Section 95115 - Stationary Fuel Combustion SourcesThe operator of a facility who is required to report under section 95101 of this article, and who is not eligible for abbreviated reporting under section 95103(a), must comply with Subpart C of 40 CFR Part 98 (§§ 98.30 to 98.38) in reporting stationary fuel combustion emissions and related data to ARB, except as otherwise provided in this section.
(a) CO2from Steam Producing Units. The operator of a steam producing unit combusting municipal solid waste or solid biomass fuels may use Equation C-2c of 40 CFR § 98.33(a)(2)(B)(iii), unless required to use Tier 3 or 4 by 40 CFR Part 98 or Part 75. Operators of steam producing units combusting fossil-based solid fuels must select applicable Tier 3 or Tier 4 methods.(b)CEMS CO2Monitoring. Notwithstanding the allowed use of oxygen concentration monitors in 40 CFR § 98.33(a)(4)(iv), an operator installing a continuous emissions monitoring system that includes a stack gas volumetric flow rate monitor after January 1, 2012, and who reports CO2 emissions using this system, must install and use a CO2 monitor. An operator without a CO2 monitor who uses a CEMS and O2 concentrations to calculate and report a unit's CO2 emissions, and who conducts a Relative Accuracy Test Audit (RATA) for the unit, must at least annually include in the RATA the direct monitoring of CO2 concentration and flow, and the calculation of CO2 mass per hour. The operator must retain these results pursuant to the recordkeeping requirements of section 95105 and make them available to ARB upon request. The requirements of this paragraph do not apply to facilities for which pipeline natural gas is the only fuel consumed.(c)Choice of Tier for Calculating CO2Emissions. Notwithstanding the provisions of 40 CFR § 98.33(b), the operator's selection of a method for calculation of CO2 emissions from combustion sources is subject to the following limitations by fuel type and unit size. The operator is permitted to select a higher tier than that required for the fuel type or unit size as specified below. (1) The operator may select the Tier 1 or Tier 2 calculation method specified in 40 CFR § 98.33(a) for any fuel listed in Table 2-3 of this section that is combusted in a unit with a maximum rated heat input capacity of 250 MMBtu/hr or less, subject to the limitation at 40 CFR § 98.33(b)(1)(iv), or for biomass-derived fuels listed in Table C-1 of 40 CFR Part 98 when these emissions are not subject to a compliance obligation under the cap-and-trade regulation, except as limited by section 95115(e).(2) The operator may select the Tier 2 calculation method specified in 40 CFR § 98.33(a)(2) for natural gas when it is pipeline quality as defined in section 95102 of this article, and for distillate fuels listed in Table 2-3 of this section. Tier 1 may be selected when the fuel supplier is providing pipeline quality natural gas measured in units of therms or million Btu. Equation C-2c of 40 CFR § 98.33(a) may be selected for the units specified in paragraph (a) of this section.(3) The operator may select any calculation method specified in 40 CFR § 98.33(a) when calculating emissions that are shown to be de minimis under section 95103(i) of this article, or for a fuel providing less than 10 percent of the annual heat input to a unit with a maximum rated heat input capacity of 250 MMBtu/hr or less, unless not permitted under 40 CFR § 98.33(b).(4) The operator must use either the Tier 3 or the Tier 4 calculation method specified under 40 CFR § 98.33(a)(3)-(4) for any other fuel, including non-pipeline quality natural gas and fuel with emissions identified as non-exempt biomass-derived CO2, subject to the limitations of 40 CFR § 98.33(b)(4)-(5) requiring use of the Tier 4 method. The operator using Tier 3 must determine annual average carbon content with weighted fuel use values, as required by Equation C-2b of 40 CFR § 98.33. When fuel mass or volume is measured by lot, the term "n" in Equation C-2b is substituted as the number of lots received in the year.(d)Source Test Option for N2O and CH4. In lieu of other methods specified in this article, a facility operator may conduct site-specific source testing to derive emission factors and determine annual emissions of N2O or CH4 from any combustion source. Alternatively, the operator may use the results of an applicable test method specified in title 17, California Code of Regulations, section 95471. For source testing: (1) The facility operator must submit to the Executive Officer a test plan at least 45 days prior to the first test date. The test plan must provide for testing at least annually, and more frequently as needed to account for seasonal variations in fuels or processes.(2) The plan must specify conduct of performance and stack tests consistent with the requirements of approved ARB or U.S. EPA test methods. Process rates during the test must be determined in a manner that is consistent with the procedures used for GHG report accounting purposes.(3) Upon approval of the test plan by the Executive Officer, the test procedures in that plan must be repeated as specified in the plan. The Executive Officer and the local air pollution control officer must be notified at least ten days in advance of subsequent tests.(e)Procedures for Biomass CO2Determination. Reporting entities must use the following procedures when calculating emissions from biomass-derived fuels that are intermixed with fossil fuels:(1) When combusting municipal solid waste (MSW) or any other fuel for which the biomass fraction is not known, the operator must follow the procedures specified in 40 CFR § 98.33(e)(3) to specify a biomass fraction.(2) For the analysis conducted under the requirements of 40 CFR § 98.34(e) for partially biogenic fuels other than MSW, the operator may choose to analyze monthly fuel samples. The operator must collect such samples weekly and combine a portion of each weekly sample to form a monthly composite mixture. The monthly composite mixture must be homogenized and well mixed prior to withdrawal of a sample for analysis.(3) When calculating emissions from a biomethane and natural gas mixture as described in 40 CFR § 98.33(a)(2) using the annual MMBtu of fuel combusted in place of the product of Fuel and HHV in Equation C-2a, the operator must calculate emissions based on contractual deliveries of biomethane subject to the requirements of 95131(i), using the natural gas emission factor in the following equations: (Ebiomass = EFnatural gas x MMBtubiomethane x 0.001)/(Enatural gas = EFnatural gas x (MMBtuannual - MMBtubiomethane) x 0.001)
Where:
Ebiomass = The annual biomass CO2, CH4 or N2O emissions from biomethane (metric tons)
Enatural gas = The annual fossil CO2, CH4 or N2O emissions from natural gas (metric tons)
EFnatural gas = The natural gas emission factor from Tables C-1 and C-2 of 40 CFR Part 98 (kg/MMBtu)
MMBtuannual = The total delivered MMBtus for the reporting year based on utility bills or meters meeting the accuracy requirements of section 95103(k)
MMBtubiomethane = The total biomethane deliveries subject to the requirements of section 95131(i) for the reporting year based on contractual deliveries
(4) When calculating emissions from a biomethane and natural gas mixture as described in 40 CFR § 98.33(a)(4) using a continuous emission monitoring system (CEMS), or when calculating those emissions according to Subpart D of 40 CFR Part 98 , the reporting entity must calculate the biomethane emissions as described in subparagraph (3) of this section, with the remainder of emission being natural gas emissions.(5) When calculating emissions from a biogas and natural gas mixture using 40 CFR § 98.33(a)(4) or the carbon content method described in 40 CFR § 98.33(a)(3), or when calculating those emissions according to Subpart D of 40 CFR Part 98 , the reporting entity must calculate biogas emissions using a carbon content method as described in 40 CFR § 98.33(a)(3), with the remainder of emissions being natural gas emissions.(f)Fuel Sampling Frequencies. The operator who collects and analyzes fuel samples to conduct the monitoring analyses required under 40 CFR § 98.34 must sample at the frequencies specified in that section, except in the following cases. (1) Natural gas that is outside the range of pipeline quality as defined in section 95102 must be sampled and analyzed at least monthly by the reporting entity or the fuel supplier.(2) Under 40 CFR § 98.34(b)(3)(ii)(E), in cases where equipment necessary to perform daily sampling and analysis of carbon content and molecular weight for refinery fuel gas is not in place, such equipment must be installed and procedures established to implement daily sampling and analysis no later than January 1, 2013.(3) The operator is estimating CO2 emissions using a CEMS under 40 CFR § 98.33(a)(4).(g)Fuel Use for CEMS Units. The operator who estimates and reports CO2 emissions using a CEMS under 40 CFR § 98.33(a)(4) must also report the quantity of each type of fuel combusted in the unit or group of units (as applicable) during the reporting year, in standard cubic feet for gaseous fuels, gallons for liquid fuels, short tons for solid fuels, and bone dry short tons for biomass-derived solids. Fuel use monitoring devices for units covered under this paragraph are exempt from the provisions of section 95103(k) of this article.(h)Aggregation of Units. Facility operators may elect to aggregate units according to 40 CFR § 98.36(c), except as otherwise provided in this paragraph. Facility operators that are reporting under more than one source category in paragraphs 95101(a)(1)(A)-(B) and that elect to follow 40 CFR § 98.36(c)(1), (c)(3) or (c)(4), must not aggregate units that belong to different source categories. For the purpose of unit aggregation, units subject to 40 CFR Part 98 Subpart C that are associated with one source category must not be grouped with other Subpart C units associated with another source category, except when 40 CFR § 98.36(c)(2) applies. Aggregation of stationary fuel combustion units is limited to units of the same type, where the unit type categories are: boiler, reciprocating internal combustion engine, turbine, process heater, and other (none of the above). When reporting under the provisions of 40 CFR § 98.36(c)(1) for an aggregation of units or (c)(3) for common pipe configurations, the requirements can be met by separately reporting the fuel use by fuel type as a percentage of the aggregated fuel consumption attributed to each individual unit or each group of units of the same type. Units subject to section 95112 must use the criteria for aggregation in section 95112(b). Facility operators that choose to aggregate units according to the common stack provision in 40 CFR § 98.36(c)(2) using CEMS may report emissions according to 40 CFR § 98.36(c)(2), but they must separately report the fuel use by fuel type as a percentage of the aggregated fuel consumption attributed to each individual unit or each group of units of the same type, such that the grouping of units still meets the limitations for unit aggregation specified elsewhere in this paragraph.(i)Pilot Lights. Notwithstanding the exclusion of pilot lights from this source category in 40 CFR § 98.30(d), the operator must include emissions from pilot lights in the emissions data report when operated 300 hours or more in the data year. The operator may apply appropriate methods from 40 CFR § 98.33 or engineering methods to calculate these emissions when pilot lights are unmetered. Pilot lights fueled from a common fuel source may be aggregated for reporting. Pilot lights may be reported as de minimis consistent with the requirements of section 95103(i). Pilot lights are not subject to the measurement device calibration requirements of section 95103, but pilot light emissions calculations are subject to verification.(j)Electricity Generating and Cogeneration Units. The operator of a facility that includes electricity generating and cogeneration units meeting the applicability criteria of section 95101 must meet the requirements specified in section 95112 of this article.(k)Natural Gas Supplier Information. The operator who is reporting emissions from the combustion of natural gas must report the name(s) of the supplier(s) of natural gas to the facility, the operator's natural gas supplier customer account number(s), natural gas supplier service account identification number(s) or other primary account identifier(s), and the annual MMBtu delivered to each account according to billing statements (10 therms = 1 MMBtu), and if the natural gas was received directly from an interstate pipeline supplier. In the case that the natural gas is purchased from an entity other than the natural gas supplier, the operator must report the supplier name and customer or service account identification number, but may report the annual MMBtu delivered based on the seller's billing statement.(l)Information on Natural Gas Supplied to Downstream Users. The operator who is reporting emissions from the combustion of natural gas must report whether any of the natural gas reported pursuant to section 95115(k) was supplied to downstream users outside of the operator's facility boundary. If so, the operator must report the name of the facility and the annual MMBtu delivered to each user according to billing statements or financial records.(m)Procedures for Missing Data. To substitute for missing data for emissions reported under section 95115 of this article, the operator must follow the requirements of section 95129.(n)Additional Product Data. Operators of the following types of facilities must also report the production quantities indicated below. (1) The operator of a facility engaged in hot rolling and/or cold rolling of steel must report the quantity of hot rolled steel sheet, pickled steel sheet, cold rolled and annealed steel sheet, galvanized steel sheet, and tin plate produced in the data year (short tons). For cold rolled and annealed steel sheet, the operator must also report a description of the process used to produce the products, such as continuous annealing process or batch annealing.(2) The operator of a soda ash manufacturing facility must report the quantity of soda ash equivalent produced in the data year (short tons).(3) The operator of a gypsum manufacturing facility must report the quantity of plaster that is sold as a separate finished product and the amount of stucco used to produce saleable plasterboard produced in the data year (short tons)(4) The operator of a turbine and turbine generator set testing facility must report the nameplate power of the units tested (horsepower tested).(5) The operator of a poultry processing facility must report the quantity of whole chicken and chicken parts, poultry deli products, and protein meal and fat produced in the data year (short tons).(6) The operator of a facility that manufactures dehydrated flavors must report the production of dehydrated onion, dehydrated garlic, dehydrated chili peppers, dehydrated parsley, and dehydrated spinach in the data year (short tons).(7) The operator of a beer brewery must report the production of lager beer in the data year (gallons).(8) The operator of a snack food manufacturing facility must report the production of fried potato chips, baked potato chips, corn chips, corn curls, and pretzels in the data year (short tons).(9) The operator of a sugar manufacturing facility must report the production of granulated refined sugar in the data year (short tons)(10) The operator of a tomato processing facility must report the quantity of aseptic tomato paste (short ton of 31 percent TSS), aseptic whole and diced tomato (short ton), non-aseptic tomato paste and tomato puree (short ton of 24 percent TSS), non-aseptic whole and diced tomato (short ton), and non-aseptic tomato juice (short ton) produced in the data year.(11) The operator of a pipe foundry must report the production of ductile iron pipes produced in the data year (short tons).(12) The operator of a facility producing aluminum billets must report the production of aluminum and aluminum alloy billets in the data year (short tons).(13) The operator of a facility mining or processing of rare earth minerals must report the production of rare earth oxide equivalents in the data year (short tons).(14) The operator of a facility mining or processing freshwater diatomite filter aids must report the production of freshwater diatomite filter aids in the data year (short tons).(15) The operator of a forging facility must report the production of seamless rolled ring during the data year (short tons).(16) The operator of a dairy product facility must report the production of fluid milk product, butter, condensed milk, buttermilk powder, intermediate dairy ingredients, lactose, whey protein concentrate (WPC), deproteinized whey, cheese by cheese type, milk powder by the type of heat treatment (low heat, medium heat, or high heat), anhydrous milkfat, and milk protein concentrate by product type during the data year (short tons). Butter re-melted and re-introduced to the manufacturing process may be reported again as butter production. Buttermilk powder and nonfat dry milk and skimmed milk powder that is re-constituted and re-introduced to the manufacturing process may be reported as production. The operator must report the production of total WPC and WPC with high protein concentration using diafiltration process during the data year (short tons). The operator must also report the amount of imported protein.(17) The operator of an almond or pistachio processing facility must report the production of adjusted hulled and dried pistachios, flavored pistachios, blanched almonds, flavored almonds, and pasteurized almonds (short tons).(18) The operator of a wet corn milling facility must report the production of corn entering wet milling process during the data year (short tons).(19) The operator of a winery must report the production of distilled spirits (proof gallons), dry color concentrate (short tons), grape juice concentrate (gallons), grape seed extract (short tons), and liquid color concentrate (gallons) during the data year.(20) The operator of a sulfuric acid regeneration facility must report the production of sulfuric acid produced (short tons).(21) The operator of a borate manufacturing facility must report the quantity of borate produced in the data year in boric oxide equivalent (short tons). Table 2-3: Petroleum Fuels For Which Tier 1 or Tier 2 Calculation Methodologies May Be Used Under Section 95115(c)(1)
| Fuel Type | Default High Heat Value | Default CO2 Emission Factor |
| | |
| MMBtu/gallon | kg CO2 /MMBtu |
| Distillate Fuel Oil No. 1 | 0.139 | 73.25 |
| Distillate Fuel Oil No. 2 | 0.138 | 73.96 |
| Distillate Fuel Oil No. 4 | 0.146 | 75.04 |
| Kerosene | 0.135 | 75.20 |
| Liquefied petroleum gases (LPG)1 | 0.092 | 62.98 |
| Propane | 0.091 | 61.46 |
| Propylene | 0.091 | 65.95 |
| Ethane | 0.096 | 62.64 |
| Ethylene | 0.100 | 67.43 |
| Isobutane | 0.097 | 64.91 |
| Isobutylene | 0.103 | 67.74 |
| Butane | 0.101 | 65.15 |
| Butylene | 0.103 | 67.73 |
| Natural Gasoline | 0.110 | 66.83 |
| Motor Gasoline (finished) | 0.125 | 70.22 |
| Aviation Gasoline | 0.120 | 69.25 |
| Kerosene-Type Jet Fuel | 0.135 | 72.22 |
| ____________________ |
1 Commercially sold as "propane" including grades such as HD5.
Cal. Code Regs. Tit. 17, § 95115
1. New section filed 12-2-2008; operative 1-1-2009 (Register 2008, No. 49).
2. Amendment of section heading, section and NOTE filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
3. Amendment of subsections (c)(2), (c)(4), (e)(3) and (h) filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
4. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
5. Amendment of subsections (k), (n)(5), (n)(10)-(12) and (n)(14)-(16) and new subsection (n)(19) filed 12-31-2014; operative 1-1-2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
6. Amendment of subsections (c)(1)-(2) and (h) and subsections within subsection (n), including renumbering of former table 1 to table 2-3, filed 9-1-2017; operative 1-1-2018 (Register 2017, No. 35).
7. Amendment of subsection (n)(16) filed 3-29-2019; operative 4-1-2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13). Note: Authority cited: Sections 38510, 38530, 39600, 39601, 39607, 39607.4 and 41511, Health and Safety Code. Reference: Sections 38530, 39600 and 41511, Health and Safety Code.
1. New section filed 12-2-2008; operative 1-1-2009 (Register 2008, No. 49).
2. Amendment of section heading, section and Note filed 12-14-2011; operative 1-1-2012 pursuant to Government Code section 11343.4 (Register 2011, No. 50).
3. Amendment of subsections (c)(2), (c)(4), (e)(3) and (h) filed 12-19-2012; operative 1-1-2013 pursuant to Government Code section 11343.4 (Register 2012, No. 51).
4. Amendment filed 12-31-2013; operative 1-1-2014 pursuant to Government Code section 11343.4(b)(3) (Register 2014, No. 1).
5. Amendment of subsections (k), (n)(5), (n)(10)-(12) and (n)(14)-(16) and new subsection (n)(19) filed 12-31-2014; operative 1/1/2015 pursuant to Government Code section 11343.4(b)(3) (Register 2015, No. 1).
6. Amendment of subsections (c)(1)-(2) and (h) and subsections within subsection (n), including renumbering of former table 1 to table 2-3, filed 9-1-2017; operative 1/1/2018 (Register 2017, No. 35).
7. Amendment of subsection (n)(16) filed 3-29-2019; operative 4/1/2019 pursuant to Government Code section 11343.4(b)(3) (Register 2019, No. 13).