P.1 

OAR Box 1865 

Prepped by Charmelle Mathews 

Document Number: 

189) IX-A-2 

Docket Number: 

A-83-27 

Printed 12/3/2008 3:22:24 PM Sheet 189 of 198 
P.2 

A-83-27 

IX-A-2 

Protection of 

Environment 

MAP 27(991 

40 

PARTS 53 TO 60 

Revised as of July 1, 1990 
P.3 

^ 

Environmental Protection Agency 

§ 60.40b 

of 

rdance 

'and M$ 

tth the 

Ehod 19 

fuantity/heat 

'and date *ach pretreated 

shipment jwas received 

5us quarter;Xhe nante and lotation 

of theifuel Dretreatment facitfty; an; 

the t^tal quantity and total/neat ci 

tenyof all/fuels received at/the affect 

edyfacilitf duringythe preyfe-us quarter. 

/(f) For any periods fojr whicir opac 

ty, sujsur diqjflde or >Utrogon oxides 

data are nbt av 

erator>or the 

a signed sti 

if any/6hanges of /the emissio; 

fectf 

e: 

owner or 

cDfty sh: 

idlcati 

opera 

system during the Period 

avaXability/Operaflons p/th e 

nem and affecjted facility d 

ofyflata unavailability i of 

able, 

fa-

ment 

ade in 

control 

tfted: 

'period 

e con-

y before 

data un-

compaDed wit 

trol s/stem and 

and/following th( 

av/ilabilll 

ag) The owner' or operator of they 

fected/iacility shall^ubmit a si 

statement Lntticatin^whether: 

The/required continuous moni-

stem calibration, span, and 

ctrecks or other perioaic audil 

5r havr not been performed, 

fied. 

The/data usedyCo show cpfmpli-

or was rums\ obtained^ in ac-

with approved methods and 

lures of Uos part and is repre-

of plant performance. 

(3) The rnjymnurn dat^t require) 

lave or have not been met; 

' minimurr/aata requirements 

been rafti for error* that wet 

able. 

(4/Compliance with tlie stani 

has irot been achieved d] 

reporting peri< 

(h) Foi'the purposes of the^reports 

required under 5,00.7. period* of excj 

emissions are arefined assail 6-mbnite 

periods during which/the average 

opacity exceeds the ajsplicable/opacity 

standard^ under 5JW>.42a(b)/OpaciJ 

levels inexcessofine appl 

ty standard and/the dat 

are to Jtfe subi 

ministrator/ach calendar 

(i) The jflwner or/operal 

fected facility shall submit 

Subpart Db—Standards of Perform-

ance for Industrial-Commercial-

Institutional Steam Generating 

Units 

SOURCE: 52 FR 47842. Dec. 16, 1987. unless 

otherwise noted. 

§ 60.40b Applicability and delegation of 

authority. 

(a) The affected facility to which 

this subpart applies is each steam gen-

erating unit that commences construc-

tion, modification, or reconstruction 

after June 19, 1984, and that has a 

heat input capacity from fuels com-

busted in the steam generating unit of 

greater than 29 MW (100 million Btu/ 

hour). 

(b) Any affected facility meeting the 

applicability requirements under para-

graph (a) of this section and commenc-

ing construction, modification, or re-

construction after June 19, 1984, but 

on or before June 19, 1986. is subject 

to the following standards: 

(1) Coal-fired affected facilities 

having a heat input capacity between 

29 and 73 MW (100 and 250 million 

Btu/hour), inclusive, are subject to 

the particulate matter and nitrogen 

oxides standards under this subpart. 

(2) Coal-fired affected facilities 

having a heat input capacity greater 

than 73 MW (250 million Btu/hour) 

and meeting the applicability require-

ments under Subpart D (Standards of 

performance for fossil-fuel-fired steam 

generators; § 60.40) are subject to the 

particulate matter and nitrogen oxides 

standards under this subpart and to 

the sulfur dioxide standards under 

Subpart D (§ 60.43). 

(3) Oil-fired affected facilities 

having a heat input capacity between 

29 and 73 MW (100 and 250 million 

Btu/hour), inclusive, are subject to 

the nitrogen oxides standards under 

this subpart. 

(4) Oil-fired affected facilities 

having a heat input capacity greater 

275 
P.4 

§ 60.41b 

than 73 MW (250 million Btu/hour) 

and meeting the applicability require-

ments under Subpart D (Standards of 

performance for fossil-fuel-fired steam 

generators; 5 60.40) are also subject to 

the nitrogen oxides standards under 

this subpart and the particulate 

matter and sulfur dioxide standards 

under Subpart D (§ 60.42 and § 60.43). 

(c) Affected facilities which also 

meet the applicability requirements 

under Subpart J (Standards of per-

formance for petroleum refineries; 

§ 60.104) are subject to the particulate 

matter and nitrogen oxides standards 

under this subpart and the sulfur di-

oxide standards under Subpart J 

(§60.104). 

(d) Affected facilities which also 

meet the applicability requirements 

under Subpart E (Standards of per-

formance for incinerators; § 60.50) are 

subject to the nitrogen oxides and par-

ticulate matter standards under this 

subpart. 

(e) Steam generating units meeting 

the applicability requirements under 

Subpart Da (Standards of perform-

ance for electric utility steam generat-

ing units; 5 60.40a) are not subject to 

this subpart. 

(f) Any change to an existing steam 

generating unit for the sole purpose of 

combusting gases containing TRS as 

defined under §60.281 is not consid-

ered a modification under § 60.14 and 

the steam generating unit is not sub-

ject to this subpart. 

(g) In delegating implementation 

and enforcement authority to a State 

under section 111(c) of the Act, the 

following authorities shall be retained 

by the Administrator and not trans-

ferred to a State. 

(1) Section 60.44b(f). 

(2) Section 60.44b(g). 

(3) Section 60.49b(a)(4). 

§ 60.41b 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. 

Annual capacity factor means the 

ratio between the actual heat input to 

a steam generating unit from the fuels 

listed in §60.42b(a), §60.43b(a). or 

§ 60.44b(a), as applicable, during a cal-

endar year and the potential heat 

40 CFR Ch. I (7-1-90 Edition) 

input to the steam generating unit 

had it been operated for 8,760 hours 

during a calendar year at the maxi-

mum steady state design heat input 

capacity. In the case of steam generat-

ing units that are rented or leased, the 

actual heat input shall be determined 

based on the combined heat input 

from all operations of the affected fa-

cility in a calendar year. 

Byproduct/waste means any liquid 

or gaseous substance produced at 

chemical manufacturing plants or pe-

troleum refineries (except natural gas, 

distillate oil, or residual oil) and com-

busted in a steam generating unit for 

heat recovery or for disposal. Gaseous 

substances with carbon dioxide levels 

greater than 50 percent or carbon 

monoxide levels greater than 10 per-

cent are not byproduct/waste for the 

purposes of this subpart. 

Chemical manufacturing plants 

means industrial plants which are clas-

sified by the Department of Com-

merce under Standard Industrial Clas-

sification (SIC) Code 28. 

Coal means all solid fuels classified 

as anthracite, bituminous, subbitumin-

ous, or lignite by the American Society 

of Testing and Materials in ASTM 

D388-77. Standard Specification for 

Classification of Coals by Rank (IBR— 

see § 60.17), coal ref use, and petroleum 

coke. Coal-derived synthetic fuels, in-

cluding but not limited to solvent re-

fined coal, gasified coal, coal-oil mix-

tures, and coal-water mixtures, are 

also included in this definition for the 

purposes of this subpart. 

Coal refuse means any byproduct of 

coal mining or coal cleaning oper-

ations with an ash content greater 

than 50 percent, by weight, and a 

heating value less than 13,900 kJ/kg 

(6,000 Btu/lb) on a dry basis. 

Combined cycle system means a 

system in which a separate source, 

such as a gas turbine, internal combus-

tion engine, kiln, etc., provides ex-

haust gas to a heat recovery steam 

generating unit. 

Conventional technology means wet 

flue gas desulfurization (FGD) tech-

nology, dry FGD technology, atmos-

pheric fluidized bed combustion tech-

nology, and oil hydrodesulfurization 

technology. 

276 
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Environmental Protection Agency 

Distillate oil means fuel oils that 

contain 0.05 weight percent nitrogen 

or less and comply with the specifications for fuel oil numbers 1 and 2, as 

defined by the American Society of 

Testing and Materials in ASTM D396-

78, Standard Specifications for Fuel 

Oils (incorporated by reference—see 

§ 60.17). 

Dry flue gas desulfurization technology means a sulfur dioxide control 

system that is located downstream of 

the steam generating unit and removes sulfur oxides from the combustion gases of the steam generating 

unit by contacting the combustion 

gases with an alkaline slurry or solution and forming a dry powder material. This definition includes devices 

where the dry powder material is subsequently converted to another form. 

Alkaline slurries or solutions used in 

dry flue gas desulfurization technology include but are not limited to lime 

and sodium. 

Duct burner means a device that 

combusts fuel and 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 before the exhaust gases enter a heat recovery 

steam generating unit. 

Emerging technology means any 

sulfur dioxide control system that is 

not defined as a conventional technology under this section, and for which 

the owner or operator of the facility 

has applied to the Administrator and 

received approval to operate as an 

emerging technology under 

§ 60.49b(a)(4). 

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 requirements established under 40 CFR 52.21 or under 

40 CFR 51.18 and 40 CFR 51.24. 

Fluidized bed combustion technology 

means combustion of fuel in a bed or 

series of beds (including but not limited to bubbling bed units and circulating bed units) of limestone aggregate 

(or other sorbent materials) in which 

these materials are forced upward by 

§ 60.41b 

the flow of combustion air and the 

gaseous products of combustion. 

Fuel pretreatment means a process 

that removes a portion of the sulfur in 

a fuel before combustion of the fuel in 

a steam generating unit. 

Full capacity means operation of the 

steam generating unit at 90 percent or 

more of the maximum steady-state 

design heat input capacity. 

Heat input means heat derived from 

combustion of fuel in a steam generating unit and does not include the heat 

input from preheated combustion air, 

recirculated flue gases, or exhaust 

gases from other sources, such as gas 

turbines, internal combustion engines, 

kilns, etc. 

Heac release rate means the steam 

generating unit design heat input capacity (in MW or Btu/hour) divided 

by the furnace volume (in cubic 

meters or cubic feet); the furnace 

volume is that volume bounded by the 

front furnace wall where the burner is 

located, the furnace side waterwall, 

and extending to the level just below 

or in front of the first row of convection pass tubes. 

Heat transfer medium means any 

material that is used to transfer heat 

from one point to another point. 

High heat release rate means a heat 

release rate greater than 730,000 J/ 

sec-m3 (70,000 Btu/hour-fts). 

Lignite means a type of coal classified as lignite A or lignite B by the 

American Society of Testing and Materials in ASTM D388-77, Standard 

Specification for Classification of 

Coals by Rank (IBR—see § 60.17). 

Low heat release rate means a heat 

release rate of 730,000 J/sec-m3 

(70,000 Btu/hour-ft3) or less. 

Mass-feed stoker steam generating 

unit means a steam generating unit 

where solid fuel is introduced directly 

into a retort or is fed directly onto a 

grate where it is combusted. 

Maximum heat input capacity 

means the ability of a steam generating unit to combust a stated maximum 

amount of fuel on a steady state basis, 

as determined by the physical design 

and characteristics of the steam generating unit. 

Municipal-type solid waste means 

refuse, more than 50 percent of which 

is waste consisting of a mixture of 

277 
P.6 

§ 60.41b 

paper, wood, yard wastes, food wastes, 

plastics, leather, rubber, and other 

combustible materials, and noncom-

bustible materials such as glass and 

rock. 

Natural gas means (1) a naturally 

occurring mixture of hydrocarbon and 

nonhydrocarbon gases found in geo-

logic formations beneath the earth's 

surface, of which the principal constit-

uent is methane; or (2) liquid petrole-

um gas, as defined by the American 

Society for Testing and Materials in 

ASTM D1835-82, "Standard Specifica-

tion for Liquid Petroleum Gases" 

(IBR—see § 60.17). 

Noncontinental area means the 

State of Hawaii, the Virgin Islands, 

Guam, American Samoa, the Commonwealth of Puerto Rico, or the 

Northern Mariana Islands. 

Oil means crude oil or petroleum or 

a liquid fuel derived from crude oil or 

petroleum, including distillate and re-

sidual oil. 

Petroleum refinery means industrial 

plants as classified by the Department 

of Commerce under Standard Indus-

trial Classification (SIC) Code 29. 

Potential sulfur dioxide emission 

rate means the theoretical sulfur diox-

ide emissions (ng/J, lb/million Btu 

heat input) that would result from 

combusting fuel in an uncleaned state 

and without using emission control 

systems. 

Process heater means a device that is 

primarily used to heat a material to 

initiate or promote a chemical reac-

tion in which the material participates 

as a reactant or catalyst. 

Pulverized coal-fired steam generating unit means a steam generating 

unit in which pulverized coal is intro-

duced into an air stream that carries 

the coal to the combustion chamber of 

the steam generating unit where it is 

fired in suspension. This includes both 

conventional pulverized coal-fired and 

micropulverized coal-fired steam gen-

erating units. 

Residual oil means crude oil, fuel oil 

numbers 1 and 2 that have a nitrogen 

content greater than 0.05 weight per-

cent, and all fuel oil numbers 4, 5 and 

6, as defined by the American Society 

of Testing and Materials in ASTM 

D396-78, Standard Specifications for 

Fuel Oils (IBR—see § 60.17). 

40 CFR Ch. I (7-1-90 Edition) 

Spreader stoker steam generating 

unit means a steam generating unit in 

which solid fuel is introduced to the 

combustion zone by a mechanism that 

throws the fuel onto a grate from 

above. Combustion takes place both in 

suspension and on the grate. 

Steam generating unit means a 

device that combusts any fuel or by-

product/waste to produce steam or to 

heat water or any other heat transfer 

medium. This term includes any mu-

nicipal-type solid waste incinerator 

with a heat recovery steam generating 

unit or any steam generating unit that 

combusts fuel and is part of a cogen-

eration system or a combined cycle 

system. This term does not include 

process heaters as they are defined in 

this subpart. 

Steam generating unit operating day 

means a 24-hour period between 12:00 

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 com-

busted continuously for the entire 24-

hour period. 

Very low sulfur oil means an oil that 

contains no more than 0.5 weight per-

cent sulfur or that, when combusted 

without sulfur dioxide emission con-

trol, has a sulfur dioxide emission rate 

equal to or less than 215 ng/J (0.5 lb/ 

million Btu) heat input. 

Wet flue gas desulfurization technology means a sulfur dioxide control 

system that is located downstream of 

the steam generating unit and re-

moves sulfur oxides from the combus-

tion gases of the steam generating 

unit by contacting the combustion gas 

with an alkaline slurry or solution and 

forming a liquid material. This defini-

tion applies to devices where the aque-

ous liquid material product of this 

contact is subsequently converted to 

other forms. Alkaline reagents used in 

wet flue gas desulfurization technolo-

gy include, but are not limited to, lime, 

limestone, and sodium. 

Wet scrubber system means any 

emission control device that mixes an 

aqueous stream or slurry with the ex-

haust gases from a steam generating 

unit to control emissions of particulate 

matter or sulfur dioxide. 

Wood means wood, wood residue, 

bark, or any derivative fuel or residue 

^ 

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Environmental Protection Agency 

thereof, in any form, including, but 

not limited to, sawdust, sanderdust, 

wood chips, scraps, slabs, millings, 

shavings, and processed pellets made 

from wood or other forest residues. 

[52 FR 47842, Dec. 16. 1987, as amended at 54 FR 51819, Dec. 18.1989] § 60.42b Standard for sulfur dioxide. 

(a) Except as provided in paragraphs 

(b). (c), (d), or (j) of this section, on 

and after the date on which the per-

formance test is completed or required 

to be completed under § 60.8 of this 

part, whichever date comes first, no 

owner or operator of an affected facili-

ty that combusts coal or oil shall cause 

to be discharged into the atmosphere 

any gases that contain sulfur dioxide 

in excess of 10 percent (0.10) of the po-

tential sulfur dioxide emission rate (90 

percent reduction) and that contain 

sulfur dioxide in excess of the emis-

sion limit determined according to the 

following formula: 

E.=(KA+KfcHb)/<H.+H„> 

where: E, is the sulfur dioxide emission limit, in 

ng/J or lb/million Btu heat input. 

K. is 520 ng/J (or 1.2 lb/million Btu). K„ is 340 ng/J (or 0.80 lb/million Btu). H, is the heat input from the combustion of 

coal, in J (million Btu), 

H„ is the heat input from the combustion of 

oil, in J (million Btu). 

Only the heat input supplied to the affected facility from the combustion of 

coal and oil is counted under this sec-

tion. No credit is provided for the heat 

input to the affected facility from the 

combustion of natural gas, wood, mu-

nicipal-type solid waste, or other fuels 

or heat input to the affected facility 

from exhaust gases from another 

source, such as gas turbines, internal 

combustion engines, kilns, etc. 

(b) On and after the date on which 

the performance test is completed or 

required to be completed under § 60.8 

of this part, whichever comes first, no 

owner or operator of an affected facili-

ty that combusts coal refuse alone in a 

fluidized bed combustion steam gener-

ating unit shall cause to be discharged 

into the atmosphere any gases that 

contain sulfur dioxide in excess of 20 

Percent of the potential sulfur dioxide 

emission rate (80 percent reduction) 

and that contain sulfur dioxide in 

§ 60.42b 

excess of 520 ng/J (1.2 lb/million Btu) 

heat input. If coal or oil is fired with 

coal refuse, the affected facility is sub-

ject to paragraph (a) or (d) of this sec-

tion, as applicable. 

(c) On and after the date on which 

the performance test is completed or 

is required to be completed under 

§ 60.8 of this part, whichever comes 

first, no owner or operator of an affected facility that combusts coal or 

oil, either alone or in combination 

with any other fuel, and that uses an 

emerging technology for the control of 

sulfur dioxide emissions, shall cause to 

be discharged into the atmosphere any 

gases that contain sulfur dioxide in 

excess of 50 percent of the potential 

sulfur dioxide emission rate (50 per-

cent reduction) and that contain 

sulfur dioxide in excess of the emis-

sion limit determined according to the 

following formula: 

E,=(Kjac+K-Hd)/H«+Hd) 

where: E. is th

e sulfur dioxide emission limit, expressed in ng/J (lb/mlllion Btu) heat 

input, 

K. is 260 ng/J (0.60 lb/million Btu). K« is 170 ng/J (0.40 lb/mlllion Btu), 

E.. is the heat input from the combustion of 

coal, J (million Btu), 

HA is the heat input from the combustion of 

oil. J (million Btu). 

Only the heat input supplied to the affected facility from the combustion of 

coal and oil is counted under this sec-

tion. No credit is provided for the heat 

input to the affected facility from the 

combustion of natural gas, wood, mu-

nicipal-type solid waste, or other fuels, 

or from the heat input to the affected 

facility from exhaust gases from an-

other source, such as gas turbines, in-

ternal combustion engines, kilns, etc. 

(d) On and after the date on which 

the performance test is completed or 

required to be completed under §60.8 of 

this part, whichever comes first, no 

owner or operator of an affected facili-

ty listed in paragraphs (d) (1), (2), or 

(3) of this section shall cause to be dis-

charged into the atmosphere any 

gases that contain sulfur dioxide in 

excess of 520 ng/J (1.2 lb/million Btu) 

heat input if the affected facility com-

busts coal, or 215 ng/J (0.5 lb/million 

Btu) heat input lf the affected facility 

combusts oil other than very low 

279 

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P.8 

§ 60.43b 

sulfur oil. Percent reduction require-

ments are not applicable to affected 

facilities under this paragraph. 

(1) Affected facilities that have an 

annual capacity factor for coal and oil 

of 30 percent (0.30) or less and are sub-

ject to a Federally enforceable permit 

limiting the operation of the affected 

facility to an annual capacity factor 

for coal and oil of 30 percent (0.30) or 

less; 

(2) Affected facilities located in a 

noncontinental area; or 

(3) Affected facilities combusting 

coal or oil, alone or in combination 

with any other fuel, in a duct burner 

as part of a combined cycle system 

where 30 percent (0.30) or less of the 

heat input to the steam generating 

unit is from combustion of coal and oil 

in the duct burner and 70 percent 

(0.70) or more of the heat input to the 

steam generating unit is from the ex-

haust gases entering the duct burner. 

(e) Except as provided in paragraph 

(f) of this section, compliance with the 

emission limits, fuel oil sulfur limits, 

and/or percent reduction require-

ments under this section are deter-

mined on a 30-day rolling average 

basis. 

(f) Except as provided in paragraph 

(j)(2) of this section, compliance with 

the emission limits or fuel oil sulfur 

limits under this section is determined 

on a 24-hour average basis for affected 

facilities that (1) have a Federally en-

forceable permit limiting the annual 

capacity factor for oil to 10 percent or 

less, (2) combust only very low sulfur 

oil, and (3) do not combust any other 

fuel. 

(g) Except as provided in paragraph 

(i) of this section, the sulfur dioxide 

emission limits and percent reduction 

requirements under this section apply 

at all times, including periods of start-

up, shutdown, and malfunction. 

(h) Reductions in the potential 

sulfur dioxide emission rate through 

fuel pretreatment are not credited 

toward the percent reduction require-

ment under paragraph (c) of this sec-

tion unless: 

(1) Fuel pretreatment results in a 50 

percent or greater reduction in poten-

tial sulfur dioxide emissions and 

(2) Emissions from the pretreated 

fuel (without combustion or post com-

40 CFR Ch. I (7-1-90 Edition) 

bustion sulfur dioxide control) are 

equal to or less than the emission 

limits specified in paragraph (c) of 

this section. 

(i) An affected facility subject to 

paragraph (a), (b), or (c) of this sec-

tion may combust very low sulfur oil 

or natural gas when the sulfur dioxide 

control system is not being operated 

because of malfunction or mainte-

nance of the sulfur dioxide control 

system. 

(j) Percent reduction requirements 

are not applicable to affected facilities 

combusting only very low sulfur oil. 

The owner or operator of an affected 

facility combusting very low sulfur oil 

shall demonstrate that the oil meets 

the definition of very low sulfur oil by: 

(1) Following the performance testing 

procedures as described in § 60.45b(c) 

or § 60.45b(d), and following the moni-

toring procedures as described in 

§ 60.47b(a) or § 60.47b(b) to determine 

sulfur dioxide emission rate or fuel oil 

sulfur content; or (2) maintaining fuel 

receipts as described in § 60.49b(r). 

\ [52 FR 47842. Dec. 16, 1987. as amended at 54 FR 51819. Dec. 18.1989] § 60.43b Standard for particulate matter.. • 

(a) On and after the date on which., 

the initial performance test is com-

pleted or is required to be completed 

under § 60.8 of this part, whichever, 

comes first, no owner or operator of an 

affected facility which combusts coal 

or combusts mixtures of coal with" 

other fuels, shall cause to be dis-. 

charged into the atmosphere from, 

that affected facility any gases tha£ 

contain particulate matter in excess ot 

the following emission limits: v 

(1) 22 ng/J (0.05 lb/million Btu). 

heat input, :-^ 

(i) If the affected facility combusts, 

only coal, or i y 

(ii) If the affected facility combusts: 

coal and other fuels and has an annual, 

capacity factor for the other fuels- c£ 

10 percent (0.10) or less. -*M. 

(2) 43 ng/J (0.10 lb/million Bti&J 

heat input if the affected facility coop 

busts coal and other fuels and has My 

annual capacity factor for the othdp 

fuels greater than 10 percent (0.1C 

and is subject to a federally enfor 

ble requirement limiting operation 

280 
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Environmental Protection Agency 

the affected facility to an annual capacity factor greater than 10 percent 

(0.10) for fuels other than coal. 

(3) 86 ng/J (0.20 lb/million Btu) 

heat input if the affected facility combusts coal or coal and other fuels and 

(i) Has an annual capacity factor for 

coal or coal and other fuels of 30 percent (0.30) or less, 

(ii) Has a maximum heat input capacity of 73 MW (250 million Btu/ 

hour) or less, 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity 

factor of 30 percent (0.30) or less for 

coal or coal and other solid fuels, and 

(iv) Construction of the affected facility commenced after June 19, 1984, 

and before November 25, 1986. 

(b) On and after the date on which 

the performance test is completed or 

required to be completed under 60.8 of 

this part, whichever date comes first, 

no owner or operator of an affected facility that combusts oil (or mixtures of 

oil with other fuels) and uses a conventional or emerging technology to 

reduce sulfur dioxide emissions shall 

cause to be discharged into the atmosphere from that affected facility any 

gases that contain particulate matter 

in excess of 43 ng/J (0.10 lb/million 

Btu) heat input. 

(c) On and after the date on which 

the initial performance test is completed or is required to be completed 

under § 60.8 of this part, whichever 

date comes first, no owner or operator 

of an affected facility that combusts 

wood, or wood with other fuels, except 

coal, shall cause to be discharged from 

that affected facility any gases that 

contain particulate matter in excess of 

the following emission limits: 

(1) 43 ng/J (0.10 lb/million Btu) 

heat input if the affected facility has 

an annual capacity factor greater than 

30 percent (0.30) for wood. 

(2) 86 ng/J (0.20 lb/million Btu) 

heat input if 

(i) The affected facility has an 

annual capacity factor of 30 percent 

(0.30) or less for wood, 

(ii) is subject to a federally enforceable requirement limiting operation of 

the affected facility to an annual capacity factor of 30 percent (0.30) or 

tess for wood, and 

§ 60.43b 

(iii) Has a maximum heat input capacity of 73 MW (250 million Btu/ 

hour) or less. 

(d) On and after the date on which 

the initial performance test is completed or is required to be completed 

under § 60.8 of this part, whichever 

date comes first, no owner or operator 

of an affected facility that combusts 

municipal-type solid waste or mixtures 

of municipal-type solid waste with 

other fuels, shall cause to be discharged into the atmosphere from 

that affected facility any gases that 

contain particulate matter in excess of 

the following emission limits: 

(1) 43 ng/J (0.10 lb/million Btu) 

heat input, 

(i) If the affected facility combusts 

only municipal-type solid waste, or 

(ii) If the affected facility combusts 

municipal-type solid waste and other 

fuels and has an annual capacity 

factor for the other fuels of 10 percent 

(0.10) or less. 

(2) 86 ng/J (0.20 lb/million Btu) 

heat input if the affected facility combusts municipal-type solid waste or 

municipal-type solid waste and other 

fuels; and 

(i) Has an annual capacity factor for 

municipal-type solid waste and other 

fuels of 30 percent (0.30) or less, 

(ii) Has a maximum heat input capacity of 73 MW (250 million Btu/ 

hour) or less, 

(iii) Has a federally enforceable requirement limiting operation of the affected facility to an annual capacity 

factor of 30 percent (0.30) for municipal-type solid waste, or municipal-type 

solid waste and other fuels, and 

(iv) Construction of the affected facility commenced after June 19, 1984,. 

but before November 25,1986. 

(e) For the purposes of this section, 

the annual capacity factor is determined by dividing the actual heat 

input to the steam generating unit 

during the calendar year from the 

combustion of coal, wood, or municipal-type solid waste, and other fuels, 

as applicable, by the potential heat 

input to the steam generating unit if 

the steam generating unit had been 

operated for 8,760 hours at the maximum design heat input capacity. 

(f) On and after the date on which 

the initial performance test is com281 
P.10 

§ 60.44b 

pleted or is required to be completed 

under 60.8 of this part, whichever date 

comes first, no owner or operator of an 

affected facility that combusts coal, 

oil, wood, or mixtures of these fuels 

with any other fuels shall cause to be 

discharged into the atmosphere any 

gases that exhibit greater than 20 percent opacity (6-minute average), 

except for one 6-minute period per 

hour of not more than 27 percent 

opacity. 

(g) The particulate matter and opacity standards apply at all times, except 

during periods of startup, shutdown or 

malfunction. 

-[52 FR 47842, Dec. 16. 1987. as amended at 

54 FR 51819. Dec. 18. 1989] 

§ 60.44b Standard for nitrogen oxides. 

(a) Except as provided under paragraph (k) of this section, on and after 

the date on which the initial performance test is completed or is required to 

be completed under § 60.8 of this part, 

whichever date comes first, no owner 

or operator of an affected facility that 

is subject to the provisions of this section and that combusts only coal, oil, 

or natural gas shall cause to be discharged into the atmosphere from 

that affected facility any gases that 

contain nitrogen oxides (expressed as 

NOi) in excess of the following emission limits: 

Fuel/Steam generating unit type 

(1) Natural gas and distillate od. except (4): 

(I) Low heat release rate 

00 High heat release rate 

(2) Residual oil: 

0) Low heat ralaain rate 

00 High heat release rate 

(3) Coal: 

0) Mass-fend stoker 

00 Spreader stoker and fluidized bed 

ffO Pufwt-td coal 

0Y) Uonrte except (v) 

(v) Lignite mined in North Dakota. South 

Dakota, or Montana and combusted in 

a slag *ap «i»naci» 

(vQ Coal-derived synthetic fuels 

(4) Duct burner used in a combined cycle 

system: 

0) Natural gas and dktiillate oil 

00 Residual oi 

NitroQon oxkte 

6nvMi0fi (vnits 

no/Jflb/ 

muon Btu) 

(expressed as 

NO.) heat 

input 

43 (0.10) 

86(0.20) 

130 (0.30) 

170 (0.40) 

210 (0.50) 

260 (0.60) 

300 (0.70) 

260 (0.60) 

340 (O.SO) 

210 (O.SO) 

86 (0.20) 

170 (0.40) 

40 CFR Ch. I (7-1-90 Edition) 

(b) Except as provided under paragraph (k) of this section, on and after 

the date on which the initial performance test is completed or is required to 

be completed under § 60.8 of this part, 

whichever date comes first, no owner 

or operator of an affected facility that 

simultaneously combusts mixtures of 

coal, oil, or natural gas shall cause to 

be discharged into the atmosphere 

from that affected facility any gases 

that contain nitrogen oxides in excess 

of a limit determined by use of the following formula: 

E„ = [(ELr> Hr>)+(ELto Hre)+(ELc H«)]/ 

(Kn+'a„+Ii<) 

where: 

E, is the nitrogen oxides emission limit (expressed as NO,), ng/J (lb/million Btu) 

EL„ is the appropriate emission limit from 

paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/million 

Btu) 

Hn is the heat input from combustion of 

natural gas or distillate oil, 

FTj,^ is the appropriate emission limit from 

paragraph (a)(2) for combustion of residual oil, 

Hre is the heat input from combustion of residual oil, 

EL, is the appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

and 

Km is the heat input from combustion of 

coal. 

(c) On and after the date on which 

the initial performance test is completed or is required to be completed 

under § 60.8 of this part, whichever 

comes first, no owner or operator of an 

affected facility that simultaneously 

combusts coal or oil, or a mixture of 

these fuels with natural gas. and wood, 

municipal-type solid waste, or any 

other fuel shall cause to be discharged 

into the atmosphere any gases that 

contain nitrogen oxides in excess of 

the emission limit for the coal or oil, 

or mixture of these fuels with natural 

gas combusted in the affected facility, 

as determined pursuant to paragraph' 

(a) or (b) of this section, unless the af* 

fected facility has an annual capacity 

factor for coal or oil. or mixture ot 

these fuels with natural gas of 10 per-, 

cent (0.10) or less and is subject to ft 

federally enforceable requirement; 

that limits operation of the facility ta 

an annual capacity factor of 10 pert 

- ^ 

282 
P.11 

n 

Environmental Protection Agency 

cent (0.10) or less for coal, oil, or a 

mixture of these fuels with natural 

gas. 

(d) On and after the date on which 

the initial performance test is com-

pleted or is required to be completed 

under § 60.8 of this part, whichever 

date comes first, no owner or operator 

of an affected facility that simulta-

neously combusts natural gas with 

wood, municipal-type solid waste, or 

other solid fuel, except coal, shall 

cause to be discharged into the atmos-

phere from that affected facility any 

gases that contain nitrogen oxides in 

excess of 130 ng/J (0.30 lb/million 

Btu) heat input unless the affected fa-

cility has an annual capacity factor for 

natural gas of 10 percent (0.10) or less 

and is subject to a federally enforcea-

ble requirement that limits operation 

of the affected facility to an annual 

capacity factor of 10 percent (0.10) or 

less for natural gas. 

(e) On and after the date on which 

the initial performance test is com-

pleted or is required to be completed 

under §60.8 of this part, whichever 

date comes first, no owner or operator 

of an affected facility that simulta-

neously combusts coal, oil, or natural 

gas with byproduct/waste shall cause 

to be discharged into the atmosphere 

from that affected facility any gases 

that contain nitrogen oxides in excess 

of an emission limit determined by the 

following formula unless the affected 

facility has an annual capacity factor 

for coal, oil, and natural gas of 10 per-

cent (0.10) or less and is subject to a 

federally enforceable requirement 

which limits operation of the affected 

facility to an annual capacity factor of 

10 percent (0.10) or less: 

E.= [(EL„ Hr,)+(ELre H„)+ (EL, H,)]/ 

(B^+H^+H.) 

where: 

E. is the nitrogen oxides emission limit (ex-

pressed as NOi). ng/J (lb/million Btu) 

EL,, is the appropriate emission limit from 

paragraph (a)(1) for combustion of natural gas or distillate oil, ng/J (lb/million 

Btu). 

Rn is the heat input from combustion of 

natural gas, distillate oil and gaseous by-

product/waste, ng/J (lb/million Btu). 

ELn is the appropriate emission limit from 

paragraph (a)(2) for combustion of residual oil. ng/J (lb/million Btu) 

§ 60.44b 

Hro is the heat input from combustion of residual oil and/or liquid byproduct/ 

waste. 

EL< is the appropriate emission limit from 

paragraph (a)(3) for combustion of coal, 

and 

Hc is the heat input from combustion of 

coal. 

(f) Any owner or operator of an affected facility that combusts byproduct/waste with either natural gas or 

oil may petition the Administrator 

within 180 days of the initial startup 

of the affected facility to establish a 

nitrogen oxides emission limit which 

shall apply specifically to that affect-

ed facility when the byproduct/waste 

is combusted. The petition shall in-

clude sufficient and appropriate data, 

as determined by the Administrator, 

such as nitrogen oxides emissions from 

the affected facility, waste composi-

tion (including nitrogen content), and 

combustion conditions to allow the 

Administrator to confirm that the affected facility is unable to comply 

with the emission limits in paragraph 

(e) of this section and to determine 

the appropriate emission limit for the 

affected facility. 

(1) Any owner or operator of an affected facility petitioning for a facility-specific nitrogen oxides emission 

limit under this section shall: 

(i) Demonstrate compliance with the 

emission limits for natural gas and dis-

tillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) of this section, as appropriate, 

by conducting a 30-day performance 

test as provided in 8 60.46b(e). During 

the performance test only natural gas, 

distillate oil, or residual oil shall be 

combusted in the affected facility; and 

(ii) Demonstrate that the affected 

facility is unable to comply with the 

emission limits for natural gas and dis-

tillate oil in paragraph (a)(1) of this 

section or for residual oil in paragraph 

(a)(2) of this section, as appropriate, 

when gaseous or liquid byproduct/ 

waste is combusted in the affected fa-

cility under the same conditions and 

using the same technological system 

of emission reduction applied when 

demonstrating compliance under para-

graph (f)(l)(i) of this section. 

(2) The nitrogen oxides emission 

limits for natural gas or distillate oil in 

283 
P.12 

§ 60.45b 

paragraph (a)(1) of this section or for 

residual oil in paragraph (a)(2) of this 

section, as appropriate, shall be applicable to the affected facility until and 

unless the petition is approved by the 

Administrator. If the petition is approved by the Administrator, a facility-specific nitrogen oxides emission 

limit will be established at the nitrogen oxides emission level achievable 

when the affected facility is combusting oil or natural gas and byproduct/ 

waste in a manner that the Administrator determines to be consistent 

with minimizing nitrogen oxides emissions. 

(g) Any owner or operator of an affected facility that combusts hazardous waste (as defined by 40 CFR part 

261 or 40 CFR part 761) with natural 

gas or oil may petition the Administrator within 180 days of the initial startup of the affected facility for a waiver 

from compliance with the nitrogen 

oxides emission limit which applies 

specifically to that affected facility. 

The petition must include sufficient 

and appropriate data, as determined 

by the Administrator, on nitrogen 

oxides emissions from the affected facility, waste destruction efficiencies, 

waste composition (including nitrogen 

content), the quantity of specific 

wastes to be combusted and combustion conditions to allow the Administrator to determine if the affected facility is able to comply with the nitrogen oxides emission limits required by 

this section. The owner or operator of 

the affected facility shall demonstrate 

that when hazardous waste is combusted in the affected facility, thermal 

destruction efficiency requirements 

for hazardous waste specified in an applicable federally enforceable require- >. 

ment preclude compliance with the ni- \ 

trogen oxides emission limits of this 

section. The nitrogen oxides emission 

limits for natural gas or distillate oil in 

paragraph (a)(1) of this section or for 

residual oil in paragraph (a)(2) of this 

section, as appropriate, are applicable 

to the affected facility until and 

unless the petition is approved by the 

Administrator. (See 40 CFR 761.70 for 

regulations applicable to the incineration of materials containing polychlorinated biphenyls (PCB's).) 

40 CFR Ch. I (7-1-90 Edition) 

(h) For purposes of paragraph (i) of 

this section, the nitrogen oxide standards under this section apply at all 

times including periods of startup, 

shutdown, or malfunction. 

(i) Except as provided under paragraph (j) of this section, compliance 

with the emission limits under this 

section is determined on a 30-day rolling average basis. 

(j) Compliance with the emission 

limits under this section is determined 

on a 24-hour average basis for the initial performance test and on a 3-hour 

average basis for subsequent performance tests for any affected facilities 

that: 

(1) Combust, alone or in combination, only natural gas, distillate oil, or 

residual oil with a nitrogen content of 

0.30 weight percent or less; 

(2) Have a combined annual capacity 

factor of 10 percent or less for natural 

gas, distillate oil, and residual oil with 

a nitrogen content of 0.30 weight percent or less; and 

(3) Are subject to a Federally enforceable requirement limiting operation of the affected facility to the 

firing of natural gas, distillate oil, 

and/or residual oil with a nitrogen 

content of 0.30 weight percent or less 

and limiting operation of the affected 

facility to a combined annual capacity 

factor of 10 percent or less for natural 

gas. distillate oil, and residual oil and a 

nitrogen content of 0.30 weight percent or less. 

(k) Affected facilities that meet the 

criteria described in paragraphs (j) (1), 

(2), and (3) of this section, and that 

have a heat input capacity of 73 MW^ 

(250 million Btu/hour) or less, are not 

subject to the nitrogen oxides emission limits under this section. -'. 

[52 FR 47842. Dec. 16, 1987. as amended at 

54 FR 51825, Dec. 18. 1989] ; ?r 

§ 60.45b Compliance and performance test 

methods and procedures for sulfur <U' _, 

oxide. ". •'•? 

(a) The sulfur dioxide emission^ 

standards under § 60.42b apply at alj{ 

times. 

(b) In conducting the performanc 

tests required under § 60.8, the owne 

or operator shall use the methods and 

procedures in Appendix A of this pa 

284 
t Environmenta

l Protection Agency 

or the methods and procedures as 

specified in this section, except as pro-

vided in § 60.8(b). Section 60.8(f) does 

not apply to this section. The 30-day 

notice required in § 60.8(d) applies 

only to the initial performance test 

unless otherwise specified by the Ad-

ministrator. 

(c) The owner or operator of an affected facility shall conduct performance tests to determine compliance 

with the percent of potential sulfur di-

oxide emission rate (% P.) and the 

sulfur dioxide emission rate (E.) pur-

suant to § 60.42b following the proce-

dures listed below, except as provided 

under paragraph (d) of this section. 

(1) The initial performance test shall 

be conducted over the first 30 consecu-

tive operating days of the steam gen-

erating unit. Compliance with the 

sulfur dioxide standards shall be de-

termined using a 30-day average. The 

first operating day included in the ini-

tial performance test shall be sched-

uled within 30 days after achieving the 

maximum production rate at which 

the affected facility will be operated, 

but not later than 180 days after ini-

tial startup of the facility. 

(2) lf only coal or only oil is com-

busted, the following procedures are 

used: 

(i) The procedures in Method 19 are 

used to determine the hourly sulfur 

dioxide emission rate (En,) and the 30-

day average emission rate (E*,). The 

hourly averages used to compute the 

30-day averages are obtained from the 

continuous emission monitoring 

system of 5 60.47b (a) or (b). 

(ii) The percent of potential sulfur 

dioxide emission rate (% P.) emitted to 

the atmosphere is computed using the 

following formula: 

% P.= 100 d-% R,/100)(l-% R./100) 

where: % R, Is th

e sulfur dioxide removal efficiency 

of the control device as determined by 

Method 19, In percent. 

% Rt is the sulfur dioxide removal efficiency 

of fuel pretreatment as determined by 

Method 19, in percent. 

(3) If coal or oil is combusted with 

other fuels, the same procedures re-

quired in paragraph (c)(2) of this sec-

tion are used, except as provided in 

the following: 

§ 60.45b 

(i) An adjusted hourly sulfur dioxide 

emission rate (Eh0°) is used in Equation 

19-19 of Method 19 to compute an ad-

justed 30-day average emission rate 

(E.„°). The E

h0 i

s computed using the 

following formula: 

Eh.*- lE^-E^ 1-X

k)]/X* 

where: 

Eh," is the adjusted hourly sulfur dioxide 

emission rate, ng/J (lb/million Btu). 

E

ho i

s the hourly sulfur dioxide emission 

rate, ng/J (lb/million Btu). 

E. is the sulfur dioxide concentration in 

fuels other than coal and oil combusted 

in the affected facility, as determined by 

the fuel sampling and analysis proce-

dures in Method 19, ng/J (lb/million 

Btu). The value E. for each fuel lot is 

used for each hourly average during the 

time that the lot is being combusted. 

Xk is the fraction of total heat input from 

fuel combustion derived from coal, oil, 

or coal and oil, as determined by appli-

cable procedures in Method 19. 

(ii) To compute the percent of po-

tential sulfur dioxide emission rate (% 

P.), an adjusted % R, (% R,°) is com-

puted from the adjusted EM° from 

paragraph (b)(3)(i) of this section and 

an adjusted average sulfur dioxide 

inlet rate (En

0

) using the following for-

mula: % RV=10

0 (1.0-E.VEa

0

) 

To compute E^°, an adjusted hourly 

sulfur dioxide inlet rate (E

w

°) is used. 

The Em0 is computed using the follow-

ing formula: 

Et?-- [Eu-EwU -X»)]/X* 

where: 

Eh,° is the adjusted hourly sulfur dioxide 

inlet rate, ng/J (lb/mlllion Btu). 

Ehi is the hourly sulfur dioxide Inlet rate, 

ng/J (lb/mlllion Btu). 

(4) The owner or operator of an affected facility subject to paragraph 

(b)(3) of this section does not have to 

measure parameters E, or X

k i

f the 

owner or operator elects to assume 

that X

k=1.0

. Owners or operators of 

affected facilities who assume X

k=1.0 

shall 

(i) Determine % P, following the 

procedures in paragraph (c)(2) of this 

section, and 

(ii) Sulfur dioxide emissions (E.) are 

considered to be in compliance with 

sulfur dioxide emission limits under 

S 60.42b. 

285 
P.M 

§ 60.45b 

(5) The owner or operator of an affected facility that qualifies under the 

provisions of 5 60.42b(d) does not have 

to measure parameters E, or Xk under 

paragraph (b)(3) of this section if the 

owner or operator of the affected fa-

cility elects to measure sulfur dioxide 

emission rates of the coal or oil follow-

ing the fuel sampling and analysis pro-

cedures under Method 19. 

(d) Except as provided in paragraph 

(j), the owner or operator of an affect-

ed facility that combusts only very low 

sulfur oil, has an annual capacity 

factor for oil of 10 percent (0.10) or 

less, and is subject to a Federally en-

forceable requirement limiting oper-

ation of the affected facility to an 

annual capacity factor for oil of 10 

percent (0.10) or less shall: 

(1) Conduct the initial performance 

test over 24 consecutive steam generat-

ing unit operating hours at full load; 

(2) Determine compliance with the 

standards after the initial perform-

ance test based on the arithmetic aver-

age of the hourly emissions data 

during each steam generating unit op-

erating day if a continuous emission 

measurement system (CEMS) is used, 

or based on a daily average if Method 

6B or fuel sampling and analysis pro-

cedures under Method 19 are used. 

(e) The owner or operator of an affected facility subject to § 60.42b(d)(l) 

shall demonstrate the maximum 

design capacity of the steam generat-

ing unit by operating the facility at 

maximum capacity for 24 hours. This 

demonstration will be made during the 

initial performance test and a subse-

quent demonstration may be request-

ed at any other time. If the 24-hour 

average firing rate for the affected fa-

cility is less than the maximum design 

capacity provided by the manufactur-

er of the affected facility, the 24-hour 

average firing rate shall be used to de-

termine the capacity utilization rate 

for the affected facility, otherwise the 

maximum design capacity provided by 

the manufacturer is used. 

(f) For the initial performance test 

required under 9 60.8, compliance with 

the sulfur dioxide emission limits and 

percent reduction requirements under 

. 60.42b is based on the average emis-

sion rates and the average percent re-

duction for sulfur dioxide for the first 

40 CFR Ch. I (7-1-90 Edition) 

30 consecutive steam generating unit 

operating days, except as provided 

under paragraph (d) of this section. 

The initial performance test is the 

only test for which at least 30 days 

prior notice is required unless other-

wise specified by the Administrator. 

The initial performance test is to be 

scheduled so that the first steam gen-

erating unit operating day of the 30 

successive steam generating unit oper-

ating days is completed within 30 days 

after achieving the maximum produc-

tion rate at which the affected facility 

will be operated, but not later than 

180 days after initial startup of the fa-

cility. The boiler load during the 30-

day period does not have to be the 

maximum design load, but must be 

representative of future operating con-

ditions and include at least one 24-

hour period at full load. 

(g) After the initial performance test 

required under S 60.8. compliance with 

the sulfur dioxide emission limits and 

percent reduction requirements under 

S 60.42b is based on the average emis-

sion rates and the average percent re-

duction for sulfur dioxide for 30 suc-

cessive steam generating unit operat-

ing days, except as provided under 

paragraph (d). A separate perform-

ance test is completed at the end of 

each steam generating unit operating 

day after the initial performance test, 

and a new 30-day average emission 

rate and percent reduction for sulfur 

dioxide are calculated to show compli-

ance with the standard. 

(h) Except as provided under para-

graph (i) of this section, the owner or 

operator of an affected facility shall 

use all valid sulfur dioxide emissions ; 

data in calculating % P, and E*, under 1 

paragraph (c), of this section whether ^ 

or not the minimum emissions data re- i 

quirements under S 60.46b areil 

achieved. All valid emissions data, m-J! 

eluding valid sulfur dioxides emission f 

data collected during periods of start*! 

up, shutdown and malfunction, shattj 

be used in calculating % P. and E^ 

pursuant to paragraph (c) of this 

tion. 

(i) During periods of malfunction 

maintenance of the sulfur dioxide 

trol systems when oil is combusted 

provided under 5 60.42b(i), emissii 

data are not used to calculate % P. 

286 
f.W»

3 T^p? » P.15 

1 Environmenta

l Protection Agency 

E, under § 60.42b (a), (b) or (c), howev-

er, the emissions data are used to de-

termine compliance with the emission 

limit under § 60.42b(i). 

(j) The owner or operator of an affected facility that combusts very low 

sulfur oil is not subject to the compli-

ance and performance testing require-

ments of this section if the owner or 

operator obtains fuel receipts as de-

scribed in § 60.49b(r). 

[52 FR 47842, Dec. 16. 1987, as amended at 

54 FR 51820. 51825. Dec. 18, 1989] 

§ 60.46b Compliance and performance test 

methods and procedures for particulate 

matter and nitrogen oxides. 

(a) The particulate matter emission 

standards and opacity limits under 

§ 60.43b apply at all times except 

during periods of startup, shutdown, 

or malfunction. The nitrogen oxides 

emission standards under § 60.44b 

apply at all times. 

(b) Compliance with the particulate 

matter emission standards under 

§ 60.43b shall be determined through 

performance testing as described in 

paragraph (d) of this section. 

(c) Compliance with the nitrogen 

oxides emission standards under 

§ 60.44b shall be determined through 

performance testing under paragraph 

(e) or (f), or under paragraphs (g) and 

(h) of this section, as applicable. 

(d) To determine compliance with 

the particulate matter emission limits 

and opacity limits under § 60.43b, the 

owner or operator of an affected facili-

ty shall conduct an initial perform-

ance test as required under 5 60.8 

using the following procedures and 

reference methods: 

(1) Method 3B is used for gas analy-

sis when applying Method 5 or 

Method 17. 

(2) Method 5, Method 5B, or Method 

17 shall be used to measure the con-

centration of particulate matter as fol-

lows: 

(i) Method 5 shall be used at affect-

ed facilities without wet flue gas desul-

furization (FGD) systems; and 

(ii) Method 17 may be used at facili-

ties with or without wet scrubber sys-

tems provided the stack gas tempera-

ture does not exceed a temperature of 

180 *C (320 *F). The procedures of sec-

tions 2.1 and 2.3 of Method SB may be 

§ 60.46b 

used in Method 17 only if it is used 

after a wet FGD system. Do not use 

Method 17 after wet FGD systems if 

the effluent is saturated or laden with 

water droplets. 

(iii) Method 5B is to be used only 

after wet FGD systems. 

(3) Method 1 is used to select the 

sampling site and the number of tra-

verse sampling points. The sampling 

time for each run is at least 120 min-

utes and the minimum sampling 

volume is 1.7 dscm (60 dscf) except 

that smaller sampling times or vol-

umes may be approved by the Admin-

istrator when necessitated by process 

variables or other factors. 

(4) For Method 5, the temperature 

of the sample gas in the probe and 

filter holder is monitored and is main-

tained at 160 *C (320 'F). 

(5) For determination of particulate 

matter emissions, the oxygen or 

carbon dioxide sample is obtained si-

multaneously with each run of 

Method 5, Method 5B or Method 17 by 

traversing the duct at the same sam-

pling location. 

(6) For each run using Method 5, 

Method 5B or Method 17, the emission 

rate expressed in nanograms per joule 

heat input is determined using: 

(i) The oxygen or carbon dioxide 

measurements and particulate matter 

measurements obtained under this sec-

tion, 

(ii) The dry basis F factor, and 

(iii) The dry basis emission rate cal-

culation procedure contained in 

Method 19 (Appendix A). 

(7) Method 9 is used for determining 

the opacity of stack emissions. 

(e) To determine compliance with 

the emission limits for nitrogen oxides 

required under § 60.44b, the owner or 

operator of an affected facility shall 

conduct the performance test as re-

quired under § 60.8 using the continu-

ous system for monitoring nitrogen 

oxides under § 60.48(b). 

(1) For the initial compliance test, 

nitrogen oxides from the steam gener-

ating unit are monitored for 30 succes-

sive steam generating unit operating 

days and the 30-day average emission 

rate is used to determine compliance 

with the nitrogen oxides emission 

standards under § 60.44b. The 30-day 

average emission rate is calculated as 

287 
I 

P.16 

§ 60.46b 

the average of all hourly emissions 

data recorded by the monitoring 

system during the 30-day test period. 

(2) Following the date on which the 

initial performance test is completed 

or is required to be completed under 

§ 60.8 of this part, whichever date 

comes first: the owner or operator of 

an affected facility which combusts 

coal or which combusts residual oil 

having a nitrogen content greater 

than 0.30 weight percent shall determine compliance with the nitrogen 

oxides emission standards under 

§ 60.44b on a continuous basis through 

the use of a 30-day rolling average 

emission rate. A new 30-day rolling average emission rate is calculated each 

steam generating unit operating day 

as the average of all of the hourly nitrogen oxides emission data for the 

preceding 30 steam generating unit operating days. 

(3) Following the date on which the 

initial performance test is completed 

or is required to be completed under 

§60.8 of this part, whichever date 

comes first, the owner or operator of 

an affected facility which has a heat 

input capacity greater than 73 MW 

(250 million Btu/hour) and which 

combusts natural gas. distillate oil, or 

residual oil having a nitrogen content 

of 0.30 weight percent or less shall determine compliance with the nitrogen 

oxides standards under 5 60.44b on a 

continuous basis through the use of a 

30-day rolling average emission rate. A 

new 30-day rolling average emission 

rate is calculated each steam generating unit operating day as the average 

of all of the hourly nitrogen oxides 

emission data for the preceding 30 

steam generating unit operating days. 

(4) Following the date on which the 

initial performance test is completed 

or required to be completed under 

8 60.8 of this part, whichever date 

comes first, the owner or operator of 

an affected facility which has a heat 

input capacity of 73 MW (250 million 

Btu/hour) or less and which combusts 

natural gas, distillate oil, or residual 

oil having a nitrogen content of 0.30 

weight percent or less shall upon request determine compliance with the 

nitrogen oxides standards under 

§ 60.44b through the use of a 30-day 

performance test. During periods 

40 CFR Ch. I (7-1-90 Edition) 

when performance tests are not requested, nitrogen oxides emissions 

data collected pursuant to 

§ 60.48b(g)(l) or § 60.48b(g)(2) are used 

to calculate a 30-day rolling average 

emission rate on a daily basis and used 

to prepare excess emission reports, but 

will not be used to determine compliance with the nitrogen oxides emission 

standards. A new 30-day rolling average emission rate is calculated each 

steam generating unit operating day 

as the average of all of the hourly nitrogen oxides emission data for the 

preceding 30 steam generating unit operating days. 

(5) If the owner or operator of an affected facility which combusts residual 

oil does not sample and analyze the residual oil for nitrogen content, as specified in §60.49b(e), the requirements 

of paragraph (iii) of this section apply 

and the provisions of paragraph (iv) of 

this section are inapplicable. 

(f) To determine compliance with 

the emission limit for nitrogen oxides 

required by § 60.44b(a)(4) for duct 

burners used in combined cycle systems, the owner or operator of an affected facility shall conduct the performance test required under 5 60.8 . 

using the nitrogen oxides and oxygen! 

measurement procedures in 40 CFR? 

part 60 Appendix A, Method 2d.| 

During the performance test, one sampling site shall be located as close asi 

practicable to the exhaust of the tuf-| 

bine, as provided by section 6.1.1 o/i 

Method 20. A second sampling s$ $ 

shall be located at the outlet to 

steam generating unit. Measurement 

of nitrogen oxides and oxygen shaU jgjjj 

taken at both sampling sites di 

the performance test. The nitrogenj 

oxides emission rate from the cos 

bined cycle system shall be calculat 

by subtracting the nitrogen oxid 

emission rate measured at the 

pling site at the outlet from the 

bine from the nitrogen oxides emissiq 

rate measured at the sampling sitet 

the outlet from the steam gener 

unit. 

(g) The owner or operator of an 

fected facility described in 5 60.441 

or §60.44b(k) shall demonstrate 

maximum heat input capacity of 

steam generating unit by or, 

the facility at maximum capacity: ^ 

288 
P.17 

Environmental Protection Agency 

24 hours. The owner or operator of an 

affected facility shall determine the 

maximum heat input capacity using 

the heat loss method described in Sections 5 and 7.3 of the ASME Power 

Test Codes 4.1 (see IBR 5 60.17(h)). 

This demonstration of maximum heat 

input capacity shall be made during 

the initial performance test for affected facilities that meet the criteria of 

§ 60.44b(j). It shall be made 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 start-up of 

each facility, for affected facilities 

meeting the criteria of § 60.44b(k). 

Subsequent demonstrations may be required by the Administrator at any 

other time. If this demonstration indicates that the maximum heat input 

capacity of the affected facility is less 

than that stated by the manufacturer 

of the affected facility, the maximum 

heat input capacity determined during 

this demonstration shall be used to determine the capacity utilization rate 

for the affected facility. Otherwise, 

the maximum heat input capacity provided by the manufacturer is used. 

(h) The owner or operator of an affected facility described in § 60.44b(j) 

that has a heat input capacity greater 

than 73 MW (250 million Btu/hour) 

shall: 

(1) Conduct an initial performance 

test as required under § 60.8 over a 

minimum of 24 consecutive steam generating unit operating hours at maximum heat input capacity to demonstrate compliance with the nitrogen 

oxides emission standards under 

5 60.44b using Method 7, 7A. 7E, or 

other approved reference methods; 

and 

(2) Conduct subsequent performance 

tests once per calendar year or every 

400 hours of operation (whichever 

comes first) to demonstrate compliance with the nitrogen oxides emission 

standards under 5 60.44b over a minimum of 3 consecutive steam generating unit operating hours at maximum 

heat input capacity using Method 7, 

7A, 7E, or other approved reference 

methods. 

[52 FR 47842. Dec. 16, 1987, as amended at 

54 FR 51820. 51825. Dec. 18. 1989; 55 FR 

18876, May 7,1990] 

§ 60.47b 

§ 60.47b Emission monitoring for sulfur 

dioxide. 

(a) Except as provided in paragraphs 

(b) and (f) of this section, the owner or 

operator of an affected facility subject 

to the sulfur dioxide standards under 

§ 60.42b shall install, calibrate, maintain, and operate continuous emission 

monitoring systems (CEMS) for measuring sulfur dioxide concentrations 

and either oxygen (Oz) or carbon dioxide (C02) concentrations and shall 

record the output of the systems. The 

sulfur dioxide and either oxygen or 

carbon dioxide concentrations shall 

both be monitored at the inlet and 

outlet of the sulfur dioxide control 

device. 

(b) As an alternative to operating 

CEMS as required under paragraph 

(a) of this section, an owner or operator may elect to determine the average 

sulfur dioxide emissions and percent 

reduction by: 

(1) Collecting coal or oil samples in 

an as-fired condition at the inlet to 

the steam generating unit and analyzing them for sulfur and heat content 

according to Method 19. Method 19 

provides procedures for converting 

these measurements into the format 

to be used in calculating the average 

sulfur dioxide input rate, or 

(2) Measuring sulfur dioxide according to Method 6B at the inlet or outlet 

to the sulfur dioxide control system. 

An initial stratification test is required 

to verify the adequacy of the Method 

6B sampling location. The stratification test shall consist of three paired 

runs of a suitable sulfur dioxide and 

carbon dioxide measurement train operated at the candidate location and a 

second similar train operated according to the procedures in Section 3.2 

and the applicable procedures in Section 7 of Performance Specification 2. 

Method 6B, Method 6A, or a combination of Methods 6 and 3 or 3B or 

Methods 6C and 3A are suitable measurement techniques. If Method 6B is 

used for the second train, sampling 

time and timer operation may be adjusted for the stratification test as 

long as an adequate sample volume is 

collected; however, both sampling 

trains are to be operated similarly. For 

the location to be adequate for 

289 
P.18 

§ 60.48b 

Method 6B 24-hour tests, the mean of 

the absolute difference between the 

three paired runs must be less than 10 

percent. 

(3) A daily sulfur dioxide emission 

rate, ED, shall be determined using the 

procedure described in Method 6A, 

Section 7.6.2 (Equation 6A-8) and 

stated in ng/J (lb/million Btu) heat 

input. 

(4) The mean 30-day emission rate is 

calculated using the daily measured 

values in ng/J (lb/million Btu) for 30 

successive steam generating unit oper-

ating days using equation 19-20 of 

Method 19. 

(c) The owner or operator of an affected facility shall obtain emission 

data for at least 75 percent of the op-

erating hours in at least 22 out of 30 

successive boiler operating days. If 

this minirnnm data requirement is not 

met with a single monitoring system, 

the owner or operator of the affected 

facility shall supplement the emission 

data with data collected with other 

monitoring systems as approved by 

the Administrator or the reference 

methods and procedures as described 

in paragraph (b) of this section. 

(d) The 1-hour average sulfur diox-

ide emission rates measured by the 

CEMS required by paragraph (a) of 

this section and required under 

§ 60.13(h) is expressed in ng/J or lb/ 

million Btu heat input and is used to 

calculate the average emission rates 

under 5 60.42b. Each 1-hour average 

sulfur dioxide emission rate must be 

based on more than 30 minutes of 

steam generating unit operation and 

include at least 2 data points with 

each representing a 15-minute period. 

Hourly sulfur dioxide emission rates 

are not calculated if the affected facil-

ity is operated less than 30 minutes in 

a 1-hour period and are not counted 

toward determination of a steam gen-

erating unit operating day. 

(e) The procedures under § 60.13 

shall be followed for installation, eval-

uation, and operation of the CEMS. 

(1) All CEMS shall be operated in 

accordance with the applicable proce-

dures under Performance Specifica-

tions 1, 2, and 3 (Appendix B). 

(2) Quarterly accuracy determina-

tions and daily calibration drift tests 

40 CFR Ch. I (7-1-90 Edition) 

shall be performed in accordance with 

Procedure 1 (Appendix F). 

(3) For affected facilities combusting 

coal or oil, alone or in combination 

with other fuels, the span value of the 

sulfur dioxide CEMS at the inlet to 

the sulfur dioxide control device is 125 

percent of the maximum estimated 

hourly potential sulfur dioxide emis-

sions of the fuel combusted, and the 

span value of the CEMS at the outlet 

to the sulfur dioxide control device is 

50 percent of the maximum estimated 

hourly potential sulfur dioxide emis-

sions of the fuel combusted. 

(f) The owner or operator of an affected facility that combusts very low 

sulfur oil is not subject to the emission 

monitoring requirements of this sec-

tion if the owner or operator obtains 

fuel receipts as described in 

§ 60.49b(r). 

^ [52 FR 47842. Dec. 16. 1987, as amended at 

54 FR 51820, Dec. 18,1989; 55 FR 5212. Feb. 

14. 1990; 55 FR 18876. May 7, 1990] 

§ 60.48b Emission monitoring for particu-

late matter and nitrogen oxides. 

(a) The owner or operator of an affected facility subject to the opacity 

standard under 5 60.43b shall install, 

calibrate, maintain, and operate a con-, 

tinuous monitoring system for measur-

ing the opacity of emissions dis-

charged to the atmosphere and record 

the output of the system. 

(b) Except as provided under para-

graphs (g), (h), and (i) of this section, 

the owner or operator of an affected, 

facility subject to the nitrogen oxidesi 

standards under 5 60.44b shall install,; 

calibrate, maintain, and operate a con-, 

tinuous monitoring system for measur-' 

ing nitrogen oxides emissions dis-

charged to the atmosphere and record^ 

the output of the system. -/ 

(c) The continuous monitoring sys-.f 

terns required under paragraph (b) ol 

this section shall be operated and data^ 

recorded during all periods of operrt^ 

ation of the affected facility except^ 

for continuous monitoring system $ 

breakdowns and repairs. Data is re»if. 

corded during calibration checks, and^ 

zero and span adjustments. ^'ay>k 

(d) The 1-hour average nitroge 

oxides emission rates measured by 

continuous nitrogen oxides monitor i 

290 
P.19 

% 

Environmental Protection Agency 

quired by paragraph (b) of this section 

and required under 5 60.13(h) shall be 

expressed in ng/J or lb/million Btu 

heat input and shall be used to calcu-

late the average emission rates under 

5 60.44b. The 1-hour averages shall be 

calculated using the data points re-

quired under 5 60.13(b). At least 2 data 

points must be used to calculate each 

1-hour average. 

(e) The procedures under 5 60.13 

shall be followed for installation, eval-

uation, and operation of the continu-

ous monitoring systems. 

(1) For affected facilities combusting 

coal, wood or municipal-type solid 

waste, the span value for a continuous 

monitoring system for measuring 

opacity shall be between 60 and 80 

percent. 

(2) For affected facilities combusting 

coal, oil, or natural gas, the span value 

for nitrogen oxides is determined as 

follows: 

Oil 

Coal 

Mixtures 

Fuel 

Span values for 

nitrogen oxides 

(PPM) 

500 

SCO 

1,000 

500(x+y)+1.000z 

where: x is th

e fraction of total heat input derived 

from natural gas, 

y is the fraction of total heat input derived 

from oil, and 

z is the fraction of total heat input derived 

from coal. 

(3) All span values computed under 

paragraph (e)(2) of this section for 

combusting mixtures of regulated 

fuels are rounded to the nearest 500 

ppm. 

(f) When nitrogen oxides emission 

data are not obtained because of con-

tinuous monitoring system break-

downs, repairs, calibration checks and 

zero and span adjustments, emission 

data will be obtained by using standby 

monitoring systems, Method 7, 

Method 7A, or other approved refer-

ence methods to provide emission data 

for a minimimn of 75 percent of the op-

erating hours in each steam generat-

ing unit operating day, in at least 22 

out of 30 successive steam generating 

unit operating days. 

§ 60.49b 

(g) The owner or operator of an affected facility that has a heat input 

capacity of 73 MW (250 million Btu/ 

hour) or less, and which has an annual 

capacity factor for residual oil having 

a nitrogen content of 0.30 weight per-

cent or less, natural gas, distillate oil, 

or any mixture of these fuels, greater 

than 10 percent (0.10) shall: 

(1) Comply with the provisions of 

paragraphs (b), (c), (d), (e)(2), (e)(3), 

and (f) of this section, or 

(2) Monitor steam generating unit 

operating conditions and predict nitro-

gen oxides emission rates as specified 

in a plan submitted pursuant to 

§ 60.49b(c). 

(h) The owner or operator of an affected facility which is subject to the 

nitrogen oxides standards of 

5 60.44b(a)(4) is not required to install 

or operate a continuous monitoring 

system to measure nitrogen oxides 

emissions. 

(i) The owner or operator of an affected facUity described in 5 60.44b(j) or 5 60.44b(k) is not required to install or operate a continuous monitoring 

system for measuring nitrogen oxides 

emissions. 

(Approved by the Office of Management 

and Budget under control number 2060-

0072) 

[52 FR 47842, Dec. 16, 1987, as amended at 

54 FR 51825. Dec. 18. 1989] 

§ 60.49b Reporting and recordkeeping re-

quirements. 

(a) The owner or operator of each 

affected facility shall submit notifica-

tion of the date of initial startup, as 

provided by § 60.7. This notification 

shall include: 

(1) The design heat input capacity of 

the affected facility and identification 

of the fuels to be combusted in the affected facility, 

(2) If applicable, a copy of any Fed-

erally enforceable requirement that 

limits the annual capacity factor for 

any fuel or mixture of fuels under 

§§60.42b(d)(l). 60.43b(a)(2), (a)(3)(iil), 

(c)(2)(il), (d)(2)(ili), 60.44b(c). (d), (e), 

(i), (J), (k). 60.45b(d). (g). 60.46b(h), or 

60.48b(i), 

(3) The annual capacity factor at 

which the owner or operator antici-

pates operating the facility based on 

291 
P.20 

§ 60.49b 

all fuels fired and based on each individual fuel fired, and, 

(4) Notification that an emerging 

technology will be used for controlling 

emissions of sulfur dioxide. The Administrator will examine the description of the emerging technology and 

will determine whether the technology qualifies as an emerging technology. In making this determination, the 

Administrator may require the owner 

or operator of the affected facility to 

submit additional information concerning the control device. The affected facility is subject to the provisions 

of 5 60.42b(a) unless and until this determination is made by the Administrator. 

(b) The owner or operator of each 

affected facility subject to the sulfur 

dioxide, particulate matter, and/or nitrogen oxides emission limits under 

55 60.42b. 60.43b, and 60.44b shall 

submit to the Administrator the performance test data from the initial 

performance test and the performance 

evaluation of the CEMS using the applicable performance specifications in 

appendix B. The owner or operator of 

each affected facility described in 

5 60.44b(J) or 5 60.44b(k) shall submit 

to the Administrator the maximum 

heat input capacity data from the 

demonstration of the maximum heat 

input capacity of the affected facility. 

(c) The owner or operator of each affected facility subject to the nitrogen 

oxides standard of § 60.44b who seeks 

to demonstrate compliance with those 

standards through the monitoring of 

steam generating unit operating conditions under the provisions of 

5 60.48b(g)(2) shah submit to the Administrator for approval a plan that 

identifies the operating conditions to 

be monitored under 5 60.48b(g)(2) and 

the records to be maintained under 

5 60.49b(j). This plan shall be submitted to the Administrator for approval 

within 360 days of the initial startup 

of the affected facility. The plan shall: 

(1) Identify the specific operating 

conditions to be monitored and the relationship between these operating 

conditions and nitrogen oxides emission rates (i.e., ng/J or lbs/million Btu 

heat input). Steam generating unit operating conditions include, but are not 

limited to, the degree of staged com40 CFR Ch. I (7-1-90 Edition) 

bustion (i.e., the ratio of primary air 

to secondary and/or tertiary air) and 

the level of excess air (i.e., flue gas 

oxygen level); 

(2) Include the data and information 

that the owner or operator used to 

identify the relationship between nitrogen oxides emission rates and these 

operating conditions; 

(3) Identify how these operating 

conditions, including steam generating 

unit load, will be monitored under 

§ 60.48b(g) on an hourly basis by the 

owner or operator during the period of 

operation of the affected facility; the 

quality assurance procedures or practices that will be employed to ensure 

that the data generated by monitoring 

these operating conditions will be representative and accurate; and the type 

and format of the records of these operating conditions, including steam 

generating unit load, that will be 

maintained by the owner or operator 

under 5 60.49b(j). 

If the plan is approved, the owner or 

operator shall maintain records of predicted nitrogen oxide emission rates 

and the monitored operating conditions, including steam generating unit 

load, identified in the plan. 

(d) The owner or operator of an affected facility shall record and maintain records of the amounts of each 

fuel combusted during each day and 

calculate the annual capacity factor 

individually for coal, distillate oil, residual oil, natural gas. wood, and municipal-type solid waste for each calendar quarter. The annual capacity 

factor is determined on a 12-month 

rolling average basis with a new 

annual capacity factor calculated at 

the end of each calendar month. 

(e) For an affected facility that combusts residual oil and meets the criteria under 55 60.46b(e)(4), 60.44b(J), or 

(k). the owner or operator shall maintain records of the nitrogen content of 

the residual oil combusted in the affected facility and calculate the average fuel nitrogen content on a per calendar quarter basis. The nitrogen content shall be determined using ASTM 

Method D3431-80, Test Method for 

Trace Nitrogen in Liquid Petroleum ? 

Hydrocarbons (IBR-see 5 60.17), or.? 

fuel suppliers. If residual oil blends f 

292 

I 
P.21 

t 

•mmEnvironmenta

l Protection Agency 

are being combusted, fuel nitrogen 

specifications may be prorated based 

on the ratio of residual oils of differ-

ent nitrogen content in the fuel blend. 

(f) For facilities subject to the opaci-

ty standard under 5 60.43b, the owner 

or operator shall maintain records of 

opacity. 

(g) Except as provided under para-

graph (p) of this section, the owner or 

operator of an affected facility subject 

to the nitrogen oxides standards under 

5 60.44b shall maintain records of the 

following information for each steam 

generating unit operating day: 

(1) Calendar date. 

(2) The average hourly nitrogen 

oxides emission rates (expressed as 

NOj) (ng/J or lb/million Btu heat 

input) measured or predicted. 

(3) The 30-day average nitrogen 

oxides emission rates (ng/J or lb/mil-

lion Btu heat input) calculated at the 

end of each steam generating unit op-

erating day from the measured or pre-

dicted hourly nitrogen oxide emission 

rates for the preceding 30 steam gen-

erating unit operating days. 

(4) Identification of the steam gener-

ating unit operating days when the 

calculated 30-day average nitrogen 

oxides emission rates are in excess of 

the nitrogen oxides emissions stand-

ards under 5 60.44b, with the reasons 

for such excess emissions as well as a 

description of corrective actions taken. 

(5) Identification of the steam gener-

ating unit operating days for which 

pollutant data have not been obtained, 

including reasons for not obtaining 

sufficient data and a description of 

corrective actions taken. 

(6) Identification of the times when 

emission data have been excluded 

from the calculation of average emis-

sion rates and the reasons for exclud-

ing data. 

(7) Identification of "F" factor used 

for calculations, method of determina-

tion, and type of fuel combusted. 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the continuous monitoring 

system. 

(9) Description of any modifications 

to the continuous monitoring system 

that could affect the ability of the 

continuous monitoring system to 

§ 60.49b 

comply with Performance Specifica-

tion 2 or 3. 

(10) Results of daily CEMS drift 

tests and quarterly accuracy assess-

ments as required under Appendix F, 

Procedure 1. 

(h) The owner or operator of any affected facility in any category listed in 

paragraphs (h) (1) or (2) of this sec-

tion is required to submit excess emis-

sion reports for any calendar quarter 

during which there are excess emis-

sions from the affected facility. If 

there are no excess emissions during 

the calendar quarter, the owner or op-

erator shall submit a report semiannu-

ally stating that no excess emissions 

occurred during the semiannual re-

porting period. 

(1) Any affected facility subject to 

the opacity standards under 

5 60.43b(e) or to the operating parame-

ter monitoring requirements under 

5 60.13(0(1). 

(2) Any affected facility that is sub-

ject to the nitrogen oxides standard of 

5 60.44b, and that 

(i) Combusts natural gas, distillate 

oil, or residual oil with a nitrogen con-

tent of 0.3 weight percent or less, or 

(ii) Has a heat input capacity of 73 

MW (250 million Btu/hour) or less 

and is required to monitor nitrogen 

oxides emissions on a continuous basis 

under 5 60.48b(g)(l) or steam generat-

ing unit operating conditions under 

5 60.48b(g)(2). 

(3) For the purpose of 5 60.43b, 

excess emissions are defined as all 6-

minute periods during which the aver-

age opacity exceeds the opacity stand-

ards under 5 60.43b(f). 

(4) For purposes of 5 60.48b(g)(l), 

excess emissions are defined as any 

calculated 30-day rolling average nitro-

gen oxides emission rate, as deter-

mined under § 60.46b(e), which ex-

ceeds the applicable emission limits in 

5 60.44b. 

(i) The owner or operator of any affected facility subject to the continuous monitoring requirements for nitrogen oxides under 5 60.48(b) shall 

submit a quarterly report containing 

the information recorded under para-

graph (g) of this section. All quarterly 

reports shall be postmarked by the 

30th day following the end of each cal-

endar quarter. 

293 
P.22 

§ 60.49b 

(j) The owner or operator of any affected facility subject to the sulfur dioxide standards under 5 60.42b shall 

submit written reports to the Adminis-

trator for every calendar quarter. All 

quarterly reports shall be postmarked 

by the 30th day following the end of 

each calendar quarter. 

(k) For each affected facility subject 

to the compliance and performance 

testing requirements of § 60.45b and 

the reporting requirement in para-

graph (j) of this section, the following 

information shall be reported to the 

Administrator: 

(1) Calendar dates covered in the re-

porting period. 

(2) Each 30-day average sulfur diox-

ide emission rate (ng/J or lb/million 

Btu heat input) measured during the 

reporting period, ending with the last 

30-day period in the quarter; reasons 

for noncompliance with the emission 

standards; and a description of correc-

tive actions taken. 

(3) Each 30-day average percent re-

duction in sulfur dioxide emissions cal-

culated during the reporting period, 

ending with the last 30-day period in 

the quarter; reasons for noncompli-

ance with the emission standards; and 

a description of corrective actions 

taken. 

(4) Identification of the steam gener-

ating unit operating days that coal or 

oil was combusted and for which 

sulfur dioxide or diluent (oxygen or 

carbon dioxide) data have not been ob-

tained by an approved method for at 

least 75 percent of the operating hours 

in the steam generating unit operating 

day; justification for not obtaining 

sufficient data; and description of cor-

rective action taken. 

(5) Identification of the times when 

emissions data have been excluded 

from the calculation of average emis-

sion rates; justification for excluding 

data; and description of corrective 

action taken if data have been ex-

cluded for periods other than those 

during which coal or oil were not com-

busted in the steam generating unit. 

(6) Identification of "F" factor used 

for calculations, method of determina-

tion, and type of fuel combusted. 

(7) Identification of times when 

hourly averages have been obtained 

based on manual sampling methods. 

40 CFR Ch. I (7-1-90 Edition) 

(8) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS. 

(9) Description of any modifications 

to the CEMS that could affect the 

ability of the CEMS to comply with 

Performance Specification 2 or 3. 

(10) Results of daily CEMS drift 

tests and quarterly accuracy assess-

ments as required under Appendix F, 

Procedure 1. 

(11) The annual capacity factor of 

each fired as provided under para-

graph (d) of this section. 

(1) For each affected facility subject 

to the compliance and performance 

testing requirements of 5 60.45b(d) 

and the reporting requirements of 

paragraph (j) of this section, the fol-

lowing information shall be reported 

to the Administrator: 

(1) Calendar dates when the facility 

was in operation during the reporting 

period; 

(2) The 24-hour average sulfur diox-

ide emission rate measured for each 

steam generating unit operating day 

during the reporting period that coal 

or oil was combusted, ending in the 

last 24-hour period in the quarter, rea-

sons for noncompliance with the emis-

sion standards; and a description of 

corrective actions taken; 

(3) Identification of the steam gener-

ating unit operating days that coal or 

oil was combusted for which sulfur di-

oxide or diluent (oxygen or carbon di-

oxide) data have not been obtained by 

an approved method for at least 75 

percent of the operating hours; justifi-

cation for not obtaining sufficient 

data; and description of corrective 

action taken. 

(4) Identification of the times when 

emissions data have been excluded 

from the calculation of average emis-

sion rates; justification for excluding 

data; and description of corrective 

action taken if data have been ex-

cluded for periods other than those 

during which coal or oil were not com-

busted in the steam generating unit. 

(5) Identification of "F" factor used 

for calculations, method of determina-

tion, and type of fuel combusted. 

(6) Identification of times when 

hourly averages have been obtained f 

based on manual sampling methods.. -' f 

294 I 
Z&'f •*-%**, l

J

>i«t;.fSWe.} P.23 

Environmental Protection Agency 

(7) Identification of the times when 

the pollutant concentration exceeded 

full span of the CEMS. 

(8) Description of any modifications 

to the CEMS which could affect the 

ability of the CEMS to comply with 

Performance Specification 2 or 3. 

(9) Results of daily CEMS drift tests 

and quarterly accuracy assessments as 

required under Appendix F, Procedure 

1. 

(m) For each affected facility subject to the sulfur dioxide standards 

under 5 60.42b for which the minimum 

amount of data required under 

§ 60.47b(f) were not obtained during a 

calendar quarter, the following information is reported to the Administrator in addition to that required under 

paragraph (k) of this section: 

(1) The number of hourly averages 

available for outlet emission rates and 

inlet emission rates. 

(2) The standard deviation of hourly 

averages for outlet emission rates and 

inlet emission rates, as determined in 

Method 19. Section 7. 

(3) The lower confidence limit for 

the mean outlet emission rate and the 

upper confidence limit for the mean 

inlet emission rate, as calculated in 

Method 19, Section 7. 

(4) The ratio of the lower confidence 

limit for the mean outlet emission rate 

and the allowable emission rate, as determined in Method 19, Section 7. 

(n) If a percent removal efficiency 

by fuel pretreatment (i.e., % R,) is 

used to determine the overall percent 

reduction (i.e., % R.) under 5 60.45b, 

the owner or operator of the affected 

facility shall submit a signed statement with the quarterly report: 

(1) Indicating what removal efficiency by fuel pretreatment (i.e., % R,) was 

credited for the calendar quarter; 

(2) Listing the quantity, heat content, and date each pretreated fuel 

shipment was received during the previous calendar 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 calendar quarter; 

(3) Documenting the transport of 

the fuel from the fuel pretreatment 

facility to the steam generating unit. 

§ 60.49b 

(4) Including a signed statement 

from the owner or operator of the fuel 

pretreatment facility certifying that 

the percent removal efficiency 

achieved by fuel pretreatment was determined in accordance with the provisions of Method 19 (Appendix A) and 

listing the heat content and sulfur 

content of each fuel before and after 

fuel pretreatment. 

(0) All records required under this 

section shall be maintained by the 

owner or operator of the affected facility for a period of 2 years following 

the date of such record. 

(p) The owner or operator of an affected facUity described in 55 60.44b(j) 

or (k) shall maintain records of the 

following information for each steam 

generating unit operating day: 

(1) Calendar date, 

(2) The number of hours of operation, and 

(3) A record of the hourly steam 

load. 

(q) The owner or operator of an affected facility described in 5 60.44b(J) 

or S 60.44b(k) shall submit to the Administrator on a quarterly basis: 

(1) The annual capacity factor over 

the previous 12 months, 

(2) The average fuel nitrogen content during the quarter, lf residual oil 

was fired; and 

(3) If the affected facility meets the 

criteria described in 5 60.44b(j), the results of any nitrogen oxides emission 

tests required during the quarter, the 

hours of operation during the quarter, 

and the hours of operation since the 

last nitrogen oxides emission test. 

(r) The owner or operator of an affected facility who elects to demonstrate that the affected facility combusts only very low sulfur oil under 

5 60.42b(j)(2) shall obtain and maintain at the affected facility fuel receipts from the fuel supplier which 

certify that the oil meets the definition of distillate oil as defined in 

5 60.41b. For the purposes of this section, the oil need not meet the fuel nitrogen content specification in the definition of distillate oil. Quarterly reports shall be submitted to the Administrator certifying that only very low 

sulfur oil meeting this definition was 

combusted in the affected facility 

during the preceding quarter. 

295 
P.24 

§60.50 

(Approved by the Office of Management 

and Budget under control number 2060-

0135) 

[52 FR 47842, Dec. 16, 1987. as amended at 

54 FR 51820, 51825. Dec. 18, 1989] 

40 CFR Ch. I (7-1-90 Edition) 

§60.53. 

(al 

'Monitoring > 

'he 

tons. 

ier opei 

sha 

ane 

the 

y inproyjSions of 

gopei 

methods and/pVocedui 

/ conducting/the performance 

equirea in £60.8, the* owner or 

tor snail use as reference met 

rocedures thVtest metttods 

ndixjA of this part or•/Other 

procedures as sffecified 

ion, except as ppdvided in 

8(bL 

Le owngr or opeprftor shs 

compliance wtfh the 

Latter standaroyui 5 60.55 

deticufoltter. 

(gr/ 

(b) 

tei 

late/ 

lows: 

(1) Tile emission rate (dz/bf particulate ^matter, corrected to 12 percent 

CO/shall he computed for each run 

g the following equation: 

:

„ = c, (12/%CO>) 

where.* 

di concentration of particulate 

corrected to 12 percenrCOi. i 

dscf). . / 

c,=concentration of .particular' matter, g/ 

dscm (gr/dscf). 

%COt=COi concentration^ percent dry 

basis. / 

(2) Method 5 shall be usecKto determine the particulate matter concentration (c,). The sampling time and 

sample volume for eacbVrun shaH be at 

least 60 minutes and 0.85 dscm (30 

dscf). 

(3) The emission rate correction 

factor, integrated or grab sampling 

and analysis-procedure of Method 3B 

shall be used to determine. CO* concentrati0n (%CO»). 

(i) The CO» sample shall be obtained 

(taneousYy with, and at the same 

traverse points as, the particulate run, 

jf the particulate run has more than 

12 traverse points, the CC** traverse 

points may be reduced to 12 if Method 

1 is/used to*locate the 12 CO»'traverse 

points. If individual COa samples 

taken art each 

concentration1 

rection eqi 

tic mean/of 

sample concentrations: 

point. 

296 

I 

$i&