The 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)
CO
2
from 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 CO
2
Monitoring.
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
CO
2 emissions using this system, must install and use a
CO
2 monitor. An operator without a
CO
2 monitor who uses a CEMS and
O
2 concentrations to calculate and report a unit's
CO
2 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 CO
2 concentration and flow, and the
calculation of CO
2 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 CO
2
Emissions.
Notwithstanding the provisions of
40 CFR §
98.33(b), the operator's
selection of a method for calculation of CO
2 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 CO
2, 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
N
2O
and CH
4. 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 N
2O or CH
4
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 CO
2
Determination. 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
CO
2 emissions using a CEMS under
40 CFR §
98.33(a)(4).
(g)
Fuel Use for CEMS Units.
The operator who estimates and reports CO
2 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.
Notes
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).