Stationary Fuel Combustion Sources SEPA
Final Rule: Mandatory Reporting of Greenhouse Gases Environmental Protection
United States
Environn
Agency
Under the Mandatory Reporting of Greenhouse Gases (GHGs) rule, owners or operators of facilities
that emit 25,000 metric tons or more of GHGs per year (expressed as carbon dioxide equivalents)
from stationary fuel combustion or that meet any other applicability requirements of the rule (see
information sheet on General Provisions) are required to report emissions from stationary fuel
combustion. Owners or operators must collect emission data; calculate GHG emissions; and follow
the specified procedures for quality assurance, missing data, recordkeeping, and reporting.
How Is This Source Category Defined?
Stationary fuel combustion sources are devices that combust any solid, liquid, or gaseous fuel generally to:
• Produce electricity, steam, useful heat, or energy for industrial, commercial, or institutional use; or
• Reduce the volume of waste by removing combustible matter.
These devices include, but are not limited to, boilers, combustion turbines, engines, incinerators, and process
heaters. The rule excludes flares (unless otherwise required by another subpart), portable equipment, and
emergency generators, emergency equipment, agricultural irrigation pumps, and combustion of hazardous
waste (except for co-fired fuels).
Facilities that contain stationary fuel combustion units, but do not contain a source in any other source
category covered by the rule, are not required to submit a report if their aggregate maximum rated heat input
capacity from all stationary fuel combustion units is less than 30 million British thermal units per hour
(mmBtu/hr).
Electricity generating units that are subject to EPA's Acid Rain Program (40 CFR part 75) or that report CO2
emissions year-round through part 75 are covered under 40 CFR part 98, subpart D (Electricity Generation).
What GHGs Must Be Reported?
Facilities must report annual carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O) emissions from
each fuel combustion unit. For each unit, CO2, CH4> and N2O emissions must be reported separately for each
type of fuel combusted, including biomass fuels. In addition, facilities report any CO2 emissions from sorbent
use in air pollution control equipment.
How Should GHG Emissions Be Calculated?
The following methodologies can be used to calculate CO2, CH4, and N2O emissions:
• Calculating CO? Emissions from Combustion
Facilities must calculate CO2 emissions using one of four methodological tiers, subject to certain
restrictions based on unit size and fuel burned (see flow chart on page 3):
o Tier 1 uses an emission factor that is multiplied by annual fuel use and a default heating value
for that fuel.
o Tier 2 uses an emission factor that is multiplied by annual fuel use and a measured heating
value of that fuel. Units that combust MSW or other solid fuels and generate steam must use
steam production (in place of fuel use) and an emission factor.
40 CFR 98, subpart C 1 EPA-430-F-09-005R
September 2009
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o Tier 3 uses a calculation based on annual fuel use and measured carbon content of that fuel.
For this tier, calculate emissions only for fuels that contribute 10 percent or more of the
annual heat input to the unit.
o Tier 4 requires a continuous emissions monitoring system (CEMS).
In general, reporters are required to calculate GHG emissions only for specific fuels that are listed in
the rule, except that units larger than 250 mmBtu/hr also must calculate GHG emissions for any fuel
that provides 10 percent or more of the annual heat input to the unit.
• Calculating CO? for units with existing CEMS
o Combustion units that have certain types of existing CEMS in place and meet specific criteria
are required to use the Tier 4 methodology. This might require certain upgrades to the
existing CEMS in order to comply with the Tier 4 methodology. Those upgrades will depend
on the fuel burned and the CEMS currently installed on a unit.
o Combustion units that are subject to the reporting requirements under EPA's Acid Rain
Program will continue to measure CO2 mass emissions using the 40 CFR part 75 methods and
must report CO2 emissions by converting the cumulative fourth quarter CO2 emissions from
short tons to metric tons.
o As an alternative to any of the four tier calculation methodologies, units that report to EPA
year-round heat input data under 40 CFR part 75, can calculate annual CO2 emissions using
part 75 methods.
• Calculating N2O and CFU Emissions From Combustion
Most units can use an emission factor that is based on annual fuel use and the high heat value of fuel
(using a default value prescribed in the rule if a measured heat value is not available). Units covered
under EPA's Acid Rain Program and other units that monitor and report annual heat input under 40
CFR part 75 requirements will use an emission factor and the measured annual heat input.
• Calculating CO? Emissions From Sorbent Use
Fluidized bed boilers and units equipped with a wet flue gas desulfurization system or sorbent
injection will use the calculation procedure provided in the rule to estimate CO2 emissions from
sorbent use.
• Calculating Biogenic CO? Emissions From Biomass Fuel Combustion
Facilities must estimate CO2 emissions from the combustion of the biomass fuels listed in the rule.
Emissions are estimated by using the Tier 1 Calculation Methodology described above. For units that
combust municipal solid waste or pre-mixed biomass fuels, the rule provides methods for calculating
the biomass portion of CO2 emissions.
What Measurements are Required?
Required measurements are determined as follows:
• Annual fuel use can be determined either by use of company records (e.g., billing data, steam
generation, unit operating hours) or by direct measurement using flow meters, depending on the size
of the unit and the type of fuel burned.
• Depending on the tier calculation method used and the fuel burned, reporters could be required to
measure high heating value, molecular weight, or carbon content of fuel. Fuel sampling and analysis
must be conducted daily, weekly, monthly, quarterly, semi-annually, or by lot depending on the fuel
burned.
40 CFR 98, subpart C 2 EPA-430-F-09-005R
September 2009
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General Stationary Fuel Combustion Requirements for CO2
40 CFR 98 Subpart C
Do OEMS
and Unit
Meet Certain
Conditions?1
Does the Uni
Report Annual
CC>2 Through
Part 75?
Tier 4. Use
CEMS to
Monitor CO,
Does the Unit
Have Existing
CEMS?
Continue to Monitor CO2
According to Part 75.
Report Annual CO2
Emissions.
Does Unit Burn
any Biomass-
derived Fuel
e.g., Wood)?,
Is Units Rated
Heat Input
Capacity >250
mmBtu/hr?
CEMS conditional requirements (All four conditions must apply):
- Unit capacity: >250 mmBtu/hr solid fuelor>250 tons/day MSW.
- Unit has operated >1,000 hours/year in any year since 2005.
- Unit has either a Part 60, Part 75, or state-certified gas monitor of
any kind or a flow rate monitor (or both).
- The existing CEMS are required by regulation or permit, and are
also required to undergo periodic QA/QC testing.
OR
- Unit capacity: < 250 mmBtu/hr solid fuel or < 250 tons/day MSW.
- Unit has operated >1,000 hours/year in any year since 2005.
- Unit has both a CO2 monitor and a flow rate monitor.
- The existing CEMS are required by regulation or permit, and are
also required to undergo periodic QA/QC testing.
For
iogenic
C02
nissions
\
For any Co-fired
Fossil Fuels
f
Tier 1." Use
Default HHV and YES
Default CO2 < <
Emission Factor
Is a CO2
emission factor
for the fuel
provided in
TableC-1?.
Measured HHV3
Is Pipeline
Natural Gas or
Distillate Oil
Burned?
oes the fue
provide >10%
of the annual
eat input?.
Measured Fuel
Is Measured
High Heating
Value (HHV)3
Available?
Is CO2 Emission
Factor for the
Fuel Provided in
Table C-1?
Are Defaul
CO2 Emission
Factor and
HHV for Fuel
Provided in
C-1?
2 MSW units that do not have CEMS may use Tier 2, using measured
annual steam generation in lieu of sampling the fuel HHV, or Tier 1 if
steam is not produced by the unit.
3 Either measured by owner/operator or provided by fuel supplier at the
required frequency.
4 Reporters have the option of using any higher Tier methodology.
40 CFR 98, subpart C
September 2009
EPA-430-F-09-005R
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What Information Must Be Reported?
In addition to the information required by the General Provisions at 40 CFR 98.3(c), the final rule calls for
facilities to report the following information:
• Annual mass emissions for each GHG for each combustion unit. Emissions can be reported as the
aggregated mass among multiple units under any of the three the following conditions:
o Groups of units, if each unit has a maximum rated heat input capacity of 250 mmBtu/hr or
less.
o Units that share a common stack and use CEMS.
o Oil-fired or gas-fired units that combust the same fuel, if the fuel is fed through a metered
common pipe.
• All measured inputs used in the emissions calculations (e.g., fuel use, carbon content, heating value)
and all certification tests and major quality assurance tests for units using CEMS.
Existing facilities that are required to report emissions from stationary combustion sources only (and no other
source categories) can submit an abbreviated emissions report using simplified calculation methods for
reporting year 2010 only.
For More Information
This document is provided solely for informational purposes. It does not provide legal advice, have legally
binding effect, or expressly or implicitly create, expand, or limit any legal rights, obligations, responsibilities,
expectations, or benefits in regard to any person. The series of information sheets is intended to assist
reporting facilities/owners in understanding key provisions of the final rule.
Visit EPA's Web site (www. epa. gov/climatechange/emissions/ghgrulemaking.html) for more information,
including the final preamble and rule, additional information sheets on specific industries, the schedule for
training sessions, and other documents and tools. For questions that cannot be answered through the Web site,
please contact us at: ghgmrr@epa.gov.
40 CFR 98, subpart C 4 EPA-430-F-09-005R
September 2009
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