the subsequent performance te st until 30 calendar days after the next boiler operating day. Requests for additional 30 day extensions shall be granted by the relevant air division or office director of the appropriate Regional Office of the U.S. EPA.

(2) You must monitor the performance of each electrostatic precipitator or fabric filter (baghouse) operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using a continuous opacity monitoring system (COMS) according to the requirements in paragraphs (o)(2)(i) through (vi) unless you elect to comply with one of the alternatives provided in paragraphs (o)(3) and (o)(4) of this section, as applicable to your control device.

(i) Each COMS must meet Performance Specif ication 1 in 40 CFR part 60, appendix B.

(ii) You must comply with the quality assurance requi rements in paragraphs (o)(2)(ii)(A) through (E) of

this section.

(A) You must automatically (intrinsic to the opacity monitor) check the zero and upscale (span) calibration drifts at least once daily. For a particul ar COMS, the acceptable range of zero and upscale calibration materials is as defined in the applicab le version of Performance Specification 1 in 40 CFR part 60, appendix B.

(B) You must adjust the zero and span whenever the 24-hour zero drift or 24-hour span drift exceeds 4 percent opacity. The COMS must allow for the amount of excess zero and span drift measured at the 24- hour interval checks to be recorded and quantified. The optical surfaces exposed to the effluent gases must be cleaned prior to performing the zero and sp an drift adjustments, except for systems using automatic zero adjustments. For systems using automatic zero adjustments, the optical surfaces must be cleaned when the cumulative automatic zero compensation exceeds 4 percent opacity.

(C) You must apply a method for producing a simulate d zero opacity condition and an upscale (span) opacity condition using a certified neutral density filter or other related technique to produce a known obscuration of the light beam. All procedures applie d must provide a system check of the analyzer internal optical surfaces and all electronic circu itry including the lamp and photodetector assembly.

(D) Except during periods of system breakdowns, re pairs, calibration checks, and zero and span adjustments, the COMS must be in continuous opera tion and must complete a minimum of one cycle of sampling and analyzing for each successive 10 second pe riod and one cycle of data recording for each successive 6-minute period.

(E) You must reduce all data from the COMS to 6- minute averages. Six-minute opacity averages must be calculated from 36 or more data points equally spaced over each 6-minute period. Data recorded during periods of system breakdowns, repairs, calibr ation checks, and zero and span adjustments must not be included in the data averages. An arithmetic or integrated average of all data may be used.

(iii) During each performance test conducted according to paragraph (o)(1) of this section, you must establish an opacity baseline level. The value of the opacity baseline level is determined by averaging all of the 6-minute average opacity values (reported to the nearest 0.1 percent opacity) from the COMS measurements recorded during each of the test run in tervals conducted for the performance test, and then28 adding 2.5 percent opacity to your calculated average opacity value for all of the test runs. If your opacity baseline level is less than 5.0 percent, then the opacity baseline level is set at 5.0 percent.

(iv) You must evaluate the preceding 24-hour average opacity level measured by the COMS each boiler operating day excluding periods of affected facility startup, shutdown, or malfunction. If the measured 24-hour average opacity emission level is greater than the baseline opacity level determined in paragraph (o)(2)(iii) of this section, you must initiate inves tigation of the relevant equipment and control systems within 24 hours of the first discovery of the high opacity incident and take the appropriate corrective action as soon as practicable to adjust c ontrol settings or repair equipment to reduce the measured 24-hour average opacity to a level below the baseline opacity level. In cases when a wet

scrubber is used in combination with another PM c ontrol device that serves as the primary PM control device, the wet scrubber must be maintained and operated.

(v) You must record the opacity measurements, ca lculations performed, and any corrective actions

taken. The record of corrective action taken must in clude the date and time during which the measured 24-hour average opacity was greater than baseline opacity level, and the date, time, and description of

the corrective action.

(vi) If the measured 24-hour average opacity for your a ffected facility remains at a level greater than the opacity baseline leve l after 7 boiler operating days, then you must conduct a new PM performance test according to paragraph (o)(1) of this section and establish a new opacity baseline value according to paragraph (o)(2) of this section. This new performan ce test must be conducted w ithin 60 days of the date that the measured 24-hour average opacity was firs t determined to exceed the baseline opacity level unless a waiver is granted by the permitting authority.

(3) As an alternative to complying with the requirements of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of an electrostatic precipitator (ESP) operated to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) using an ESP predictive model developed in accordance with the requirements in pa ragraphs (o)(3)(i) through (v) of this section.

(i) You must calibrate the ESP predictive model with each PM control device used to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) operating under normal conditions. In cases

when a wet scrubber is used in combination with an ESP to comply with the PM emissions limit, the wet scrubber must be maintained and operated.

(ii) You must develop a site-specific monitoring plan that includes a description of the ESP predictive model used, the model input parameters, and the pr ocedures and criteria for establishing monitoring parameter baseline levels indicative of compliance with the PM emissions limit. You must submit the site-specific monitoring plan for approval by the permitting authority. For reference purposes in preparing the monitoring plan, see the OAQPS “Com pliance Assurance Monitoring (CAM) Protocol for an Electrostatic Precipitator (ESP) Controlling Par ticulate Matter (PM) Emissions from a Coal-Fired

Boiler.” This document is available from the U.S. E nvironmental Protection Agency (U.S. EPA); Office of Air Quality Planning and Standards; Sector Po licies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Network (TTN) under Emis sion Measurement Center Continuous Emission Monitoring.

(iii) You must run the ESP predictive model using the applicable input data each boiler operating day and evaluate the model output for the preceding bo iler operating day excludi ng periods of affected facility startup, shutdown, or malfunction. If the values for one or more of the model parameters exceed the applicable baseline levels de termined according to your approved site-specific monitoring plan, you29 must initiate investigation of the relevant equipm ent and control systems within 24 hours of the first discovery of a model parameter deviation and, ta ke the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to return the model output to within the applicable baseline levels.

(iv) You must record the ESP predictive model input s and outputs and any corrective actions taken. The

record of corrective action taken must include the date and time during which the model output values exceeded the applicable baseline levels, and the date, time, and description of the corrective action.

(v) If after 7 consecutive days a model parameter conti nues to exceed the applicable baseline level, then you must conduct a new PM performance test according to paragraph (o)(1) of this section. This new performance test must be conducted within 60 calenda r days of the date that the model parameter was first determined to exceed its baseline level unless a waiver is granted by the permitting authority.

(4) As an alternative to complying with the requirement s of paragraph (o)(2) of this section, an owner or operator may elect to monitor the performance of a fa bric filter (baghouse) opera ted to comply with the applicable PM emissions limit in §60.42Da(c)(2) or (d) by using a bag leak detection system according to the requirements in paragraphs (o )(4)(i) through (v) of this section.

(i) Each bag leak detection system must meet th e specifications and requirements in paragraphs (o)(4)(i)(A) through (H) of this section.

(A) The bag leak detection system must be certified by the manufacturer to be capable of detecting PM emissions at concentrations of 1 milligram per actua l cubic meter (0.00044 grains per actual cubic foot)

or less.

(B) The bag leak detection system sensor must pr ovide output of relative PM loadings. The owner or operator must continuously record the output from th e bag leak detection system using electronic or other means ( e.g. , using a strip chart recorder or a data logger.)

(C) The bag leak detection system must be equipped with an alarm system that will react when the system detects an increase in relative particulate loading over the alarm set point established according to paragraph (o)(4)(i)(D) of this section, and the alar m must be located such that it can be noticed by the appropriate plant personnel.

(D) In the initial adjustment of the bag leak detection system, you must establish, at a minimum, the baseline output by adjusti ng the sensitivity (range) and the averagi ng period of the device, the alarm set points, and the alarm delay time.

(E) Following initial adjustment, you must not adjust the averaging period, alarm set point, or alarm delay time without approval from the permitting author ity except as provided in paragraph (d)(1)(vi) of

this section.

(F) Once per quarter, you may adjust the sensitivity of the bag leak detection system to account for seasonal effects, including temperature and humidity, ac cording to the procedures identified in the sitespecific monitoring plan required by paragraph (o)(4)(ii) of this section.

(G) You must install the bag leak detection sensor downstream of the fabric filter and upstream of any

wet scrubber.

(H) Where multiple detectors are required, the system's instrumentation and alarm may be shared among

detectors.

(ii) You must develop and submit to the permitting au thority for approval a site-specific monitoring plan for each bag leak detection system. You must opera te and maintain the bag leak detection system30 according to the site-specific monitoring plan at all ti mes. Each monitoring plan must describe the items in paragraphs (o)(4)(ii)(A) through (F) of this section.

(A) Installation of the bag leak detection system;

(B) Initial and periodic adjustment of the bag leak detection system, including how the alarm set-point will be established;

(C) Operation of the bag leak detection sy stem, including quality assurance procedures;

(D) How the bag leak detection system will be maintained, including a routine maintenance schedule and spare parts inventory list;

(E) How the bag leak detection system output will be recorded and stored; and

(F) Corrective action procedures as specified in para graph (o)(4)(iii) of this section. In approving the site-specific monitoring plan, the permitting author ity may allow owners and operators more than 3 hours to alleviate a specific condition that causes an alarm if the owner or operator identifies in the monitoring plan this specific condition as one that coul d lead to an alarm, adequately explains why it is

not feasible to alleviate this condition within 3 hours of the time the alarm occurs, and demonstrates that the requested time will ensure alleviation of this condition as expeditiously as practicable.

(iii) For each bag leak detection system, you must in itiate procedures to determine the cause of every alarm within 1 hour of the alarm. Except as provided in paragraph (o)(4)(ii)(F) of this section, you must

alleviate the cause of the alarm within 3 hours of the alarm by taking whatever corrective action(s) are necessary. Corrective actions may include, but are not limited to the following:

(A) Inspecting the fabric filter for air leaks, torn or broken bags or filter media, or any other condition that may cause an increase in particulate emissions;

(B) Sealing off defective bags or filter media;

(C) Replacing defective bags or filter media or otherwise repairing the control device;

(D) Sealing off a defective fabric filter compartment;

(E) Cleaning the bag leak detection system probe or otherwise repairing the ba g leak detection system;

or

(F) Shutting down the process producing the particulate emissions.

(iv) You must maintain records of the information specified in paragraphs (o)(4)(iv)(A) through (C) of this section for each bag leak detection system.

(A) Records of the bag leak detection system output;

(B) Records of bag leak detection system adjustment s, including the date and time of the adjustment, the initial bag leak detection system settings, and the final bag leak detection system settings; and

(C) The date and time of all bag leak detection system alarms, the time that procedures to determine the cause of the alarm were initiated, if procedures were initiated within 1 hour of the alarm, the cause of the alarm, an explanation of the actions taken, the date and time the cause of the alarm was alleviated, and if

the alarm was alleviated within 3 hours of the alarm.

(v) If after any period composed of 30 boiler oper ating days during which the alarm rate exceeds 5 percent of the process operating time (excluding c ontrol device or process startup, shutdown, and malfunction), then you must conduct a new PM performance test according to paragraph (o)(1) of this31 section. This new performance test must be conducted within 60 calendar days of the date that the alarm rate was first determined to exceed 5 percent limit unless a waiver is granted by the permitting authority.

(5) An owner or operator of a modified affected facility electing to meet the emission limitations in §60.42Da(d) shall determine the percent reduction in PM by using the emission rate for PM determined by the performance test conducted according to the requi rements in paragraph (o)(1) of this section and

the ash content on a mass basis of the fuel burned du ring each performance test run as determined by analysis of the fuel as fired.

(p) As an alternative to meeting the compliance provisions specified in paragraph (o) of this section, an owner or operator may elect to install, evaluate, maintain, and operate a CEMS measuring PM emissions discharged from the affected facility to the atmosphere and record the output of the system as specified in paragraphs (p)(1) through (p)(8) of this section.

(1) The owner or operator shall submit a written notification to the Administrator of intent to demonstrate compliance with this subpart by using a CEMS measuring PM. This notification shall be sent at least 30 calendar days before the initial startup of the monitor for compliance determination purposes. The owner or operator may discontinue ope ration of the monitor and instead return to demonstration of compliance with this subpart according to the requi rements in paragraph (o) of this section by submitting written notification to the Administrator of such intent at least 30 calendar days before shutdown of the monitor for compliance determination purposes.

(2) Each CEMS shall be installed, evaluated, operated, and maintained according to the requirements in §60.49Da(v).

(3) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of the date of notification to the Administrator required under paragraph (p)(1) of this section, whichever is

later.

(4) Compliance with the applicable emissions lim it shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emissions concentrations using the continuous monitoring system outlet data. The 24-hour block arit hmetic average emission concentration shall be calculated using EPA Reference Method 19 of appendix A of this part, section 4.1.

(5) At a minimum, valid non-out-of-control CEMS hourly averages shall be obtained for 75 percent of all operating hours on a 30-day rolling average basis. Beginning on January 1, 2012, val id non-out-ofcontrol CEMS hourly averages shall be obtained for 90 percent of all operating hours on a 30-day rolling average basis.

(i) At least two data points per hour shall be us ed to calculate each 1-hour arithmetic average.

(ii) [Reserved]

(6) The 1-hour arithmetic averages required shall be expressed in ng/J, MMBtu/hr, or lb/MWh and shall be used to calculate the boiler operating day daily arithmetic average emission concentrations. The 1- hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of subpart A of this part.

(7) All valid non-out-of-control CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (j)(5) of this section are not met.

(8) When PM emissions data are not obtained be cause of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emission s data shall be obtained by using other monitoring Comment [CF34]: Consistent with Part 75
monitoring32 systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid non-out-of-control emissions data for a minimum of 90 percent (only 75 percent is required prior to January 1, 2012) of all operating hours per 30-day rolling average.

(q) Compliance provisions for s ources subject to §60.42Da(b )

. )

. An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b ) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere accordi ng to the requirements in §60 .49Da(a), as applicable to the affected facility.

(r) Compliance provisions for sources subject to §60.45Da(b) . To determine compliance with the NO X plus CO emissions limit, the owner or operator shall use the procedures specified in paragraphs (r)(1) through (3) of this section.

(1) Calculate NO X emissions as 1.194 × 10 − 7 lb/scf-ppm times the average hourly NO X output concentration in ppm (measured according to the pr ovisions of §60.49Da(c)), times the average hourly flow rate (measured in scfh, according to the provi sions of §60.49Da(l) or §60.49Da(m)), divided by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable. (2) Calculate CO emissions by multiplying the average hourly CO output concentration (measured according to the provisions of §60.49Da(u), by the average hourly flow rate (measured according to the provisi ons of §60.49Da(l) or §60.49Da(m)), and dividing by the average hourly gross energy output (measured according to the provisions of §60.49Da(k)) or the average hourly net energy output, as applicable.

(3) Calculate NO X plus CO emissions by summing the NO X emissions results from paragraph (r)(1) of this section plus the NO X emissions results from paragraph (r)(2) of this section.

(s) Affirmative defense for exceedance of emissions limit during malfunction . In response to an action to enforce the standards set forth in paragraph §§60. 42Da, 60.43Da, 60.44Da and 60.45Da, you may assert an affirmative defense to a claim for civil penalties fo r exceedances of such standards that are caused by malfunction, as defined at 40 CFR 60.2. Appropriate penalties may be assessed, however, if you fail to meet your burden of proving all of the requirements in the affirmative defense as specified in paragraphs (s)(1) and (2) of this section. The affirm ative defense shall not be available for claims for injunctive relief.

(1) To establish the affirmative defense in any action to enforce such a limit, you must timely meet the notification requirements in paragraph (s)(2) of th is section, and must prove by a preponderance of

evidence that:

(i) The excess emissions:

(A) Were caused by a sudden, infrequent, and unavoidable failure of air pollution control and monitoring equipment, process equipment, or a process to operate in a normal or usual manner: and

(B) Could not have been prevented through careful planning, proper design, or better operation and maintenance practices; and

(C) Did not stem from any activity or event that could have been foreseen and avoided, or planned for;

and

(D) Were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and

(ii) Repairs were made as expeditiously as possible when the applicable emissi on limitations were being exceeded. Off-shift and overtime labor were used, to the extent practicable to make these repairs; and33 (iii) The frequency, amount, and duration of th e excess emissions (including any bypass) were minimized to the maximum extent practica ble during periods of such emissions; and

(iv) If the excess emissions resulted from a bypass of control equipment or a process, then the bypass was unavoidable to prevent loss of life, pers onal injury, or severe property damage; and

(v) All possible steps were taken to minimize the imp act of the excess emissions on ambient air quality, the environment, and human health; and

(vi) All emissions monitoring and c ontrol systems were kept in operati on if at all possible, consistent with safety and good air pollution control practices; and

(vii) All of the actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs; and

(viii) At all times, the facility was operated in a manner consistent with good practices for minimizing emissions; and

(ix) A written root cause analysis has been prepared , the purpose of which is to determine, correct, and eliminate the primary causes of the malfunction and the excess emissions resulting from the malfunction event at issue. The analysis shall also specify, us ing best monitoring methods and engineering judgment,

the amount of excess emissions that were the result of the malfunction.

(2) Notification . The owner or operator of the affected source experiencing an exceedance of its emission limit(s) during a malfunction shall notify the Administrator by telephone or facsimile (FAX) transmission as soon as possible, but no later than two business days after the initial occurrence of the malfunction or, if it is not possible to determine within two business days whether the malfunction caused or contributed to an exceedance, no later than two business days after the owner or operator knew or should have known that the malfunction caused or contributed to an exceedance, but, in no

event later than two business days after the end of the averaging period, if it wishes to avail itself of an affirmative defense to civil penalties for that malfunc tion. The owner or operator seeking to assert an affirmative defense shall also submit a written report to the Administrator within 45 days of the initial

occurrence of the exceedance of the standard in §63.9991 to demonstrate, with all necessary supporting documentation, that it has met the requirements set fort h in paragraph (s)(1) of this section. The owner or operator may seek an extension of this deadline for up to 30 additional days by submitting a written request to the Administrator before the expiration of the 45 day period. Until a request for an extension has been approved by the Administrato r, the owner or operator is subj ect to the requirement to submit such report within 45 days of the initial occurrence of the exceedance.

(a) An owner or operator of an affected facility subject to the opacity standard in §60.42Da(b) shall monitor the opacity of emissions discharged from the affected facility to the atmosphere according to the applicable requirements in paragraphs (a)(1) through (3) of this section.

(1) Except as provided for in paragraph paragraphs (a)(2 ), and (4 ) of this section, the owner or operator of an affected facility

, subject to an opacity standard in §60.42a(b) shall install, calibrate, maintain, and operate a COMS, and record the output of the system, for measuring the opacity of emissions discharged to the atmosphere. If opacity interference due to water droplets exists in the stack (for example, from the use of an FGD system), the opacity is monitored ups tream 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 SO 2 control system), alternate paramete rs indicative of the PM control system's performance and/or good combustion are monitored (subject to the approval of the Administrator). Comment [CF35]: Clarify COMS not required for

facilities not subject to an opacity standard34 (2) As an alternative to the monitoring requirements in paragraph (a)(1) of this section, an owner or operator of an affected facility that meets th e conditions in either paragraph (a)(2)(i), (ii), (iii), or ( iii iv ) of this section may elect to monitor opacity as specified in paragraph (a)(3) of this section.

(i) The affected facility uses a fabric filter (bagho use) to meet the standards in §60.42Da and a bag leak detection system is installed and operated according to the requirements in paragraphs §60.48Da(o)(4)(i) through (v);

(ii) The affected facility burns only gaseous or li quid fuels (excluding residual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or le ss, and does not use a post-combustion technology to

reduce emissions of SO 2 or PM; or

(iii) The affected facility meets all of the conditions specified in paragraphs (a)(2)(iii)(A) through (C) of

this section

. .; or

(A) No post-combustion technology (except a wet scrubber) is used for reducing PM, SO 2 , or carbon monoxide ( CO ) emissions;

(B) Only natural gas, gaseous fuels, or fuel oils th at contain less than or equal to 0.30 weight percent sulfur are burned; and

(C) Emissions of CO discharged to the atmosphere are maintained at levels less than or equal to 1.4 lb/MWh on a boiler operating day average basis as demonstrated by the use of a CEMS measuring CO emissions according to the procedures speci fied in paragraph (u) of this section.

(iv) The affected facility uses an ESP and uses an ESP predictive model to monitor the performance of the ESP developed in accordance and operated accord ing to the most current requirements in section §60.48Da of this part.

(3) The owner or operators operator of an affected facility that meets the conditions in paragraph (a)(2) of this section may, as an alternative to using a COMS, elect to monitor vi sible emissions using the applicable procedures specified in paragraphs (a)(3)(i) through (iv) of this section. The opacity performance test requirement in paragraph (a)(3)(i ) must be conducted by April 29, 2011, within 45 days after stopping use of an existing COMS, or wi thin 180 days after initial startup of the facility,

whichever is later. The permitting authority may exempt owners or operators of affected facilities burning only natural gas from the opacity monitoring requirements

. (i) The owner or operator shall conduct a performance te st using Method 9 of appendix A–4 of this part and the procedures in §60.11. If during the initia l 60 minutes of the observation all the 6-minute averages are less than 10 percent and all the individua l 15-second observations are less than or equal to 20 percent, then the observation period may be reduced from 3 hours to 60 minutes.

(ii) Except as provided in paragraph (a)(3)(iii) or (iv) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part pe rformance tests using the procedures in paragraph (a)(3)(i) of this section according to the applic able schedule in paragraphs (a)(3)(ii)(A) through (a)(3)(ii)( D C ) of this section, as determined by the most recent Method 9 of appendix A–4 of this part performance test results.

(A) If no visible emissions are obs erved, If the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed

within 12 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opaci ty standard is combusted, whichever is later ; Comment [CF36]: Add ESP model to COMS
exemption options

Comment [CF37]: No longer need since
proposing to exempt natural gas

‐ fired EGUs from

the opacity standard.

Comment [CF38]: Allow flexibility to account

for intermittent use of fuels with an opacity

standard.35 (B) If visible emissions are observed but the maximum 6

- minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A

– 4 of this part performance test must be completed

within 6 calendar months from the date that the most recent performance test was conducted;

(C (B ) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within

3 calendar months from the date that the mo st recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later ; or

( D C ) If the maximum 6-minute average opacity is grea ter than 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted.

(iii) If the maximum 6-minute opacity is less th an 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in paragraphs (a)(3)(iii)(A) a nd (B) of this section.

(A) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 of appendix A–7 of this part and demonstrate that th e sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period ( i.e. , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period) the owner or operator shall either document and adjust the operation of the facility and demonstrate within

24 hours that the sum of the occurrence of visible emis sions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (a)(3)(i) of this section within 45 calendar days according to the requirements in §60.50Da(b)(3).

(B) If no visible emissions are observed for 30 10 operating days during which an opacity standard is applicable, observations can be reduced to once ever y 7 operating days during which an opacity standard is applicable. If any visible emissions are obs erved, daily observations shall be resumed.

(iv) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance test s, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the

Administrator. The observations shal l be similar, but not necessarily identical, to the requirements in paragraph (a)(3)(iii) of this section. For refere nce purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity from Stationary Source s Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Pl anning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Netw ork (TTN) under Emission Measurement Center Preliminary Methods.36 (4) An owner or operator of an affected facility that is subject to an opacity standard under §60.42a(b) is not required to operate a COMS provided that the affected facility meets the conditions in either paragraph (4)(i) or (4)(ii) of this section.

(i) The affected facility burns only gaseous fuels a nd/or liquid fuels (excluding residue oil) with a potential SO 2 emissions rate no greater than 26 ng/J (0. 060 lb/MMBtu), and the unit operates according to a written site-specific monitoring plan approved by the permitting authority. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affectedfacility indicative of compliance with the opacity standard. For testing performed as part of this sitespecific monitoring plan, the permitting authority may require as an alternative to the notification and reporting requirements specified in §§60.8 and 60.11 th at the owner or operator submit any deviations with the excess emissions report required under §60.51a(d).

(ii) The owner or operator of the affected facili ty installs, calibrates, operates, and maintains a particulate matter continuous parametric monitori ng system (PM CPMS) according to the requirements specified in subpart UUUUU of part 63.

(b) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring SO 2 emissions SO 2 emissions , except where natural

gas is and/or liquid fuels (excluding re sidual oil) with potential SO 2 emissions rates of 26 ng/J (0.060 lb/MMBtu) or less are the only fuel fuels combusted, as follows:

(1) Sulfur dioxide emissions are monito red at both the inlet and outlet of the SO 2 control SO 2 control

device.

(2) For a facility that qualifies under the numerical limit provisions of §60.43Da (d), (i), (j), or (k)

SO 2 emissions SO 2 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 of appendix A of this part may be used to determine potential SO 2 emissions in place of a

continuous SO 2 emission monitor at the inlet to the SO 2 control device as required under paragraph (b)(1)

of this section.

(4) If the owner or operator ha s installed and certified a SO 2 CEMS according to the requirements of §75.20(c)(1) of this chapter and appendix A to part 75 of this chapter, and is continuing to meet the ongoing quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used to meet the requirements of this section, provided that:

(i) A CO 2 or O 2 continuous monitoring system is installed, calibrated, maintained and operated at the same location, according to para graph (d) of this section; and

(ii) For sources subject to an SO 2 emission limit in lb/MMBtu under §60.43Da:

(A) When relative accuracy testing is conducted, SO 2 concentration data and CO 2 (or O 2 ) data are collected simultaneously; and

(B) In addition to meeting the applicable SO 2 and CO 2 (or O 2 ) relative accuracy specifications in Figure 2 of appendix B to part 75 of this chapter, the rela tive accuracy (RA) standard in section 13.2 of Performance Specification 2 in appendix B to this part is met when the RA is calculated on a lb/MMBtu basis; and

(iii) The reporting requirements of §60.51Da are met. The SO 2 and, if required, CO 2 (or O 2 ) data reported to meet the requirements of §60.51Da shall not include substitute data values derived from the missing Comment [CF39]: Add flexibility for permitting authority to approve site specific opacity monitoring plan

Comment [CF40]: Allow PM CPMS for NESHAP

PM monitoring to qualify for COMS exemption

Comment [CF41]: Add exemption for low sulfur

oil form the SO2 CEMS requirement. Do we need to

add a fuel sampling/receipts requirement

Comment [CF42]: Since adding additional

numerical limits it is simpler to just refer the entire

section.37 data procedures in subpart D of part 75 of this chapter, nor shall the SO 2 data have been bias adjusted according to the procedures of part 75 of this chapter.

(c)(1) The owner or operator of an affected facility shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring NO X emissions discharged to the atmosphere;

or

(2) If the owner or operator has installed a NO X emission rate CEMS to meet the requirements of part 75 of this chapter and is continuing to meet the ongoing requirements of part 75 of this chapter, that CEMS may be used to meet the requirements of this secti on, except that the owner or operator shall also meet the requirements of §60.51Da. Data reported to meet the requirements of §60.51Da shall not include data substituted using the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.

(d) The owner or operator of an affected facility not complying with an output based limit shall install, calibrate, maintain, and operate a CEMS, and record the output of the system, for measuring the O 2 or carbon dioxide (CO 2 ) content of the flue gases at each location where SO 2 or NO X emissions are monitored. For affected facilities subject to a lb/MMBtu SO 2 emission limit under §60.43Da, if the owner or operator has installed and certified a CO 2 or O 2 monitoring system according to §75.20(c) of this chapter and appendix A to part 75 of this chap ter and the monitoring system continues to meet the applicable quality-assurance provisions of §75.21 of this chapter and appendix B to part 75 of this chapter, that CEMS may be used together with the part 75 SO 2 concentration monitoring system described in paragraph (b) of th is section, to determine the SO 2 emission rate in lb/MMBtu. SO 2 data used to meet the requirements of §60.51Da shall not include substitute data values derived from the missing data procedures in subpart D of part 75 of this ch apter, nor shall the data have been bias adjusted according to the procedures of part 75 of this chapter.

(e) The CEMS under paragraphs (b), (c), and (d) of th is section are operated and data recorded during all periods of operation of the affected facili ty including periods of startup, shutdown, and malfunction or emergency conditions , and , except for CEMS breakdowns, repairs, calibration checks, and zero and span adjustments.

(f)(1) For units that began construction, reconstruc tion, or modification on or before February 28, 2005, the owner or operator shall obtain emission data for at least 18 hours in at least 22 out of 30 successive boiler operating days. If this minimum data requi rement cannot be met with CEMS, the owner or operator shall supplement emission data with othe r monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section.

(2) For units that began construction, reconstruction, or modification after February 28, 2005, the owner or operator shall obtain emission data for at least 90 percent of all operating hours for each 30 successive boiler operating days. If this minimum data require ment cannot be met with a CEMS, the owner or operator shall supplement emission data with othe r monitoring systems approved by the Administrator or the reference methods and procedures as described in paragraph (h) of this section.

(g) The 1-hour averages required under paragraph §60.13(h) are expressed in ng/J (lb/MMBtu) heat input and used to calculate the average emissi on rates under §60.48Da. The 1-hour averages are calculated using the data points required under §60.13(h)(2).

(h) When it becomes necessary to supplement CEMS data to meet the minimum data requirements in paragraph (f) of this section, the owner or operato r shall use the reference me thods and procedures as specified in this paragraph. Acceptable alternative methods and procedures are given in paragraph (j) of

this section.38 (1) Method 6 of appendix A of this part shall be used to determine the SO 2 concentration at the same

location as the SO 2 monitor. Samples shall be taken at 60-m inute intervals. The sampling time and sample volume for each sample shall be at least 20 minutes and 0.020 dscm (0.71 dscf). Each sample represents a 1-hour average.

(2) Method 7 of appendix A of this part shall be used to determine the NO X concentration at the same

location as the NO X monitor. Samples shall be taken at 30-minut e intervals. The arithmetic average of two consecutive samples represents a 1-hour average.

(3) The emission rate correction factor, integrated ba g sampling and analysis procedure of Method 3B of appendix A of this part shall be used to determine the O 2 or CO 2 concentration at the same location as the

O 2 or CO 2 monitor. Samples shall be taken for at least 30 minutes in each hour. Each sample represents a 1-hour average.

(4) The procedures in Method 19 of appendix A of this part shall be used to compute each 1-hour average concentration in ng/J (lb/MMBtu) heat input.

(i) The owner or operator shall use methods and pro cedures in this paragraph to conduct monitoring system performance evaluations under §60.13(c) a nd calibration checks under §60.13(d). Acceptable alternative methods and procedures are gi ven in paragraph (j) of this section.

(1) Methods 3B, 6, and 7 of appendix A of this part shall be used to determine O 2 , SO 2 , and

NO X concentrations, respectively.

(2) SO 2 or NO X (NO), as applicable, shall be used for preparing the calibration gas mixtures (in N 2 , as applicable) under Performance Specifica tion 2 of appendix B of this part.

(3) For affected facilities burning only fossil fuel, the span value for a COMS is between 60 and 80 percent. Span values for a CEMS measuring NO X shall be determined using one of the following procedures:

(i) Except as provided under paragraph (i)(3)(ii) of this section, NO X span values shall be determined as

follows:

Fossil fuel Span values for NO X (ppm)

Gas 500.

Liquid 500.

Solid 1,000.

Combination 500 (x + y) + 1,000z.

Where:

x = Fraction of total heat input derived from gaseous fossil fuel,

y = Fraction of total heat input derived from liquid fossil fuel, and

z = Fraction of total heat input derived from solid fossil fuel.39 (ii) As an alternative to meeting the requirements of paragraph (i)(3)(i) of this section, the owner or operator of an affected facility may elect to use the NO X span values determined according to section 2.1.2 in appendix A to part 75 of this chapter.

(4) All span values computed under paragraph (i)(3)(i) of this section for burning combinations of fossil fuels are rounded to the nearest 500 ppm. Span valu es computed under paragraph (i)(3)(ii) of this section shall be rounded off according to section 2. 1.2 in appendix A to part 75 of this chapter.

(5) For affected facilities burning fossil fuel, alone or in combination with non-fossil fuel and determining span values under paragraph (i)(3)(i) of this section, the span value of the SO 2 CEMS at the

inlet to the SO 2 control device is 125 percent of the maximum estimated hourly potential emissions of the fuel fired, and the outlet of the SO 2 control device is 50 percent of maximum estimated hourly potential

emissions of the fuel fired. For affected facilities determining span values under paragraph (i)(3)(ii) of this section, SO 2 span values shall be determined according to section 2.1.1 in appendix A to part 75 of this chapter.

(j) The owner or operator may use the following as alte rnatives to the reference methods and procedures specified in this section:

(1) For Method 6 of appendix A of this part, Method 6A or 6B (whenever Methods 6 and 3 or 3B of appendix A of this part data are used) or 6C of appe ndix A of this part may be used. Each Method 6B of appendix A of this part sample obtained over 24 hours represents 24 1-hour averages. If Method 6A or 6B of appendix A of this part is used under pa ragraph (i) of this section, the conditions under §60.48Da(d)(1) apply; these conditions do not apply under paragraph (h) of this section.

(2) For Method 7 of appendix A of this part, Method 7A, 7C, 7D, or 7E of appendix A of this part may be used. If Method 7C, 7D, or 7E of appendix A of this part is used, the sampling time for each run shall

be 1 hour.

(3) For Method 3 of appendix A of this part, Method 3A or 3B of appendix A of this part may be used if the sampling time is 1 hour.

(4) For Method 3B of appendix A of this part, Met hod 3A of appendix A of this part may be used.

(k) The procedures specified in paragraphs (k)(1) thr ough (3) of this section shall be used to determine

gross energy output for sources demonstrating compliance with the an output-based standard under §§60.42Da(c), 60.43Da(i), 60.43Da(j), 60.44Da(d)(1), and 6 0.44Da( e ).

. (1) The owner or operator of an affected facility with electricity generation shall install, calibrate, maintain, and operate a wattmeter; measure gross el ectrical output in MWh on a continuous basis; and record the output of the monitor.

(2) The owner or operator of an affected facility wi th process steam generation shall install, calibrate, maintain, and operate meters for steam flow, temper ature, and pressure; measure gross process steam output in joules per hour (or Btu per hour) on a conti nuous basis; and record the output of the monitor.

(3) For affected facilities generating process steam in combination with electrical generation, the gross energy output is determined from the gross electrical output measured in accordance with paragraph (k)(1) of this section plus 75 percent of the gross thermal output (measured relative to ISO conditions) of the process steam measured in accordance with paragraph (k)(2) of this section. according to the definition of “gross energy output” specified in §60.41Da that is applicable to the affected facility..

(l) The owner or operator of an affected facili ty demonstrating compliance with an output-based

standard under §60.42Da, §60.43Da, §60.44Da, or §60. 45Da shall install, certify, operate, and maintain Comment [CF43]: Simplify since adding new paragraphs

Comment [CF44]: Simplify40 a continuous flow monitoring system meeting the requirements of Performance Specification 6 of appendix B of this part and the calibration drift ( CD ) assessment, relative accuracy test audit ( RATA ), and reporting provisions of procedure 1 of appendix F of this part, and record the output of the system, for measuring the volumetric flow rate of exhaust gases discharged to the atmosphere; or

(m) Alternatively, data from a continuous flow monitoring system certified according to the requirements of §75.20(c) of this chapter and appendix A to part 75 of this chapter, and continuing to meet the applicable quality control and quality assurance requirements of §75.21 of this chapter and appendix B to part 75 of this chapter, may be used. Flow rate data reported to meet the requirements of §60.51Da shall not include substitute data values deri ved from the missing data procedures in subpart D of part 75 of this chapter, nor shall the data have b een bias adjusted according to the procedures of part 75 of this chapter.

(n) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in 40 CFR 72.2, may use, as an alternative to the requirements specified in either paragraph (l) or (m) of this section, a fu el flow monitoring syst em certified and operated according to the requirements of appendix D of part 75 of this chapter.

(o) The owner or operator of a duct burner, as described in §60.41Da, which is subject to the

NO X standards of §60.44Da(a)(1), (d)(1), or (e)(1) is not required to install or operate a CEMS to

measure NO X emissions; a wattmeter to measure gross electrical output; meters to measure steam flow, temperature, and pressure; and a continuous flow mo nitoring system to measure the flow of exhaust gases discharged to the atmosphere.

(p) The owner or operator of an affected facility demonstrating compliance with an Hg limit in §60.45Da shall install and operate a CE MS to measure and record the concentration of Hg in the exhaust gases from each stac k according to the requirements in paragraphs (p)(1) through (p)(3) of this section. Alternatively, for an affected facility that is also subject to the requirements of subpart I of part 75 of this chapter, the owner or operator may install, certify, maint ain, operate and quality

- assure the data from a Hg CEMS according to §75.10 of this chapter and appendices A and B to part 75 of this chapter, in lieu of following the procedures in paragraphs (p)(1) through (p)(3) of this section

. (1) The owner or operat or must install, operate, and maintain each CEMS accordi ng to Performance Specification 12A in appendix B to this part.

(2) The owner or operator must conduct a performance evaluation of each CEMS according to the requirements of §60.13 and Performance Spe cification 12A in appendix B to this part.

(3) The owner or operator must operate each CEMS according to the requirements in paragraphs (p)(3)(i) through (iv) of this section.

(i) As specified in §60.13(e)(2), each CEMS must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15

- minute period.

(ii) The owner or operator must reduce CEMS data as specified in §60.13(h).

(iii) The owner or operator shall use all valid data points collected during the hour to calculate the hourly average Hg concentration.

(iv) The owner or operator must record the results of each required certification and quality assurance

test of the CEMS.

(4) Mercury CEMS data collection must conform to paragraphs (p)(4)(i) through (iv) o f this section. Comment [CF45]: Delete since CAMR vacated41 (i) For each calendar month in which the affected unit operates, valid hourly Hg concentration data, stack gas volumetric flow rate data, moisture data (if required), and elect rical output data (i.e., valid data for all of these parameters) shall be obtained for at least 75 percent of the unit operating hours in the

month.

(ii) Data reported to meet the requirements of th is subpart shall not include hours of unit startup, shutdown, or malfunction. In addition, for an affected facility that i s also subject to subpart I of part 75 of this chapter, data reported to meet the requireme nts of this subpart shall not include data substituted using the missing data procedures in subpart D of part 75 of this chap ter, nor shall the data have been

bias a djusted according to the procedures of part 75 of this chapter.

(iii) If valid data are obtained for less than 75 percent of the unit operating hours in a month, you must

discard the data collected in that month a nd replace the data with the mean of the in dividual monthly

emission rate values determined in the last 12 months. In the 12

- month rolling average calculation, this substitute Hg emission rate shall be weighted according to the number of unit operating hours in the month for which the data capture requirement of §60.49Da(p)(4)(i) was not met.

(iv) Notwithstanding the requirements of paragraph (p)( 4)(iii) of this section, if valid data are obtained for less than 75 percent of the unit operating hours in another month in that same 12

- month rolling

ave rage cycle, discard the data collected in that m onth and replace the data with the highest individual monthly emission rate determined in the last 12 months. In the 12

- month rolling average calculation, this substitute Hg emission rate shall be weighted ac cording to the number of unit operating hours in the month for which the data capture requ irement of §60.49Da(p)(4)(i) was not met.

(q) As an alternative to the CEMS required in paragr aph (p) of this section, the owner or operator may use a sorbent trap mo nitoring system (as defined in §72.2 of this chapter) to monitor Hg concentration, according to the procedures described in §75.15 of this chapter and appendix K to part 75 of this chapter.

(r) For Hg CEMS that measure Hg concentration on a dry basis or fo r sorbent trap monitoring systems, the emissions data must be corrected for the stack ga s moisture content. A certified continuous moisture monitoring system that meets the requirements of §75. 11(b) of this chapter is acceptable for this purpose. Alternati vely, the appropriate default moisture value, as specified in §75.11(b) or §75.12(b) of this chapter, may be used.

(p) [Reserved]

(s) The owner or operator shall prepare and submit to the Administrator for approval a unit-specific monitoring plan for each monitoring system, at leas t 45 days before commencing certification testing of the monitoring systems. The owner or operator sha ll comply with the requirements in your plan. The plan must address the requirements in para graphs (s)(1) through (6) of this section.

(1) Installation of the CEMS sampling probe or other interface at a measurement location relative to each affected process unit such that the measurem ent is representative of the exhaust emissions ( e.g. , on or downstream of the last control device);

(2) Performance and equipment specifications for the sample interface, the pollutant concentration or parametric signal analyzer, and the da ta collection and reduction systems;

(3) Performance evaluation procedures and acceptance criteria ( e.g., calibrations, relative accuracy test audits (RATA), etc.);

(4) Ongoing operation and maintenance procedures in accordance with the general requirements of §60.13(d) or part 75 of this chapter (as applicable);42 (5) Ongoing data quality assurance procedures in ac cordance with the general requirements of §60.13 or part 75 of this chapter (as applicable); and

(6) Ongoing recordkeeping and reporting procedures in accordance with the requirements of this subpart.

(t) The owner or operator of an affected facility demonstrating compliance with the output-based emissions limitation under §60.42Da (c)(1) shall shall install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or operator of an affected facility demonstrating co mpliance with the input-based emission limitation in §60.42Da may install, certify, operate, and maintain a CEMS for measuring PM emissions according to the requirements of paragraph (v) of this section. An owner or op erator of an affected facility demonstrating compliance with the input

- based emission limitation in §60.42Da(a)(1) or §60.42Da(c)(2) may install, certify, operate, and maintain a CE MS for measuring PM emissions according to the requirements of paragraph (v ) of this section.

(u) The owner or operator of an affected facility using a CEMS measuring CO emissions to meet requirements of this subpart shall meet the requireme nts specified in paragra phs (u)(1) through (4) of

this section.

(1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (u)(1)(i) through (iv) of this section.

(i) The CO CEMS must be installed, certified, main tained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part.

(ii) Each 1-hour CO emissions average is calculate d using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis).

(iii) At a minimum, valid non-out-of-control 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling av erage basis. The 1-hour av erages are calculated using the data points required in §60.13(h)(2).

(iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part.

(2) You must calculate the 1-hour average CO emissions levels for each boiler operating day by multiplying the average hourly CO output concentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate a nd divided by the corresponding average hourly useful energy output from the affected facility. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each boiler operating day.

(3) You must evaluate the preceding 24-hour av erage CO emission level each boiler operating day excluding periods of affected facility startup, s hutdown, or malfunction. If the 24-hour average CO emission level is greater than 1.4 lb/MWh, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective action as soon as practicable to adjust control settings or repair equipment to reduce the 24-hour average CO emission level to 1.4 lb/MWh or less.

(4) You must record the CO measurements and calcul ations performed according to paragraph (u)(3) of this section and any corrective actions taken. The reco rd of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 1.4 lb/MWh, and the date, time, and description of the corrective action.43 (v) The owner or operator of an affected facility using a CEMS measuring PM emissions to meet requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (v)(1) through (v)(4) of this section.

(1) The owner or operator shall conduct a performance evaluation of the CEMS according to the applicable requirements of §60.13, Performance Sp ecification 11 in appendix B of this part, and procedure 2 in appendix F of this part.

(2) During each PM correlation testing run of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 (or CO 2 ) data shall be collected concurrently (or within a 30- to 60- minute period) by both the CEMS and performance te sts conducted using the following test methods.

(i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and

(ii) For O 2 (or CO 2 ), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used.

(3) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relativ e Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years.

(4 ) After July 1, 2011, within 9 0 days after t he date of completing each performance evaluation required by paragraph (v) of this section, the owner or operator of the affected facility must either

submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data

bas e available at http://cfpub.epa.gov/oarweb/ index.cfm?action=fire.main or mail a copy to: United States Environmental Protection Agency; Energy St rategies Group; 109 TW Alexander DR; Mail Code:

D243

– 01; RTP, NC 27711

. (4) As of January 1, 2012 and within 90 days afte r the date of completing each performance test, as defined in §60.8, conducted to demonstrate complian ce with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA’s Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/e rt tool.html/) or other compatible electronic spreadsheet. Only data collected using test methods co mpatible with ERT are subject to this requirement to be submitted electronically into EPA’s WebFIRE database.

(w) The owner or operator using a SO 2 , NO X , CO 2 , and O 2 CEMS to meet the requirements of this subpart shall install, certify, operate, and maintain the CEMS as specified in paragraphs (w)(1) through (w)(5) of this section.

(1) Except as provided for under paragraphs (w)(2) , (w)(3), and (w)(4) of this section, each SO 2 , NO X , CO 2 , and O 2 CEMS required under paragraphs (b) through (d) of this section shall be installed, certified, and operated in accordance with the applicable procedures in Performance Specification 2 or 3 in appendix B to this part or according to the procedures in appendices A and B to part 75 of this chapter. Daily calibration drift assessments and quarterly accur acy determinations shall be done in accordance with Procedure 1 in appendix F to this part, and a data assessment report (DAR), prepared according to section 7 of Procedure 1 in appendix F to this part , shall be submitted with each compliance report required under §60.51Da.

(2) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to implement the following alterna tive data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than or equal to 100 ppm, the daily calibration error test and calibration ad justment procedures desc ribed in sections 2.1.1 Comment [CF46]: Updated language for

electronic reporting44 and 2.1.3 of appendix B to part 75 of this chap ter may be followed instead of the CD assessment procedures in Procedure 1, section 4.1 of appendix F of this part. If this option is selected, the data validation and out-of-control provisions in sections 2.1.4 and 2.1.5 of appendix B to part 75 of this chapter shall be followed instead of the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part. For the purposes of data validation under this subpart, the excessive CD and out-of-control criteria in Procedure 1, section 4.3 of appendix F to this part shall apply to SO 2 and

NO X span values less than 100 ppm;

(3) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For all required CO 2 and O 2 CEMS and for SO 2 and NO X CEMS with span values greater than 30 ppm, quarterly linearity checks may be performed in accordance with section 2.2.1 of appendix B to part 75 of this chapter, instead of performing the cylinder gas audits (CGAs) described in Procedure 1, section 5.1.2 of appendix F to this part. If this op tion is selected: The frequency of the linearity checks shall be as specified in section 2.2.1 of appendix B to part 75 of this chapter; the applicable linearity specifications in section 3.2 of appendix A to part 75 of this chapter shall be met; the data validation and out-of-control criteria in section 2.2.3 of appendix B to part 75 of this chapter shall be followed instead of the excessive audit inaccuracy and out-of-control crit eria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2. 2.4 of appendix B to part 75 of this chapter shall apply. For the purposes of data validation under th is subpart, the cylinder gas audits described in Procedure 1, section 5.1.2 of appendix F to this part shall be performed for SO 2 and NO X span values less than or equal to 30 ppm;

(4) As an alternative to meeting the requirements of paragraph (w)(1) of this section, an owner or operator may elect to may elect to implement the following alternative data accuracy assessment procedures. For SO 2 , CO 2 , and O 2 CEMS and for NO X CEMS, RATAs may be performed in accordance with section 2.3 of appendix B to part 75 of this chapter instead of following the procedures described in Procedure 1, section 5.1.1 of appendix F to this part . If this option is selected: The frequency of each RATA shall be as specified in section 2.3.1 of appe ndix B to part 75 of this chapter; the applicable relative accuracy specifications shown in Figure 2 in a ppendix B to part 75 of this chapter shall be met;

the data validation and out-of-control criteria in sec tion 2.3.2 of appendix B to part 75 of this chapter

shall be followed instead of the excessive audit ina ccuracy and out-of-control criteria in Procedure 1, section 5.2 of appendix F to this part; and the grace period provisions in section 2.3.3 of appendix B to part 75 of this chapter shall apply. For the purpos es of data validation under this subpart, the relative accuracy specification in section 13.2 of Performance Sp ecification 2 in appendix B to this part shall be

met on a lb/MMBtu basis for SO 2 (regardless of the SO 2 emission level during the RATA), and for

NO X when the average NO X emission rate measured by the refere nce method during the RATA is less than 0.100 lb/MMBtu;

(5) If the owner or operator elects to implement the alternative data assessment procedures described in paragraphs (w)(2) through (w)(4) of this section, eac h data assessment report shall include a summary of the results of all of the RATAs, linearity checks, CGAs, and calibration error or drift assessments required by paragraphs (w)(2) th rough (w)(4) of this section.

§60.50Da Compliance determination procedures and methods.

(a) In conducting the performance tests required in §60. 8, the owner or operator shall use as reference methods and procedures the methods in appendix A of this part or the methods and procedures as specified in this section, except as provided in §60.8( b). Section 60.8(f) does not apply to this section for

SO 2 and NO X . Acceptable alternative methods are give n in paragraph (e) of this section.45 (b) The owner or operator shall In conducting the performance tests to determine compliance with the PM standards in §60.42Da , the owner or operator shall meet the requirements specified in paragraphs (b)(1) through (3) of this section.

(1) The owner or operator shall measure filterable PM to determine compliance with the applicable PM emissions limit in §60.42Da as follows: specified in paragraphs (b)(1)(i) through (iii) of this section.

( 1 i ) The dry basis F factor (O 2 ) procedures in Method 19 of appendix A of this part shall be used to compute the emission rate of PM.

( 2 ii ) For the particular matter PM concentration, Method 5 of appendix A of this part shall be used at for

an affected facilities without facility that does not use a wet FGD systems and . For an affected facility that uses a wet FGD system, Method 5B of appendix A of this part shall be used after downstream of the

wet FGD systems

. ( i A ) The sampling time and sample volume for each ru n shall be at least 120 minutes and 1.70 dscm (60 dscf). The probe and filter holder heating system in the sampling train may be set to provide an average gas temperature of no greater than 160±14 °C (320±25 °F).

( ii B ) For each particulate run, the emission rate co rrection factor, integrated or grab sampling and analysis procedures of Method 3B of appendix A of this part shall be used to determine the O 2 concentration. The O 2 sample shall be obtained simultaneously w ith, and at the same traverse points as, the particulate run. If the particulate run has more than 12 traverse points, the O 2 traverse points may be reduced to 12 provided that Method 1 of appendix A of this part is used to locate the 12 O 2 traverse points. If the grab sampling procedure is used, the O 2 concentration for the run shall be the arithmetic mean of the sample O 2 concentrations at all traverse points.

(2) In conjunction with a performance test performed according to the requirements in paragraph (b)(1) of this section, the owner or operator of an affect ed facility for which construction, reconstruction, or modification commenced after May 3, 2011, shall measure condensable PM using Method 202 of appendix M of part 51.

(3) Method 9 of appendix A of this part and the proc edures in §60.11 shall be used to determine opacity.

(c) The owner or operator shall determine compliance with the SO 2 standards in §60.43Da as follows:

(1) The percent of potential SO 2 emissions (%Ps) to the atmosphere shall be computed using the following equation:

Where:

%Ps = Percent of potential SO 2 emissions, percent;

%Rf = Percent reduction from fu el pretreatment, percent; and

%Rg = Percent reduction by SO 2 control system, percent.

(2) The procedures in Method 19 of appendix A of this part may be used to determine percent reduction (%R f ) of sulfur by such processes as fuel pretreatme nt (physical coal cleani ng, hydrodesulfurization of fuel oil, etc.), coal pulverizers, and bottom and fl y ash interactions. This de termination is optional.46 (3) The procedures in Method 19 of appendix A of this part shall be used to determine the percent

SO 2 reduction (%R g ) of any SO 2 control system. Alternatively, a combination of an “as fired” fuel

monitor and emission rates measured after the contro l system, following the procedures in Method 19 of appendix A of this part, may be used if the percen t reduction is calculated using the average emission

rate from the SO 2 control device and the average SO 2 input rate from the “as fired” fuel analysis for 30 successive boiler operating days.

(4) The appropriate procedures in Method 19 of appendi x A of this part shall be used to determine the

emission rate.

(5) The CEMS in §60.49Da(b) and (d) shall be used to determine the concentrations of SO 2 and CO 2 or O 2

. (d) The owner or operator shall determine compliance with the NO X standard in §60.44Da as follows:

(1) The appropriate procedures in Method 19 of appendi x A of this part shall be used to determine the

emission rate of NO X

. (2) The continuous monitoring system in §60.49Da(c) and (d) shall be used to determine the

concentrations of NO X and CO 2 or O 2

. (e) The owner or operator may use the following as a lternatives to the reference methods and procedures specified in this section:

(1) For Method 5 or 5B of appendix A–3 of this part , Method 17 of appendix A–6 of this part may be

used at facilities with or without wet FGD systems if the stack temp erature at the sampling location does not exceed an average temperature of 160 °C (320 °F). The procedures of sections 8.1 and 11.1 of Method 5B of appendix A–3 of this part may be used in Method 17 of appendix A–6 of this part only if it is used after wet FGD systems. Method 17 of appendi x A–6 of this part shall not be used after wet FGD systems if the effluent is saturated or laden with water droplets.

(2) The F

c factor (CO 2 ) procedures in Method 19 of appendix A of this part may be used to compute the

emission rate of PM under the s tipulations of §60.46(d)(1). The CO 2 shall be determined in the same

manner as the O 2 concentration.

(f) Electric utility combined cycle gas turbines that are not designed to burn fuels containing 50 percent (by heat input) or more solid derived fuel not m eeting the definition of natural gas are performance tested for PM, SO 2 , and NO X using the procedures of Method 19 of appendix A–7 of this part. The

SO 2 and NO X emission rates calculations from the gas turbine used in Method 19 of appendix A–7 of this part are determined when the ga s turbine is performance tested under subpart GG of this part. The potential uncontrolled PM emission rate from a gas turb ine is defined as 17 ng/J (0.04 lb/MMBtu) heat input.

( g ) For the purposes of determining compliance w ith the emission limits in §60.45Da, the owner or operator of an electric utili ty steam generating unit which is al so a cogeneration unit shall use the procedures in paragraphs (g)(1) and (2) of this s ection to calculate emission rates based on electrical output to the grid plus 75 percent of the equivalent electrical energy (measure d relative to ISO conditions) in the unit's process stream.

(1) All conversions from Btu/hr unit input to MW unit output must use equivalents found in 40 CFR 60.40(a)(1) for electric utilities ( i.e. , 250 MMBtu/hr input to an electric utility steam genera ting unit is equivalent to 73 MW input to the electric utility steam generating unit); 73 MW input to the electric utility steam generating unit is equivalent to 25 MW output from the boiler electric utility steam Comment [CF47]: Deleted CAMR provision47 generating unit; therefore, 250 MMBtu inpu t to the electric utility steam generating unit is equivalent to 25 MW output from the electric utility steam generating unit).

(2) Use the Equation 5 in this section to determine the cogeneration Hg emission rate over a specific compliance period.

Wher e:

ER cogen = Cogeneration Hg emission rate over a compliance period in lb/MWh;

E = Mass of Hg emitted from the stack over the same compliance period (lb);

V grid = Amount of energy sent to the grid over the same compliance period (MWh); and

V process = Amount o f energy converted to steam for process use over the same compliance period (MWh).

(h) The owner or operator shall determine compliance with the Hg limit in §60.45Da according to the procedures in paragraphs (h)(1) through (3) of this section.

(1) The init ial performance test shall be commenced by the applicable date specified in §60.8(a). The required CEMS must be certified prior to commenc ing the test. The performance test consists of collecting hourly Hg emission data (lb/MWh) with the CEMS for 12 succes sive months of unit operation (excluding hours of unit startup, shutdown a nd malfunction). The average Hg emission rate is calculated for each month, and then the weighted, 12

- month average Hg emission rate is calculated according to paragraph (h)(2) or (h )(3) of this section, as applicable. If, for any month in the initial performance test, the minimum data capture requirement in §60.49Da(p)(4)(i) is not met, the owner or operator shall report a substitute Hg emission rate for that month, as follows. For t he first such month, the substitute monthly Hg emission rate shall be the arithmetic average of all valid hourly Hg emission rates recorded to date. For any s ubsequent month(s) with insufficie nt data capture, the substitute monthly Hg emission rate shall b e the highest valid hourly Hg emission rate recorded to date. When the

12

- month average Hg emission rate for the initial performance test is calculated, for each month in which there was insufficient data capture, the substitute monthly Hg emission rate sh all be weighted according to the number of unit operating hours in that month. Following the initial performance test, the owner or operator shall demonstrate compliance by calculating the weighted average of all monthly Hg emission rates (in lb/MWh) for e ach 12 successive calendar mont hs, excluding data obtained during startup, shutdown, or malfunction.

(2) If a CEMS is used to demonstrate compliance, follow the procedures in paragraphs (h)(2)(i) through (iii) of this section to determine the 12

- month roll ing average.

(i) Calculate the total mass of Hg emissions over a month (M), in lb, using either Equation 6 in paragraph (h)(2)(i)(A) of this section or Equation 7 in paragraph (h)(2)(i)(B) of this section, in conjunction with Equation 8 in paragraph (h)(2) (i)(C) of this section.

(A) If the Hg CEMS measures Hg concentration on a wet basis, use Equation 6 below to calculate the Hg mass emissions for each valid hour:

Where:48 E h = Hg mass emissions for the hour, (lb);

K = Units conversion constant, 6.24 × 10 − 1 1 lb

- scm/μgm

- scf;

C h = Hourly H g concentration, wet basis, (μgm/scm);

Q h = Hourly stack gas volumetric flow rate, (scfh); and

t h = Unit operating time, i.e., the fraction of the hour for which the unit operated. For example, th = 0.50

for a half

- hour of unit o peration and 1.00 for a full hour of operation.

(B) If the Hg CEMS measures Hg concentration on a dry basis, use Equation 7 below to calculate the Hg

mass emissions for each valid hour:

Where:

E h = Hg mass emissions for the hour, (lb);

K = Units conversi on constant, 6.24 × 10 − 11 lb

- scm/μgm

- scf;

C h = Hourly Hg concentration, dry basis, (μgm/dscm);

Q h = Hourly stack gas volumetric flow rate, (scfh);

t h = Unit operating time, i.e. , the fraction of the hour for which the unit operated; and

B
ws = Stack gas moisture content, expressed a s a decimal fraction ( e.g. , for 8 percent H 2 O, B

ws = 0.08).

(C) Use Equation 8, below, to calculate M, the total mass of Hg emitted for the month, by summing the hourly masses derived from Equation 6 or 7 (as applicable):

Where:

M = Total Hg mass emiss ions for the month, (lb);

E h = Hg mass emissions for hour “h”, from Equation 6 or 7 of this section, (lb); and

n = Number of unit operating hours in the month with valid CE and electrical output data, excluding hours of unit startup, shutdown and malfunctio n.

(ii) Calculate the monthly Hg emissi on rate on an output basis (lb/MWh) using Equation 9, below. For a cogeneration unit, use Equation 5 in pa ragraph (g) of this section instead.

Where:

ER = Monthly Hg emission rate, (lb/MWh);

M = Total mass of Hg em issions for the month, from Equation 8, above, (lb); and

P = Total electrical output for the month, fo r the hours used to calculate M, (MWh).49 (iii) Until 12 monthly Hg emission rates have been accumulated, calculate and report only the monthly averages. Th en, for each subsequent calendar month, use Equation 10 below to calculate the 12

- month rolling average as a weighted average of the Hg emis sion rate for the current month and the Hg emission rates for the previous 11 months , with one exception. Calendar m onths in which the unit does not operate (zero unit operating hours) shall not be included in the 12

- month rolling average.

Where:

E avg = Weighted 12

- month rolling average Hg emission rate, (lb/MWh);

ER i = Monthly Hg emission rate, for month “i”, (lb/MWh) ; and

n = Number of unit operating hours in month “i” with valid CEM and electrical output data, excluding hours of unit startup, shutdown, and malfunction.

(3) If a sorbent trap monitoring system is used in lieu of a Hg CEMS, as described in §75.15 of thi s chapter and in appendix K to part 75 of this chapte r, calculate the monthly Hg emission rates using Equations 7 through 9 of this section, except that for a particular pair of sorbent traps, C h in Equation 7

shall be the flow

- proportional average Hg conce ntration measured over the data collection period.

(i) Daily calibration drift (CD) tests and quarterly accuracy determinations shall be performed for Hg CEMS in accordance with Procedure 1 of appendix F to this part. For the CD assessments, you may use

ei ther elemental mercury or mercuric chloride (Hg° HgCl 2 ) standards. The four quarterly accuracy

determinations shall consist of one RATA a nd three measurement error (ME) tests using HgCl 2 standards, as described in section 8.3 of Performance Specification 12

– A in appendix B to this part (note: Hg° standards may be used if the Hg m onitor does not have a converter). Alternatively, the owner or operator may implement the applicable dail y, weekly, quarterly, and annual quality assurance (QA) requirements for Hg C EMS in appendix B to part 75 of this chapter, in lieu of the QA procedures in appendices B and F to this part. Annual RATA of sorbent trap monitoring systems shall be performed in accordance with appendices A and B to part 75 of this chapter, and all other quality assurance requirements specified in appendix K to part 75 of this chapter shall be met for sorbent trap monitoring
systems.

§60.51Da Reporting requirements.

(a) For SO 2 , NO X , PM

, and Hg NO X plus CO emissions, the performance test data from the initial and subsequent performance test and from the performanc e evaluation of the continuous monitors (including the transmissometer) are submitted must be reported to the Administrator.

(b) For SO 2 and NO X the following information is reported to the Administrator for each 24-hour period.

(1) Calendar date.

(2) The average SO 2 and NO X emission rates (ng/J, lb/MMBtu, or lb/MWh) 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, descript ion of corrective actions taken.50 (3) For owners or operators of affected facilitie s complying with the percent reduction requirement, percent reduction of the potentia l combustion concentration of SO 2 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 whic h pollutant or diluent data have not been obtained by an approved method for at least 75 percent of the hours of operation of the facility; justification for not obtaining sufficient data; and desc ription 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 (NO X only), emergency conditions (SO 2 only), or other reasons, and justification for excluding da ta for reasons other than startup, shutdown, malfunction, or em ergency conditions or malfunction

. (6) Identification of “F” factor used for calculations, method of determination, and type of fuel

combusted.

(7) Identification of times when hourly averag es have been obtained based on manual sampling

methods.

(8) Identification of the times when the pollutant concentration exceeded full span of the CEMS.

(9) Description of any modifications to CEMS which could affect the ability of the CEMS to comply with Performance Specifications 2 or 3.

(c) If the minimum quantity of emission data as required by §60.49Da is not obtained for any 30 successive boiler operating days, the following information obtained under the requirements of §60.48Da(h) is reported to the Administrator for that 30-day period:

(1) The number of hourly averages available for outle t emission rates (no) and inlet emission rates (n i ) as applicable.

(2) The standard deviation of hourly averages for outlet emission rates (s

o ) and inlet emission rates (s i ) as applicable.

(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.

(4) The applicable potential combustion concentration.

(5) The ratio of the upper confidence limit for the mean outlet emission rate (E

o *) and the allowable emission rate (E std ) as applicable.

(d) If any standards under In addition to the applicable requirements in §60. 7 43Da are exceeded during emergency conditions because of control system malfunction , the owner or operator of the an affected facility subject to the opacity limits in §60.43c(c) and conducting performance tests using Method 9 of appendix A-4 of this part shall submit a signed statement: excess emission reports for any excess emissions from the affected facility that occu r during the reporting period and maintain records according to the requirements specified in paragraph (d)(1) of this section.

(1) Indicating if emergency conditions existed and requirements under §60.48Da(d) were met during each period, and For each performance test conducted using Method 9 of appendix A-4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (c)(1)(i) through (iii) of this section.

(i) Dates and time intervals of all opacity observation periods;51 (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and

(iii) Copies of all visible emission observer opacity field data sheets.

(2) ]RESERVED]

(2) L isting 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 neighbor ing 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 SO 2 emission standard under §60.43Da is claimed, the owner or operator of the affected facility shall submit a signed statement:

(1) Indicating what percentage cleaning credit was ta ken for the calendar quarter, and whether the credit was determined in accordance with the provisions of §60.50Da and Method 19 of appendix A of this part; 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, SO 2 or NO X emissions data are not available, the owner or operator of the affected facility shall submit a sign ed 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) For Hg, the following information shall be reported to the Administrator:

(1) Company name and addres s;

(2) Date of report and beginning and ending dates of the reporting period;

(3) The applicable Hg emission limit (lb/MWh); and

(4) For each month in the reporting period:

(i) The number of unit operating hours;

(ii) The number of unit operating hours wit h valid data for Hg concentration, stack gas flow rate, moisture (if required), and electrical output;

(iii) The monthly Hg emission rate (lb/MWh);

(iv) The number of hours of valid data excluded from the calculation of the monthly Hg emission rate,

due to unit startup, shutdown and malfunction; and52 (v) The 12

- month rolling average Hg emission rate (lb/MWh); and

(5) The data assessment report (DAR) required by appe ndix F to this part, or an equivalent summary of QA test results if the QA of part 75 of this chapter are implemented.

(g) [Reserved]

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

(1) The required CEMS calibration, span, and drift chec ks or other periodic audits have or have not been performed as specified.

(2) The data used to show compliance was or wa s 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.

(i) For the purposes of the reports required under §60. 7, periods of excess emissions are defined as all 6- minute periods during which the average opacity exceeds the applicable opacity standards under §60.42Da(b). Opacity levels in excess of the applicable opacity standard and the date of such excesses are to be submitted to the Administrator each calendar quarter.

(j) The owner or operator of an affected facility shall submit the written reports required under this section and subpart A to the Administrator semia nnually for each six-month period. All semiannual reports shall be postmarked by the 30th day fo llowing the end of each six-month period.

(k) The owner or operator of an affected facili ty may submit electronic quarterly reports for SO 2 and/or

NO X and/or opacity and/or Hg in lieu of submitting the written reports required under paragraphs (b), (g), and (i) of this section. The format of each qua rterly electronic report shall be coordinated with the permitting authority. The electronic report(s) shall be submitted no later than 30 days after the end of the calendar quarter and shall be accompanied by a cert ification statement from the owner or operator, indicating whether compliance with the applicable emission standards and minimum data requirements of this subpart was achieved during the reporting peri od. Before submitting reports in the electronic format, the owner or operator shall coordinate with the permitting authority to obtain their agreement to submit reports in this alternative format.

§60.52Da Recordkeeping requirements.

(a) The owner or operator of an affected fac ility subject to the emissions limitations in §60.45Da shall provide notifications in accordance with §60.7(a) and sh all maintain records of all information needed to demonstrate compliance including performance te sts, monitoring data, fuel analyses, and c alculations, consistent with the requirements of §60.7(f).

(a) [Reserved]

(b) The owner or operator of an affected facility subj ect to the opacity limits in §60.42Da(b) that elects to monitor emissions according to the requirement s in §60.49Da(a)(3) shall maintain records according to the requirements specified in paragraphs (b)(1) throu gh (3) of this section, as applicable to the visible emissions monitoring method used.

(1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(1)(i) through (iii) of

this section.53 (i) Dates and time intervals of all opacity observation periods;

(ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and

(iii) Copies of all visible emission observer opacity field data sheets;

(2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (b)(2)(i) through (iv) of

this section.

(i) Dates and time intervals of all visible emissions observation periods;

(ii) Name and affiliation for each visible emission observer participating in the performance test;

(iii) Copies of all visible emission observer opacity field data sheets; and

(iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operato r to demonstrate compliance with the applicable monitoring requirements.

(3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the

Administrator.