1 Subpart Dc—Standards of Performance for Sma ll Industrial-Commercial-Institutional Steam Generating Units §60.40c Applicability and delegation of authority. (a) Except as provided in paragraphs (d), (e), (f), a nd (g) of this section, the affected facility to which this subpart applies is each stea m generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British th ermal units per hour (MMBtu/ hr h )) or less, but greater than or equal to 2.9 MW (10 MMBtu/ hr h ). (b) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, §60.48c(a)(4) shall be retained by the Administrator and not transferred to a State. (c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are not subject to the sulfur dioxide (SO 2 ) or particulate matter (PM) emission limits, performance testing requirements, or monitoring requirements under this subpart (§§60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during periods of combustion research, as defined in §60.41c. (d) Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is not considered a modification under §60.14. (e) Heat Affected facilities (i.e. heat recovery steam generators and fuel heaters) that are associated with combined cycle gas stationary combustion turbines and meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators , fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/ hr h ) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/ hr h ) heat input of fossil fuel. If th e heat recovery steam generator , fuel heater, or other affected facility is subject to this subpart, only emissions re sulting from combustion of fuels in the steam generating unit are subject to this subpart. (The gas stationary combustion turbine emissions are subject to subpart GG or KKKK, as a pplicable, of this part). (f) Any affected facility covered by that meets the applicability requirements and is subject to subpart AAAA or subpart CCCC of this part is not subject by to this subpart. (g) Any facility covered by that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implemen ting subpart BBBB of this part is not subject by to this subpart. (h) Affected facilities that also meet the applicabilit y requirements under subpart J or subpart Ja of this part are subject to the PM and NO X standards under this subpart and the SO 2 standards under subpart J or subpart Ja of this part, as applicable. (i) Temporary boilers are not subject to this subpart.
§60.41c Definitions. As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air 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 an individual fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the case of steam generating units that are rented or leas ed, the actual heat input shall be determined based Comment [CF1]: Clarify broad definition to be consistent with broad definition of affected facility under KKKK

– fuel heater, etc.

Comment [CF2]: Exempt owner/operators of CISWI facilities from subpart Dc

Comment [CF3]: Similar exemption/rational as in Db to avoid double coverage.

Comment [CF4]: Exempt temporary boilers that burn fuels with lower emission rates2 on the combined heat input from all operations of the affected facility during a period of 12 consecutive calendar months.

Coal means all solid fuels classified as anthraci te, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see §60.17), coal refuse, and petroleum coke. Coal-derived synthetic fu els derived from coal for the purposes of creating useful heat, including but not limited to solvent refine d coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, and coal-water mixt ures, are also included in this definition for the purposes of this subpart. Coal refuse means any by-product of coal mining or coal cleaning operations with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 Btu per pound (Btu/lb) on a dry basis. Cogeneration steam generating unit means a steam generating unit that simultaneously produces both electrical (or mechanical) and thermal energy from the same primary energy source

. Combined cycle system means a system in which a separate source (such as a stationary gas turbine, internal combustion engine, or kiln) provide s exhaust gas to a steam generating unit.

Combustion research means the experimental firing of any fuel or combination of fuels in a steam generating unit for the purpose of conducting research and development of more efficient combustion or more effective prevention or control of air pollutant emissions from combustion, provided that, during these periods of research and development, the heat generated is not used fo r any purpose other than preheating combustion air for use by that steam generating unit ( i.e. , the heat generated is released to the atmosphere without being used for space heat ing, process heating, driving pumps, preheating combustion air for other units, generati ng electricity, or any other purpose). Conventional technology means wet flue gas desulfurization t echnology, dry flue gas desulfurization technology, atmospheric fluidized bed combustion te chnology, and oil hydrodesulfurization technology.

Distillate oil means fuel oil that complies with the specificat ions for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Material s in ASTM D396 (incorporated by reference, see §60.17 ) or ), diesel fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see §60.17 ). ), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see §60.17), biodiesel as defined by the American Society of Testing and Material s in ASTM D6751 (incorporated by reference, see §60.17), or biodiesel blends as defined by the Amer ican Society of Testing and Materials in ASTM D7467 (incorporated by reference, see §60.17). Dry flue gas desulfurization technology means a SO 2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by c ontacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed sl urry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas desulf urization systems include, but are not limited to, lime and sodium compounds.

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 steam generating unit. Comment [CF5]: Delete since not used in subpart Dc.

Comment [CF6]: Expand definitions to include other similar fuels.3 Emerging technology means any SO 2 control system that is not defi ned as a conventional technology under this section, and for which the owner or operat or of the affected facility has received approval from the Administrator to operate as an emerging technology under §60.48c(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 requirement s established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. Fluidized bed combustion technology means a device wherein fuel is dist ributed onto a bed (or series of beds) of limestone aggregate (or other sorbent materi als) for combustion; and th ese materials are forced upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology includes, but is not limite d to, bubbling bed units and circulating bed units. 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. Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirc ulated flue gases, or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns). Heat transfer medium means any material that is used to tran sfer heat from one point to another point. Maximum design heat input capacity means the ability of a steam generating unit to combust a stated maximum amount of fuel (or combination of fuels) on a steady state basis as de termined by the physical design and characteristics of the steam generating unit. Natural gas means: (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of wh ich the principal constituent is methane; or (2) Liquefied petroleum (LP) gas, as defined by th e American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see §60.17); or (3) A mixture of hydrocarbons that maintains a gase ous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot).

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 oil and residual oil. Potential sulfur dioxide emission rate means the theoretical SO 2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from com busting 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 reaction in which the material participates as a reactant or catalyst.

Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, and all fuel oil nu mbers 4, 5, and 6, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see §60.17).4 Steam generating unit means a device that combusts any fuel a nd produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as 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 ti me in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Temporary boiler means a steam generating unit that combusts natural gas or distillate oil with a potential SO 2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and is capable of, being carried or moved from one loca tion to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platform s. A steam generating unit is not a temporary boiler if any one of the following conditions exists:
(1) The equipment is attached to a foundation. (2) The steam generating unit or a replacement rema ins at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporar y boiler at a location and performs the same or similar function will be included in calculating the consecutive time period. (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year. (4) The equipment is moved from one location to anothe r in an attempt to circumvent the residence time requirements of this definition. Wet flue gas desulfurization technology means an SO 2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by cont acting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition includes devices where the liquid material is subsequently converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone, and sodium compounds. Wet scrubber system means any emission control device that mixe s an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO 2

. Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited to sawdust, sanderdust, wood chip s, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues. §60.42c Standard for sulfur dioxide (SO 2 ). (a) Except as provided in paragraphs (b), (c), and (e) of this section, on and after the date on which the performance test is completed or required to be comp leted under §60.8, whichever date comes first, the owner or operator of an affected facility that comb usts only coal shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is com busted with other fuels, th e affected facility shall neither: cause to be discharged into the atmosphere from the affected facility any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 10 percent (0.10) of the potential SO 2 emission rate (90 percent reduction), nor cause to be discharged into the atmosphere from the affected facility any Comment [CF7]: Need definition for exemption

– limited to fuels with lower emission rates5 gases that contain SO 2 in excess of the emission limit is determin ed pursuant to paragraph (e)(2) of this section. (b) Except as provided in paragraphs (c) and (e) of this section, on and after the date on which the performance test is completed or required to be comp leted under §60.8, whichever date comes first, the owner or operator of an affected facility that: (1) Combusts only coal refuse alone in a fluidized bed combustion steam generating unit shall neither: (i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 87 ng/J (0.20 lb/MMBtu) heat input or 20 percent (0.20) of the potential SO 2 emission rate (80 percent reduction); nor (ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of SO 2 in excess of 520 ng/J (1.2 lb/MMBtu) heat input. If coal is fired with coal refuse, the affected facility subject to paragraph (a) of this section. If oil or any other fuel (except coal) is fired with coal refuse, the affected facility is subject to the 87 ng/J (0.20 lb/MMBtu) heat input SO 2 emissions limit or the 90 percent SO 2 reduction requirement specified in paragr aph (a) of this section and the emission limit is determined pursuant to paragraph (e)(2) of this section. (2) Combusts only coal and that uses an emerging technology for the control of SO 2 emissions shall neither: (i) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 50 percent (0.50) of the potential SO 2 emission rate (50 percent reduction); nor (ii) Cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 260 ng/J (0.60 lb/MMBtu) heat input. If co al is combusted with ot her fuels, the affected facility is subject to the 50 percent SO 2 reduction requirement specified in this paragraph and the emission limit determined pursuant to paragraph (e)(2) of this section. (c) On and after the date on which the initial performa nce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, alone or in combination with any other fuel, and is lis ted in paragraphs (c)(1), (2), (3), or (4) of this section shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the emission limit determined pursuant to paragraph (e)(2) of this section. Percent reduction requirements are not applicable to affected facilities under paragraphs (c)(1), (2), (3), or (4). (1) Affected facilities that have a heat input capacity of 22 MW (75 MMBtu/ hr h ) or less

. ; (2) Affected facilities that have an annual capacity for coal of 55 percent (0.55) or less and are subject to a federally enforceable requirement limiting operati on of the affected facility to an annual capacity factor for coal of 55 percent (0.55) or less

. ; (3) Affected facilities located in a noncontinental area

. ; or (4) Affected facilities that combust coal in a duct burner as part of a combined cycle system where 30 percent (0.30) or less of the heat entering the st eam generating unit is from combustion of coal in the duct burner and 70 percent (0.70) or more of the heat entering the steam generating unit is from exhaust gases entering the duct burner. (d) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts oil shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of 215 ng/J (0.50 lb/MMBtu) heat input from oil ; or, as an alternative, no owner or operator of an Comment [CF8]: Clarify that cannot dilute with natural gas6 affected facility that combusts oil shall combust oil in the affected facility that contains greater than 0.5 weight percent sulfur. The percent reduction requirements are not applicable to affected facilities under this paragraph. (e) On and after the date on which the initial performa nce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that combusts coal, oil, or coal and oil with any other fuel shall cause to be discharged into the atmosphere from that affected facility any gases that contain SO 2 in excess of the following: (1) The percent of potential SO 2 emission rate or numerical SO 2 emission rate required under paragraph (a) or (b)(2) of this section, as appl icable, for any affected facility that (i) Combusts coal in combination with any other fuel; (ii) Has a heat input capacity greater than 22 MW (75 MMBtu/ hr h ); and (iii) Has an annual capacity factor for coal greater than 55 percent (0.55); and (2) The emission limit determined according to the following formula for any affected facility that combusts coal, oil, or coal and oil with any other fuel:

Where:

E s = SO 2 emission limit, expressed in ng/J or lb/MMBtu heat input;

K a = 520 ng/J (1.2 lb/MMBtu);

K b = 260 ng/J (0.60 lb/MMBtu);

K c = 215 ng/J (0.50 lb/MMBtu);

H a = Heat input from the combustion of coal, except coal combusted in an affected facility subject to paragraph (b)(2) of this section, in Joules (J) [MMBtu];

H b = Heat input from the combustion of coal in an affected facility subject to paragraph (b)(2) of this section, in J (MMBtu); and

H c = Heat input from the combustion of oil, in J (MMBtu). (f) Reduction in the potential SO 2 emission rate through fuel pretreatme nt is not credited toward the percent reduction requirement under para graph (b)(2) of this section unless: (1) Fuel pretreatment results in a 50 percent (0.50) or greater reduction in the potential SO 2 emission rate; and (2) Emissions from the pretreated fuel (without either combustion or post

- combustion SO 2 control) are equal to or less than the emission limits specified under paragraph (b)(2) of this sect ion. (f) [RESERVED] (g) Except as provided in paragraph (h) of this section, compliance with the percent reduction requirements, fuel oil sulfur limits, and emission limi ts of this section shall be determined on a 30-day rolling average basis. Comment [CF9]: Remove restriction of fuel pretreatement.7 (h) For affected facilities liste d under paragraphs (h)(1), (2), (3), or ( 3) 4) of this section, compliance with the emission limits or fuel oil sulfur limit s under this section may be determined based on a certification from the fuel supplier, as described under §60.48c(f), as applicable. (1) Distillate oil-fired affected facilities with heat input capacities between 2.9 and 29 MW (10 and 100 MMBtu/ hr h ). (2) Residual oil-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/ hr h ). (3) Coal-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/ hr h). (4) Other fuels-fired affected facilities with heat input capacities between 2.9 and 8.7 MW (10 and 30 MMBtu/h ). (i) The SO 2 emission limits, fuel oil sulfur limits, and pe rcent reduction requirements under this section apply at all times, including periods of startup, shutdown, and malfunction. (j) For affected facilities located in noncontinental areas and affected facilities complying with the percent reduction standard, only the heat input supplied to the affected facility from the combustion of coal and oil is counted under this section. No credit is provided for the heat input to the affected facility from wood or other fuels or for heat derived from e xhaust gases from other sources, such as stationary gas turbines, internal combustion engines, and kilns. §60.43c Standard for particulate matter (PM). (a) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts coal or combusts mixtures of coal with other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/ hr h ) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emission limits: (1) 22 ng/J (0.051 lb/MMBtu) heat input if the affect ed facility combusts only coal, or combusts coal with other fuels and has an annual capacity factor for the other fuels of 10 percent (0.10) or less. (2) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility combusts coal with other fuels, has an annual capacity factor for the other fuels greater than 10 percent (0.10), and is subject to a federally enforceable requirement limiting operation of the affect ed facility to an annual capacity factor greater than 10 percent (0.10) for fuels other than coal. (b) On and after the date on which the initial performance test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commenced construction, reconstruction, or modification on or before February 28, 2005, that combusts wood or combusts mixtures of wood with other fuels (except coal) and has a heat input capacity of 8.7 MW (30 MMBtu/ hr h ) or greater, shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of the following emissions limits: (1) 43 ng/J (0.10 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood greater than 30 percent (0.30); or (2) 130 ng/J (0.30 lb/MMBtu) heat input if the affected facility has an annual capacity factor for wood of 30 percent (0.30) or less and is subject to a federa lly enforceable requirement limiting operation of the affected facility to an annual capacity factor for wood of 30 percent (0.30) or less. Comment [CF10]: Add to be consistent with 60.48c(f)8 (c) On and after the date on which the initial performa nce test is completed or required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that can combust combusts coal, wood, or oil and has a heat input capacity of 8.7 MW (30 MMBtu/ hr h ) or greater shall cause to be discharged into the atmosphere from that affected facility 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. Owners and operators of an affected facility that elect to install, calibrate, maintain, and operate a continuous emissions monitoring system (CEMS) for measuring PM emissions according to the requirements of this subpart and are subject to a federally enforceable PM limit of 0.030 lb/MMBtu or less are exempt from the opacity st andard specified in this paragraph. (d) The PM and opacity standards under this section appl y at all times, except during periods of startup, shutdown, or malfunction. (e)(1) On and after the date on which the initial performance test is completed or is required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commences construction, reconstruction, or modifi cation after February 28, 2005, and that combusts coal, oil, wood, a mixture of these fuels, or a mixtur e of these fuels with any other fuels and has a heat input capacity of 8.7 MW (30 MMBtu/ hr h ) or greater shall cause to be discharged into the atmosphere from that affected facility any ga ses that contain PM in excess of 13 ng/J (0.030 lb/MMBtu) heat input, except as provided in paragraphs (e)(2), (e)(3), and (e)(4) of this section. (2) As an alternative to meeting the requirements of paragraph (e)(1) of this section, the owner or operator of an affected facility for which modification commenced after February 28, 2005, may elect to meet the requirements of this paragraph. On and after the date on which the initial performance test is completed or required to be completed under §60.8, wh ichever date comes first, no owner or operator of an affected facility that commenc es modification after February 28, 2005 shall cause to be discharged into the atmosphere from that affected facility any gases that contain PM in excess of both: (i) 22 ng/J (0.051 lb/MMBtu) heat input derived from the combustion of coal, oil, wood, a mixture of these fuels, or a mixture of these fuels with any other fuels; and (ii) 0.2 percent of the combustion concentration (99.8 percent reduction) when combusting coal, oil, wood, a mixture of these fuels, or a mixt ure of these fuels with any other fuels. (3) On and after the date on which the initial perform ance test is completed or is required to be completed under §60.8, whichever date comes first, no owner or operator of an affected facility that commences modification after February 28, 2005, and that combusts over 30 percent wood (by heat input) on an annual basis and has a heat input capacity of 8.7 MW (30 MMBtu/ hr h ) or greater shall cause to be discharged into the atmosphere from th at affected facility any gases that contain PM in excess of 43 ng/J (0.10 lb/MMBtu) heat input. (4) On and after the date on which the initial pe rformance test is completed or is required to be completed under §60.8, whichever date comes first, an (4) An owner or operator of an affected facility that commences construction, reconstruction, or modi fication after February 28, 2005, and that combusts only oil that contains no more than 0.50 weight percen t sulfur or a mixture of 0.50 weight percent sulfur oil with other fuels not subject to a PM sta ndard under §60.43c and not using a post-combustion technology (except a wet scr ubber) to reduce PM or SO 2 emissions is not subject to the PM limit in this section. §60.44c Compliance and performance test meth ods and procedures for sulfur dioxide. Comment [CF11]: Clarify opacity standard does

not apply when firing natural gas

Comment [CF12]: Introduction not necessary9 (a) Except as provided in paragraphs (g) and (h) of this section and §60.8(b), performance tests required under §60.8 shall be conducted following the procedures sp ecified in paragraphs (b), (c), (d), (e), and (f) of this section, as applicable. 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 Administrator. (b) The initial performance test required under §60. 8 shall be conducted over 30 consecutive operating days of the steam generating unit. Compliance with the percent reduction requirements and SO 2 emission limits under §60.42c shall be determined using a 30-d ay average. The first operating day included in the initial performance test shall be scheduled within 30 days after achieving the maximum production rate at which the affect facility will be operated, but not later than 180 da ys after the initial startup of the facility. The steam generating unit load during the 30-day period does not have to be the maximum design heat input capacity, but must be representative of future operating conditions. (c) After the initial performance test required under paragraph (b) of this section and §60.8, compliance with the percent reduction requirements and SO 2 emission limits under §60.42c is based on the average percent reduction and the average SO 2 emission rates for 30 consecutive steam generating unit operating days. A separate performance test is completed at the end of each steam generating unit operating day, and a new 30-day average percent reduction and SO 2 emission rate are calculated to show compliance with the standard. (d) If only coal, only oil, or a mixture of coal and oil is combusted in an affected facility, the procedures in Method 19 of appendix A of this part are used to determine the hourly SO 2 emission rate (E ho ) and the 30-day average SO 2 emission rate (E ao ). The hourly averages used to compute the 30-day averages are obtained from the CEMS. Method 19 of appendix A of this part shall be used to calculate E ao when using daily fuel sampling or Method 6B of appendix A of this part. (e) If coal, oil, or coal and oil are combusted with other fuels: (1) An adjusted E ho (E ho o) is used in Equation 19–19 of Method 19 of appendix A of this part to compute the adjusted E ao (E ao o). The E ho o is computed using the following formula:

Where:

E ho o = Adjusted E ho , ng/J (lb/MMBtu);

E ho = Hourly SO 2 emission rate, ng/J (lb/MMBtu);

E w = SO 2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 9 of appendix A of this part, ng/J (lb/MMBtu). The value E w for each fuel lot is used for each hourly average during the time that the lot is being combusted. The owner or operator does not have to measure E w if the owner or operator elects to assume E w = 0.

X k = Fraction of the total heat input from fuel combustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part. (2) The owner or operator of an affected facility that qualifies under the provisions of §60.42c(c) or (d) (where percent reduction is not required) does not have to measure the parameters E w or X k if the owner or operator of the affected facility elects to measure emission rates of the coal or oil using the fuel sampling and analysis procedures under Method 19 of appendix A of this part.10 (f) Affected facilities subject to the percent reduction requirements under §60.42c(a) or (b) shall determine compliance with the SO 2 emission limits under §60.42c pursuant to paragraphs (d) or (e) of this section, and shall determine compliance with the percent reduction requirements using the following procedures: (1) If only coal is combusted, the percent of potential SO 2 emission rate is computed using the following formula:

Where:

%P s = Potential SO 2 emission rate, in percent;

%R g = SO 2 removal efficiency of the control device as determined by Method 19 of appendix A of this part, in percent; and

%R f = SO 2 removal efficiency of fuel pretreatment as determined by Method 19 of appendix A of this part, in percent. (2) If coal, oil, or coal and oil are combusted with other fuels, the same procedures required in paragraph (f)(1) of this section are used, excep t as provided for in the following: (i) To compute the %P s , an adjusted %R g (%R g o) is computed from E ao o from paragraph (e)(1) of this section and an adjusted average SO 2 inlet rate (E ai o) using the following formula:

Where:

%R g o = Adjusted %R g , in percent;

E ao o = Adjusted E ao , ng/J (lb/MMBtu); and

E ai o = Adjusted average SO 2 inlet rate, ng/J (lb/MMBtu). (ii) To compute E ai o, an adjusted hourly SO 2 inlet rate (E hi o) is used. The E hi o is computed using the following formula:

Where:

E hi o = Adjusted E hi , ng/J (lb/MMBtu);

E hi = Hourly SO 2 inlet rate, ng/J (lb/MMBtu);

E w = SO 2 concentration in fuels other than coal and oil combusted in the affected facility, as determined by fuel sampling and analysis procedures in Method 19 of appendix A of this part, ng/J (lb/MMBtu). The value E w for each fuel lot is used for each hourly average during the time that the lot is being11 combusted. The owner or operator does not have to measure E w if the owner or operator elects to assume E w = 0; and

X k = Fraction of the total heat input from fuel com bustion derived from coal and oil, as determined by applicable procedures in Method 19 of appendix A of this part. (g) For oil-fired affected facilities where the owner or operator seeks to demonstrate compliance with the fuel oil sulfur limits under §60.42c based on ship ment fuel sampling, the initial performance test shall consist of sampling and analyzing the oil in the initial tank of oil to be fired in the steam generating unit to demonstrate that the oil contains 0.5 weight percent sulfur or less. Thereafter, the owner or operator of the affected facility shall sample the oil in the fuel tank after each new shipment of oil is received, as described under §60.46c(d)(2). (h) For affected facilities subject to §60.42c(h)(1), (2), or (3) where the owner or operator seeks to demonstrate compliance with the SO 2 standards based on fuel supplier certification, the performance test shall consist of the certification from the fuel su pplier, as described in §60.48c(f), as applicable. (i) The owner or operator of an affected facili ty seeking to demonstrate compliance with the SO 2 standards under §60.42c(c)(2) shall demonstrate th e maximum design heat input capacity of the steam generating unit by operating the steam genera ting unit at this capacity for 24 hours. This demonstration shall be made during the initial perfor mance test, and a subsequent demonstration may be requested at any other time. If the demonstrated 24- hour average firing rate for the affected facility is less than the maximum design heat input capacity stat ed by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used. (j) The owner or operator of an affected facility shall use all valid SO 2 emissions data in calculating %P s and E ho under paragraphs (d), (e), or (f) of this sectio n, as applicable, whether or not the minimum emissions data requirements under §60.46c(f) are achi eved. All valid emissions data, including valid data collected during periods of startup, shutdown, and malfunction, shall be used in calculating %P s or E ho pursuant to paragraphs (d), (e), or (f) of this section, as applicable. §60.45c Compliance and performance test methods and procedures for particulate matter. (a) The owner or operator of an affected facility subject to the PM and/or opacity standards under §60.43c shall conduct an initial performance test as required under §60.8, and shall conduct subsequent performance tests as requested by the Administrator, to determine compliance with the standards using the following procedures and reference methods, except as specified in paragraph (c) of this section. (1) Method 1 of appendix A of this part shall be us ed to select the sampling site and the number of traverse sampling points. (2) Method 3A or 3B of appendix A–2 of this part shall be used for gas anal ysis when applying Method 5 or 5B of appendix A–3 of this part or 17 of appendix A–6 of this part. (3) Method 5, 5B, or 17 of appendix A of this part sh all be used to measure the concentration of PM as follows: (i) Method 5 of appendix A of this part may be used only at affected facilities without wet scrubber systems. (ii) Method 17 of appendix A of this part may be used at affected facilities with or without wet scrubber systems provided the stack gas temperature does not exceed a temperature of 160 °C (320 °F). The12 procedures of Sections 8.1 and 11.1 of Method 5B of appendix A of this part may be used in Method 17 of appendix A of this part only if Method 17 of appendix A of this part is used in conjunction with a wet scrubber system. Method 17 of appendix A of this part shall not be used in conjunction with a wet scrubber system if the effluent is saturated or laden with water droplets. (iii) Method 5B of appendix A of this part may be used in conjunction with a wet scrubber system. (4) The sampling time for each run shall be at least 120 minutes and the minimum sampling volume shall be 1.7 dry standard cubic meters (dscm) [60 dr y standard cubic feet (dscf)] except that smaller sampling times or volumes may be approved by the Administrator when necessitated by process variables or other factors. (5) For Method 5 or 5B of appendix A of this part, the temperature of the sample gas in the probe and filter holder shall be monitored and maintained at 160 ±14 °C (320±25 °F). (6) For determination of PM emissions, an oxygen (O 2 ) or carbon dioxide (CO 2 ) measurement shall be obtained simultaneously with each run of Method 5, 5B, or 17 of appendix A of this part by traversing the duct at the same sampling location. (7) For each run using Method 5, 5B, or 17 of appendi x A of this part, the emission rates expressed in ng/J (lb/MMBtu) heat input shall be determined using: (i) The O 2 or CO 2 measurements and PM measurements obtained under this section, (ii) The dry basis F factor, and (iii) The dry basis emission rate calculation proce dure contained in Method 19 of appendix A of this part. (8) Method 9 of appendix A–4 of this part shall be us ed for determining the opacity of stack emissions. (b) The owner or operator of an affected facility seeking to demonstrate compliance with the PM standards under §60.43c(b)(2) shall demonstrate the ma ximum design heat input capacity of the steam generating unit by operating the steam generating unit at this capacity for 24 hours. This demonstration shall be made during the initial performance test, a nd a subsequent demonstrat ion may be requested at any other time. If the demonstrated 24-hour average firing rate for the affected facility is less than the maximum design heat input capacity stated by the manufacturer of the affected facility, the demonstrated 24-hour average firing rate shall be used to determine the annual capacity factor for the affected facility; otherwise, the maximum design heat input capacity provided by the manufacturer shall be used. (c) In place of PM testing with Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part, an owner or operator may elect to install, calibrate, maintain, and operate a CEMS for monitoring PM emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facility who elects to continuously monitor PM emissions instead of conducting performance testing using Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall install, calibrate, maintain, and operate a CEMS and shall comply with the requirements specified in paragraphs (c)(1) through (c)(14) of this section. (1) Notify the Administrator 1 month before starting use of the system. (2) Notify the Administrator 1 month before stopping use of the system. (3) The monitor shall be installed, evaluated, a nd operated in accordance with §60.13 of subpart A of this part.13 (4) The initial performance evaluation shall be completed no later than 180 days after the date of initial startup of the affected facility, as specified under §60.8 of subpart A of this part or within 180 days of notification to the Administrator of use of CEMS if the owner or operator was previously determining compliance by Method 5, 5B, or 17 of appendix A of th is part performance tests, whichever is later. (5) The owner or operator of an affected facility shall conduct an initial performance test for PM emissions as required under §60.8 of subpart A of this part. Compliance with the PM emission limit shall be determined by using the CEMS specified in paragraph (d) of this section to measure PM and calculating a 24-hour block arithmetic average emi ssion concentration using EPA Reference Method 19 of appendix A of this part, section 4.1. (6) Compliance with the PM emission limit shall be determined based on the 24-hour daily (block) average of the hourly arithmetic average emission concentrations using CEMS outlet data. (7) At a minimum, valid CEMS hourly averages shall be obtained as specified in paragraph (c)(7)(i) of this section for 75 percent of the total operating hours per 30-day rolling average. (i) At least two data points per hour shall be us ed to calculate each 1-hour arithmetic average. (ii) [Reserved] (8) The 1-hour arithmetic averages required under para graph (c)(7) of this section shall be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the boiler opera ting day daily arithmetic average emission concentrations. The 1-hour arithmetic averages shall be calculated using the data points required under §60.13(e)(2) of subpart A of this part. (9) All valid CEMS data shall be used in calculating average emission concentrations even if the minimum CEMS data requirements of paragraph (c)(7) of this section are not met. (10) The CEMS shall be operated according to Perfor mance Specification 11 in appendix B of this part. (11) During the correlation testing runs of the CEMS required by Performance Specification 11 in appendix B of this part, PM and O 2 (or CO 2 ) data shall be collected concurrently (or within a 30- to 60- minute period) by both the continuous emission m onitors and performance tests conducted using the following test methods. (i) For PM, Method 5 or 5B of appendix A–3 of this part or Method 17 of appendix A–6 of this part shall be used; and (ii) For O2 (or CO 2 ), Method 3A or 3B of appendix A–2 of this part, as applicable shall be used. (12) Quarterly accuracy determinatio ns and daily calibration drift tests shall be performed in accordance with procedure 2 in appendix F of this part. Relativ e Response Audit's must be performed annually and Response Correlation Audits must be performed every 3 years. (13) When PM emissions data are not obtained be cause of CEMS breakdowns, repairs, calibration checks, and zero and span adjustments, emission s data shall be obtained by using other monitoring systems as approved by the Administrator or EPA Reference Method 19 of appendix A of this part to provide, as necessary, valid emissions data for a minimum of 75 percent of total operating hours on a 30-day rolling average. (14) After July 1, 2011, within 9 0 days after the date of completing each performance evaluation required by paragraph (c)(11) of this section, the owner or operator of the affected facility must either submit the test data to EPA by successfully entering the data electronically into EPA's WebFIRE data base avai lable at http://cfpub.epa.gov/oarweb/ index.cfm?action=fire.main or mail a copy to: United14 States Environmental Protection Agency; Energy St rategies Group; 109 TW Alexander DR; Mail Code: D243

– 01; RTP, NC 27711

. (14) As of January 1, 2012 and within 90 days afte r the date of completing each performance test, as defined in §60.8, conducted to demonstrate complian ce with this subpart, you must submit relative accuracy test audit (i.e., reference method) data and performance test (i.e., compliance test) data, except opacity data, electronically to EPA’s Central Data Exchange (CDX) by using the Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/e rt tool.html/) or other compatible electronic spreadsheet. Only data collected using test me thods compatible with ERT are subject to this requirement to be submitted electroni cally into EPA’s WebFIRE database. (d) The owner or operator of an affected facility seeking to demonstrate compliance under §60.43c(e)(4) shall follow the applicable procedures under §60.48c(f). For residual oil-fired affected facilities, fuel supplier certifications are only allowed for facilities with heat input capacities between 2.9 and 8.7 MW (10 to 30 MMBtu/ hr h ). §60.46c Emission monitoring for sulfur dioxide. (a) Except as provided in paragraphs (d) and (e) of this section, the owner or operator of an affected facility subject to the SO 2 emission limits under §60.42c shall insta ll, calibrate, maintain, and operate a CEMS for measuring SO 2 concentrations and either O 2 or CO 2 concentrations at the outlet of the SO 2 control device (or the outlet of the steam generating unit if no SO 2 control device is used), and shall record the output of the system. The owner or operat or of an affected facility subject to the percent reduction requirements under §60.42c shall measure SO 2 concentrations and either O 2 or CO 2 concentrations at both the inlet and outlet of the SO 2 control device. (b) The 1-hour average SO 2 emission rates measured by a CEMS shal l be expressed in ng/J or lb/MMBtu heat input and shall be used to calculate the aver age emission rates under §60.42c. Each 1-hour average SO 2 emission rate must be based on at least 30 minutes of operation, and shall be calculated using the data points required under §60.13(h)(2). Hourly SO 2 emission rates are not calculated if the affected facility is operated less than 30 minutes in a 1-hour period and are not counted toward determination of a steam generating unit operating day. (c) The procedures under §60.13 shall be followed fo r installation, evaluation, and operation of the CEMS. (1) All CEMS shall be operated in accordance w ith the applicable proc edures under Performance Specifications 1, 2, and 3 of appendix B of this part. (2) Quarterly accuracy determinations and daily calibration drift tests shall be performed in accordance with Procedure 1 of appendix F of this part. (3) For affected facilities subject to the percent reduction requirements under §60.42c, the span value of the SO 2 CEMS at the inlet to the SO 2 control device shall be 125 perc ent of the maximum estimated hourly potential SO 2 emission rate of the fuel combusted, and the span value of the SO 2 CEMS at the outlet from the SO 2 control device shall be 50 percent of the maximum estimated hourly potential SO 2 emission rate of the fuel combusted. (4) For affected facilities that are not subject to the percent reduction requirements of §60.42c, the span value of the SO 2 CEMS at the outlet from the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) shall be 125 percen t of the maximum estimated hourly potential SO 2 emission rate of the fuel combusted. Comment [CF13]: Updated language for electronic reporting.15 (d) As an alternative to operating a CEMS at the inlet to the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 emission rate by sampling the fuel prior to combustion. As an alternative to operating a CEMS at the outlet from the SO 2 control device (or outlet of the steam generating unit if no SO 2 control device is used) as required under paragraph (a) of this section, an owner or operator may elect to determine the average SO 2 emission rate by using Method 6B of appendix A of this part. Fuel sampling shall be conducted pursuant to either paragraph (d)(1) or (d)(2) of this section. Method 6B of appendix A of this part shall be conducted pursuant to paragraph (d)(3) of this section. (1) For affected facilities combusting coal or oil, coal or oil samples shall be collected daily in an asfired condition at the inlet to the steam generating un it and analyzed for sulfur content and heat content according the Method 19 of appendix A of this part . Method 19 of appendix A of this part provides procedures for converting these measurements into th e format to be used in calculating the average SO 2 input rate. (2) As an alternative fuel sampling procedure for affected facilities combusting oil, oil samples may be collected from the fuel tank for each steam generating unit immediately after the fuel tank is filled and before any oil is combusted. The owner or operator of the affected facility shall analyze the oil sample to determine the sulfur content of the oil. If a partially empty fuel tank is refilled, a new sample and analysis of the fuel in the tank would be required upo n filling. Results of the fuel analysis taken after each new shipment of oil is receive d shall be used as the daily value when calculating the 30-day rolling average until the next shipment is received. If the fuel analysis shows that the sulfur content in the fuel tank is greater than 0.5 weight percent sulfur, the owne r or operator shall ensure that the sulfur content of subsequent oil shipments is low enough to cause the 30-day rolling average sulfur content to be 0.5 weight percent sulfur or less. (3) Method 6B of appendix A of this part may be used in lieu of CEMS to measure SO 2 at the inlet or outlet of the SO 2 control system. An initial stratification test is required to verify the adequacy of the Method 6B of appendix A of this part sampling locati on. The stratification test shall consist of three paired runs of a suitable SO 2 and CO 2 measurement train operated at th e candidate location and a second similar train operated according to the procedures in §3.2 and the applicable procedures in section 7 of Performance Specification 2 of appendix B of this part . Method 6B of appendix A of this part, Method 6A of appendix A of this part, or a combination of Methods 6 and 3 of appendix A of this part or Methods 6C and 3A of appendix A of this part are suitable measurement techniques. If Method 6B of appendix A of this part is used for the second trai n, sampling time and timer operation may be adjusted for the stratification test as long as an adequate sample volume is collect ed; however, both sampling trains are to be operated similarly. For the location to be adequate for Method 6B of appendix A of this part 24-hour tests, the mean of the absolute difference between the three paired runs must be less than 10 percent (0.10). (e) The monitoring requirements of paragraphs (a) and (d) of this section shall not apply to affected facilities subject to §60.42c(h) (1), (2), or (3) where the owner or operator of the affected facility seeks to demonstrate compliance with the SO 2 standards based on fuel supplier ce rtification, as described under §60.48c(f), as applicable. (f) The owner or operator of an affected facility operating a CEMS pursuant to paragraph (a) of this section, or conducting as-fired fuel sampling pursuant to paragraph (d)(1) of this section, shall obtain emission data for at least 75 percent of the operati ng hours in at least 22 out of 30 successive steam generating unit operating days. If th is minimum data requirement is not met with a single monitoring16 system, the owner or operator of the affected faci lity shall supplement the emission data with data collected with other monitoring systems as approved by the Administrator. §60.47c Emission monitoring for particulate matter. (a) Except as provided in paragraphs (c), (d), (e), and (f), and (g) of this section, the owner or operator of an affected facility combusting coal, oil, or wood th at is subject to the opacity standards under §60.43c shall install, calibrate, maintain, and operate a continuous opacity monitoring system (COMS) for measuring the opacity of the emissions discharged to the atmosphere and record the output of the system. The owner or operator of an affected facili ty subject to an opacity standard in §60.43c(c) and that is not required to install a COMS due to paragraphs (c ), (d), (e), or (f), of this section that elects not to use a COMS shall conduct a performance test usi ng Method 9 of appendix A–4 of this part and the procedures in §60.11 to demonstrate compliance with the applicable limit in §60.43c by April 29, 2011, within 45 days of stopping use of an existing COMS, or within 180 days after initial startup of the facility, whichever is later, and shall comply with e ither paragraphs (a)(1), (a)(2), or (a)(3) of this section. The observation period for Method 9 of appe ndix A-4 of this part performance tests may be reduced from 3 hours to 60 minutes if all 6-minute averages are less than 10 percent and all individual 15-second observations are less than or equal to 20 percent during the initial 60 minutes of observation. (1) Except as provided in paragraph (a)(2) and (a)(3) of this section, the owner or operator shall conduct subsequent Method 9 of appendix A–4 of this part pe rformance tests using the procedures in paragraph (a) of this section according to th e applicable schedule in paragraphs (a)(1)(i) through (a)(1)(iv) of this section, as determined by the most recent Method 9 of appendix A–4 of this part performance test results. (i) If no visible emissions are obs erved, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 12 cale ndar months from the date that the most recent performance test was conducted or within 45 days of the next day th at fuel with an opacity standard is combusted, whichever is later ; (ii) If visible emissions are observed but the maximum 6-minute average opacity is less than or equal to 5 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 6 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opaci ty standard is combusted, whichever is later ; (iii) If the maximum 6-minute average opacity is greater than 5 percent but less than or equal to 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 3 calendar months from the date that the most recent performance test was conducted or within 45 days of the next day that fuel with an opacity standard is combusted, whichever is later ; or (iv) If the maximum 6-minute average opacity is gr eater than 10 percent, a subsequent Method 9 of appendix A–4 of this part performance test must be completed within 45 calendar days from the date that the most recent performance test was conducted. (2) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 of this part performance tests, elect to perform subsequent monitoring using Method 22 of appendix A–7 of this part according to the procedures specified in paragraphs (a)(2)(i) and (ii) of this section. (i) The owner or operator shall conduct 10 minute observations (during normal operation) each operating day the affected facility fires fuel for which an opacity standard is applicable using Method 22 Comment [CF14]: Allow flexibility to account for intermittent use of fuels with an opacity standard.17 of appendix A–7 of this part and demonstrate that th e sum of the occurrences of any visible emissions is not in excess of 5 percent of the observation period ( i.e , 30 seconds per 10 minute period). If the sum of the occurrence of any visible emissions is greater than 30 seconds during the initial 10 minute observation, immediately conduct a 30 minute observation. If the sum of the occurrence of visible emissions is greater than 5 percent of the observation period ( i.e. , 90 seconds per 30 minute period) the owner or operator shall either document and adjust the operation of the facility and demonstrate within 24 hours that the sum of the occurrence of visible emis sions is equal to or less than 5 percent during a 30 minute observation ( i.e. , 90 seconds) or conduct a new Method 9 of appendix A–4 of this part performance test using the procedures in paragraph (a) of this section within 45 calendar days according to the requirements in §60.45c(a)(8). (ii) If no visible emi ssions are observed for 30 10 operating days during which an opacity standard is applicable, observations can be reduced to once ever y 7 operating days during which an opacity standard is applicable. If any visible emissions are obs erved, daily observations shall be resumed. (3) If the maximum 6-minute opacity is less than 10 percent during the most recent Method 9 of appendix A–4 of this part performance test, the owner or operator may, as an alternative to performing subsequent Method 9 of appendix A–4 performance test s, elect to perform subsequent monitoring using a digital opacity compliance system according to a site-specific monitoring plan approved by the Administrator. The observations shal l be similar, but not necessarily identical, to the requirements in paragraph (a)(2) of this section. For reference purposes in preparing the monitoring plan, see OAQPS “Determination of Visible Emission Opacity fro m Stationary Sources Using Computer-Based Photographic Analysis Systems.” This document is available from the U.S. Environmental Protection Agency (U.S. EPA); Office of Air Quality and Pl anning Standards; Sector Policies and Programs Division; Measurement Policy Group (D243–02), Research Triangle Park, NC 27711. This document is also available on the Technology Transfer Netw ork (TTN) under Emission Measurement Center Preliminary Methods. (b) All COMS shall be operated in accordance with the applicable procedures under Performance Specification 1 of appendix B of this part. The span value of the opacity COMS shall be between 60 and 80 percent. (c) Owners and operators of an affected facilities that burn only distillate oil that contains no more than 0.5 weight percent sulfur and/or liquid or gaseous fu els with potential sulfur dioxide emission rates of 26 ng/J (0.060 lb/MMBtu) heat input or less and th at do not use a post-combustion technology to reduce SO2 or PM emissions and that are subject to an opacity standard in §60.43c(c) are not required to operate a COMS if they follow the applicable procedures in §60.48c(f). (d) Owners or operators complying with the PM emission limit by using a PM CEMS must calibrate, maintain, operate, and record the output of the system for PM emissions discharged to the atmosphere as specified in §60.45c(c). The CEMS specified in paragraph §60.45c(c) sha ll be operated and data recorded during all periods of operation of the affected facility except for CEMS breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments. (e) Owners and operators of an affected facility that is subject to an opacity standard in §60.43c(c) and that does not use post-combustion technology (except a wet scrubber) for reducing PM, SO 2 , or carbon monoxide (CO) emissions, burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur, and is operated such that emi ssions of CO discharged to the atmosphere from the affected facility are maintained at levels less than or equal to 0.15 lb/MMBtu on a boiler operating day average basis is not required to operate a COMS. Owners and operators of affected facilities electing to Comment [CF15]: Decrease required number of days without visible emissions to reduce burden to regulated community18 comply with this paragraph must demonstrate comp liance according to the procedures specified in paragraphs (e)(1) through (4) of this section; or (1) You must monitor CO emissions using a CEMS according to the procedures specified in paragraphs (e)(1)(i) through (iv) of this section. (i) The CO CEMS must be installed, certified, main tained, and operated according to the provisions in §60.58b(i)(3) of subpart Eb of this part. (ii) Each 1-hour CO emissions average is calculate d using the data points generated by the CO CEMS expressed in parts per million by volume corrected to 3 percent oxygen (dry basis). (iii) At a minimum, valid 1-hour CO emissions averages must be obtained for at least 90 percent of the operating hours on a 30-day rolling average basis. The 1-hour averages are calculated using the data points required in §60.13(h)(2). (iv) Quarterly accuracy determinations and daily calibration drift tests for the CO CEMS must be performed in accordance with procedure 1 in appendix F of this part. (2) You must calculate the 1-hour average CO emissions levels for each steam generating unit operating day by multiplying the average hourly CO output co ncentration measured by the CO CEMS times the corresponding average hourly flue gas flow rate and divided by the corresponding average hourly heat input to the affected source. The 24-hour average CO emission level is determined by calculating the arithmetic average of the hourly CO emission levels computed for each steam generating unit operating day. (3) You must evaluate the preceding 24-hour aver age CO emission level each steam generating unit operating day excluding periods of affected source st artup, shutdown, or malfunction. If the 24-hour average CO emission level is greater than 0.15 lb/MMBtu, you must initiate investigation of the relevant equipment and control systems within 24 hours of the first discovery of the high emission incident and, take the appropriate corrective acti on as soon as practicable to adju st control settings or repair equipment to reduce the 24-hour average CO emission level to 0.15 lb/MMBtu or less. (4) You must record the CO measurements and calculat ions performed according to paragraph (e) of this section and any corrective actions taken. The record of corrective action taken must include the date and time during which the 24-hour average CO emission level was greater than 0.15 lb/MMBtu, and the date, time, and description of the corrective action. (f) Owners and operators of an a ffected facility that is subject to an opacity standard in §60.43c(c) and that uses a bag leak detection system to monitor the performance of a fabric filter (baghouse) according to the most recent requirements in section §60.48Da of this part is not required to operate a COMS. (g) Owners and operators of an affected facility that is subject to an opacity standard in §60. 43c(c) and that burns only gaseous fuels or fuel oils that contain less than or equal to 0.5 weight percent sulfur and operates according to a written site

- specific monitoring plan approv ed by the permitting authority is not required to operate a COMS. This monitoring plan must include procedures and criteria for establishing and monitoring specific parameters for the affec ted facility indicative of compliance with the opacity standard. (f) An owner or operator of an affected facility that is subject to an opacity standard in under §60.43c(c) is not required to operate a COMS provided that the affected facility meets the conditions in either paragraphs (f)(1), (2), or (3) of this section.19 (1) The affected facility uses a fabric filter (baghouse) as the primary PM control device and, the owner or operator operates a bag leak detection system to monitor the performance of the fabric filter according to the requirements in section §60.48Da of this part (2) The affected facility uses an ESP as the prim ary PM control device, and the owner or operator uses an ESP predictive model to monitor the performanc e of the ESP developed in accordance and operated according to the requirements in section §60.48Da of this part. (3) The affected facility burns only gaseous fuels and/or fuel oils that contain no greater than 0.5 weight percent sulfur, and the owner or operator operates the unit according to a written site-specific monitoring plan approved by the permitting authority. This monito ring plan must include procedures and criteria for establishing and monitoring specific parameters for the affected facility indicative of compliance with the opacity standard. For testing performed as part of this site-specific monitoring plan, the permitting authority may require as an alternative to the notif ication and reporting requirements specified in §§60.8 and 60.11 that the owner or operator submit any de viations with the excess emissions report required under §60.48c(c). §60.48c Reporting and reco rdkeeping requirements. (a) The owner or operator of each affected facility sha ll submit notification of the date of construction or reconstruction and actual startup, as provided by §60. 7 of this part. This notification shall include: (1) The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility. (2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under §60.42c, or §60.43c. (3) The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and base d on each individual fuel fired. (4) Notification if an emerging technol ogy will be used for controlling SO 2 emissions. The Administrator will examine the description of the control device and will determine whether the technology qualifies as an emerging technology. In making this determin ation, 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 §60. 42c(a) or (b)(1), unless and until this determination is made by the Administrator. (b) The owner or operator of each affected facility subject to the SO 2 emission limits of §60.42c, or the PM or opacity limits of §60.43c, shall submit to the Administrator the performance test data from the initial and any subsequent performance tests and, if applicable, the performance evaluation of the CEMS and/or COMS using the applicable performance specifications in appendix B of this part. (c) In addition to the applicable requirements in §60.7, the owner or operator of an affected facility subject to the opacity limits in §60.43c(c) shall s ubmit excess emission reports for any excess emissions from the affected facility that occur during the reporting period and maintain records according to the requirements specified in paragraphs (c)(1) through (3 ) of this section, as applicable to the visible emissions monitoring method used. (1) For each performance test conducted using Method 9 of appendix A–4 of this part, the owner or operator shall keep the records including the informati on specified in paragraphs (c)(1)(i) through (iii) of this section. (i) Dates and time intervals of all opacity observation periods; Comment [CF16]: Add ESP model to COMS exemption options

Comment [CF17]: Clarify can burn gaseous fuels along with low S oil

Comment [CF18]: Add additional flexibility for the permitting authority to reduce burden to the regulated community20 (ii) Name, affiliation, and copy of current visible emission reading certification for each visible emission observer participating in the performance test; and (iii) Copies of all visible emission observer opacity field data sheets ;

. (2) For each performance test conducted using Method 22 of appendix A–4 of this part, the owner or operator shall keep the records including the information specified in paragraphs (c)(2)(i) through (iv) of this section. (i) Dates and time intervals of all visible emissions observation periods; (ii) Name and affiliation for each visible emission observer participating in the performance test; (iii) Copies of all visible emission observer opacity field data sheets; and (iv) Documentation of any adjustments made and the time the adjustments were completed to the affected facility operation by the owner or operator to demonstrate compliance with the applicable monitoring requirements. (3) For each digital opacity compliance system, the owner or operator shall maintain records and submit reports according to the requirements specified in the site-specific monitoring plan approved by the Administrator (d) The owner or operator of each affected facility subject to the SO 2 emission limits, fuel oil sulfur limits, or percent reduction requirements under §60. 42c shall submit reports to the Administrator. (e) The owner or operator of each affected facility subject to the SO 2 emission limits, fuel oil sulfur limits, or percent reduction requirements under §60. 42c shall keep records and submit reports as required under paragraph (d) of this section, incl uding the following information, as applicable. (1) Calendar dates covered in the reporting period. (2) Each 30-day average SO 2 emission rate (ng/J or lb/MMBtu), or 30-day average sulfur content (weight percent), calculated during the reporting period, e nding with the last 30-day period; reasons for any noncompliance with the emission standards; and a description of corrective actions taken. (3) Each 30-day average percent of potential SO 2 emission rate calculated during the reporting period, ending with the last 30-day period; reasons for an y noncompliance with the emission standards; and a description of the corr ective actions taken. (4) Identification of any steam generating unit operating days for which SO 2 or diluent (O 2 or CO 2 ) data have not been obtained by an approved method for at least 75 percent of the operating hours; justification for not obtaining sufficient data; a nd a description of corrective actions taken. (5) Identification of any times when emissions data have been excluded from the calculation of average emission rates; justification for excluding data; and a description of corrective act ions taken if data have been excluded for periods other than those during wh ich coal or oil were not combusted in the steam generating unit. (6) Identification of the F factor used in calculat ions, method of determination, and type of fuel combusted. (7) Identification of whether averages have been obtained based on CEMS rather than manual sampling methods. (8) If a CEMS is used, identification of any times when the pollutant concentration exceeded the full span of the CEMS.21 (9) If a CEMS is used, description of any modifications to the CEMS that could affect the ability of the CEMS to comply with Performance Specifications 2 or 3 of appendix B of this part. (10) If a CEMS is used, results of daily CEMS drift tests and quarterly accuracy assessments as required under appendix F, Procedure 1 of this part. (11) If fuel supplier certification is used to demonstr ate compliance, records of fuel supplier certification as described under paragraph (f)(1), (2), (3), or (4) of this section, as applicable . In addition to records of fuel supplier certifications, the report shall include a certified statement signed by the owner or operator of the affected facility that the records of fuel supplier certifications submitted represent all of the fuel combusted during the reporting period. (f) Fuel supplier certification shall include the following information: (1) For distillate oil: (i) The name of the oil supplier; (ii) A statement from the oil supplier that the oil comp lies with the specifications under the definition of distillate oil in §60.41c; and (iii) The sulfur content or maximum sulfur content of the oil. (2) For residual oil: (i) The name of the oil supplier; (ii) The location of the oil when the sample was drawn for analysis to determine the sulfur content of the oil, specifically including whether the oil was sampled as delivered to the affected facility, or whether the sample was drawn from oil in storage at the oil supplier's or oil refiner's facility, or other location; (iii) The sulfur content of the oil from which the shipment came (or of the shipment itself); and (iv) The method used to determine the sulfur content of the oil. (3) For coal: (i) The name of the coal supplier; (ii) The location of the coal when the sample was collected for analysis to determine the properties of the coal, specifically including whether the coal was sampled as delivered to the affected facility or whether the sample was collected from coal in storage at the mine, at a coal preparation plant, at a coal supplier's facility, or at another location. The certif ication shall include the name of the coal mine (and coal seam), coal storage facility, or coal preparation plant (where the sample was collected); (iii) The results of the analysis of the coal from wh ich the shipment came (or of the shipment itself) including the sulfur content, moisture content, ash content, and heat content; and (iv) The methods used to determine the properties of the coal. (4) For other fuels: (i) The name of the supplier of the fuel; (ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J heat input; and (iii) The method used to determine the potential sulfur emissions rate of the fuel.22 (g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain records of the amount of each fuel combusted during each operating day. (2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in §60.48c(f) to demonstrate compliance with the SO 2 standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month. (3) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility or multiple affected facilities located on a contiguous property unit where the only fuels combusted in any steam generating unit (including steam generati ng units not subject to this subpart) at that property are natural gas, wood , distillate oil meeting the most current requirements in §60.42C to use fuel certification to demonstrate compliance with the SO 2 standard, and/or fuels, excluding coal and residual oil, not subject to an emissions standard (excl uding opacity) may elect to record and maintain records of the total amount of each steam generating unit fuel delivered to that property during each calendar month. (h) The owner or operator of each affected facility subject to a federally enforceable requirement limiting the annual capacity factor for any fuel or mixture of fuels under §60.42c or §60.43c shall calculate the annual capacity factor individually for each fuel combusted. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of the calendar month. (i) All records required under this section shall be maintained by the owner or operator of the affected facility for a period of two years following the date of such record. (j) The reporting period for the reports required under this subpart is each six- month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period.