EPA Proposed Mandatory Greenhouse Gas Reporting Rule

1. EPA Proposed Mandatory Greenhouse Gas Reporting Rule

2. Overview of the Reporting Rule • The purpose of the rule is to collect “comprehensive and accurate” data on GHG emissions that can be used to inform future policy decisions • No direction on the development of emission reduction or control • It is not meant to be a registry tracking individual projects or reductions • After it is published in the Federal Register, there will be a 60 day comment period (probably w/ additional 30 days) • EPA wants to publish the final rule before the end of the year • The proposed rule and preamble are extensive (1400+ pages) • In addition • Technical Support Documents • Regulatory Impact Statement

3. Regulated Gases • Mandatory reporting of GHGs would require reporting of annual emissions of: • Carbon Dioxide (CO2) • Methane (CH4) • Nitrous Oxide (N2O) • Sulfur Hexafluoride (SF6) • Hydrofluorocarbons (HFCs) • Perfluorochemicals (PFCs) • Other Fluorinated Gases (e.g. NF3, HFEs)

4. Proposed Sectors and Sources

5. Schedule for Reporting • Facilities and suppliers would begin collecting data on January 1, 2010 • First emissions report would be due on March 31, 2011 • New vehicles and engine manufacturers would start reporting w/ the 2011 model year • Reports would be submitted annually

6. What Information Would be Reported? • Total GHG emissions in MT of CO2E from all source and supply categories: • Gas • Breakdown emissions w/in each source category (e.g. unit or process level) • Activity data

7. How Would Reports be Submitted? • Facilities would report directly to the EPA • Electronic reporting • Self-certification by Designated Representative

8. Stationary Combustion

9. Who Reports? • Facilities w/ stationary fuel combustion sources that have emissions greater then 25,000 MTCO2E • In combination w/ other source categories process emissions • CO2, N2O and CH4 would be reported *Table only includes facilities w/ stationary combustion equipment not covered in other subparts of the rule **CO2 emissions from biomass are not considered as part of the determination of the threshold level

10. CO2 From Fuel Combustion • Based on the fuel combusted and the size of the stationary equipment • Facilities w/ and aggregate maximum heat input capacity of less then 30 mmBtu/hr are automatically exempt from the proposed rule • 4-tiered approach • Tier 4 –large stationary combustion units fired w/ solid fuels and have existing CEMS equipment • Tier 3 –large stationary combustion units fired w/ liquids or gaseous fuels • Tiers 1 and 2 – simplified emissions calculations

11. General Stationary Fuel Combustion Requirements for CO2Proposed 40 CFR 98 Subpart C Do CEMS and Unit Meet Certain Conditions?1 Tier 4: Use CEMS Similar to 40 CFR 75 Does Unit Have Existing CEMS? YES YES NO2 NO Does Unit Burn Wood Biomass Fuels? YES NO Is Unit >250 MMBtu/hr Heat Input? Tier 33: Measure Fuel Carbon Content YES NO NO Tier 22: Use Measured HHV and CO2 Emission Factor Is a CO2 Emission Factor for the Fuel Provided in Rule? Is Measured High Heating Value (HHV) Available? YES YES 1 Conditions for requiring CEMS: - >250 MMBtu/hr or >250 tons/day MWC. - Operates >1,000 hours/year. - Has Part 60 or Part 75 or state-certified gas monitor or flow rate monitor. - Meets QA/QC requirements as above. OR - <250 MMBtu/hr or <250 tons/day MWC. - Operates >1,000 hours/year. - Has Part 60 or Part 75 or state-certified certified gas monitor and flow rate monitor. - Meets QA/QC requirements as above. 2 MSW units that do not use CEMS would use Tier 2. 3 Reporters have the option of using any higher tier methodology. NO Tier 13: Use Default HHV and CO2 Emission Factor Are Emission Factors and HHV for Fuel Provided in the Rule? YES NO Tier 33: Measure Fuel Carbon Content

12. Tier 4 • Requires the use of certified CEMS for: • Units that use solid fossil fuels w/ a maximum heat input capacity > 250 mmBtu/hr or a unit that combusts > 250 tons MSW/day • Units combusting MSW would need to use a CO2 monitor to calculate emissions • Smaller fossil fuel-fired units (≤ 250 mmBtu/hr or 250 tons MSW/day) if all monitors needed to calculate CO2 emission are already installed • Unit has operated for > 1000 hr in any calendar year since 2005 • CEMS are required by Federal or State rules or operating permit • CEMS are certified by meet the requirements of part 75 or part 60 • CEMS must include gas or flow monitors • EPA is allowing until January 1, 2011 to install CEMS to meet the Tier 4 requirements, until that time affected units would be allowed to use Tier 3 methodology • Combustion units that are subject to the reporting requirements under the ARP would continue to measure CO2 mass emissions (using the 40 CFR part 75 methods) and continue quarterly reporting of CO2 emissions (cumulative short tons would be converted to MT)

13. Tier 3 • Required for liquid or gaseous fossil fuel-fired units w/ a maximum heat input capacity ≥ 250 mmBtu/hr and for solid fossil fuel-fired units that are not subject to tier 4 provisions • Requires periodic determination of the carbon content* of the fuel and direct measurement of the amount of fuel combusted • May be used to calculate facility wide CO2 emissions when the same liquid/gaseous fuel is used across the facility * Fuel sampling and analysis would be required only for those days/months when fuel is combusted in the unit All oil and gas flow meters would have to be calibrated prior to the first reporting year Monthly molecular weight determinations are required for gaseous fuels

14. Tier 2 • Requires that the HHVs of each fuel combusted be measured monthly • Required for units w/ heat input capacities of ≤ 250 mmBtu/hr for which EPA has provided default CO2 emission factors • Fuel consumption would be based on company records

15. Tier 1 • CO2 emissions would be calculated using the quantity of each type of fuel combusted during the year, in conjunction w/ fuel specific default CO2 emission factors and HHVs • Fuel combusted would be determined from company records • CO2 emission factors and HHVs are national-level default factors • Tier 1 method may be used by any small unit if EPA has provided the fuel specific HHV and emission factor • If owner routinely performs fuel sampling and analysis on a monthly basis (or more frequently) to determine HHV and other properties of the fuel, or if HHV data are provided by fuel supplier then Tier 2 method would have to be used

16. CO2 Emissions from Biomass Fuel Combustion • Units that combust biomass fuels will have to report annual biogenic CO2 emissions separately • This is consistent w/ IPCC and US GHG inventory framework • Where Tier 4 is not required, reporters can use Tier 1 method for fuels in which default CO2 emission factors and HHVs are provided • If no default values are provided then reports have to use Tiers 2 or 3 • For units required to use Tier 4, the rule has procedures to calculate the porting of CO2 that is from fossil fuel vs. biogenic fuels • For MSW, the rule has procedures to determine the portion of the CO2 that is from biogenic fuel using the ASTM method

17. CH4 and N2O Emissions • Units subject to the ARP would calculate emissions from continuous measurements of fuel heat input and fuel specific emission factors • Simplified emissions calculation methods • Emissions would be estimated using the EPA-provided default factors and annual heat input

18. CO2 Emissions from Sorbent • Calculate CO2 emissions from fluidized bed unit w/ sorbent injection controls or FDG using ratio of CO2 released upon capture of acid gas

19. Procedures for Estimating Missing Data • The rule requires the use of substitute data whenever a parameter that is used to calculate GHG emissions is unavailable • Tiers 2 or 3 • If HHV, fuel carbon content of fuel molecular weight data are missing, the substitute data value would be the average of the parameter immediately before and after the missing data period • Tiers 3 or 4 • If fuel or gas flow rate data is missing, the substitute data values would be the best available estimates of these parameters, based on process and operating data

20. Selection of Data Reporting Requirements • Facility-level reporting requirements proposed under 40 CFR part 98 subpart A • Unit-level information • Unit type • Maximum heat input • Type of fuels combusted • Methodology used to calculate emissions • Total annual GHG emissions • Additional reporting requirements depending on the Tier methodology used: • Tier 1 – Yearly fuel usage • Tier 2 – Monthly fuel usage, HHV inputs and sources of information, yearly MSW calc. input info • Tier 3 – Monthly/daily fuel usage, carbon content values, molecular weight measurements, result of all fuel flow meter calibrations, methods used for carbon content determinations, flow meter calibrations and oil tank drop measurements • Tier 4 – Operating days/hour; daily CO2 mass emission totals, substitute data information for CO2 concentrations, which CEMS certification and QA procedures are used, stack flow rate and moisture content • Alternatives to unit level report • Aggregate groups of small units (combined heat input ≤ 250 mmBtu/hr) • Common stacks monitored w/ CEMS • Common pipeline configuration shared by oil or gaseous fuel combusting unit, firing the same fuel fed through a common supply line

21. Selection of the Records That Must Be Retained • Record keeping requirement proposed under 40 CFR part 98, subpart A • Records must be kept for a period of 5 years

22. EPA Requests Comment on… • Reporting of emissions from portable equipment or generating units designated as emergency generators in issued permits • Integration of fuel supplier requirements (e.g. fuel HHVs) w/ both the tier 1 and 2 calculation methodologies • Use of more technology-specific CH4 and N2O emission factors that could be applied in unit-level calculations • Exemption for facilities that have an aggregate combined heat input capacity of less then 30 mmBtu/hr from stationary combustion units