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Are There Facility Specific Requirements?

Yes. They are briefly listed below:

§ 95110. Data Requirements and Calculation Methods for Cement Plants
  1. Cement Plants must report the following annually in metric tonnes:
    • CO2
    • CH4
    • liN20
  2. § 95110 outlines very specific calculation methods for cement plant reporting.
  3. CEMS requirements: Cement plants may use CEMS to calculate CO2, but must still report fuel usage by fuel type. CEMS may not be used to report cement plant emissions of CH4 and N20.
  4. For process reporting, these methodologies rely primarily on the “clinker” based method.

See pages 34-40 of the regulations for specific calculation requirements.

§ 95111 Data Requirements and Calculation Methods for Electricity Generating Facilities, Retail Providers, and Marketers.
  • Electricity Generator and Marketer reporting requirements are extensive and included in pp 41-54. Some Highlights that apply to both generally:
    1. High Heat Value by fuel type, reported in MMBtu per unit of fuel, must be reported. If this data is unavailable, the Operator must report the steam produced in MMBtu. This can be derived by measuring pounds of steam into MMBtu using the calculation method provided in § 95125(h)(1)(B).
    2. Carbon content by fuel type, based on value measured by the operator or the fuel supplier. If provided by the fuel supplier the carbon content must have been acquired using ASTM methodology.
    3. Gases measured are: CO2, CH4, N20, and fugitive HFC from cooling operations, fugitive SF6; SF6 reporting can be aggregated from multiple facilities into one report if these facilities fall under the same operator. CO2 calculations must follow those listed below in part c), while CH4 and N2O calculations must follow those mentioned in part d). In brief, CO2 can be measured via source testing and via CEMS, depending on the type of emission and fuel. N2O and CH4 can always be source tested.
    4. Electricity sold out of state must be reported
    5. Generating units must measure individual fuel type, but operator may aggregate fuel measurements used for all generating units if individual metering is not possible.
  • Electricity Marketer and Retail Provider-specific highlights:
    1. Report in MWh
    2. Power “wheeled” through California
    3. Marketers and retail providers, including government agencies such as WAPA (Western Area Power Administration), must report fugitive SF6 emissions from any transmission and distribution systems, substations, and circuit breakers located in CA.
    4. All out of state Marketers and retail providers supplying in state retail customers must report GHG data reports regarding facilities they operate, regardless of that facilities location.
    5. Power delivered by the Marketer or Retail with final point of delivery in California, regardless of Marketer or Retail Provider’s point in the supply chain, reported in MWh
    6. Power exported by Marketers and Retail Providers in MWh.
  • Retailers have additional requirements than marketers, specified in pp 46-49. (§95111(b)(3)(A)-(S))

  • Calculating CO2 emissions from Stationary Combustion for Electricity Generating Facilities
    1. Natural Gas, Coal or Petroleum Coke, Middle Distillates, Gasoline, Residual Oil, or LPG electricity generating plants currently regulated under 40 CFR 72-78: facilities currently regulated under the EPA’s Acid Rain program that report CO2 emissions data from CEMS must report this data to CARB following EPA guidelines (40 CFR 75). Fuel checks are voluntary when using this method but will likely aid verification.
    2. If the facility combusts Refinery Fuel Gas, Flexigas, or Associated Gas, it may use CEMS or calculation methods in §95113(a)(1)(E).
    3. Landfill Gas or Biogas facilities: may use calculation methods in 95125(c), (d), or CEMS (95125(g)).
    4. Biomass Solids or Municipal Solid Waste: May use CEMS, calculation methods, or source tests according to 95125(h). (Regs also describe sampling methodology, ASTM method D6866-06a, for discerning how much biomass is included within a given sample of emissions when there is a mixture of biomass and other fuels. §95125(h)(2))
    5. CO2 emissions for fuels co-fired: If an operator does not use CEMS to calculate emissions, individual calculations for each fossil fuel used must be reported
    6. Start Up Fuels: if a facility primarily combusts biomass, but uses fossil fuels for startup, shut-down, or malfunction operating periods only, fossil fuel emissions may be reported via calculation, CEMS, or source testing.
  • Calculation of N2O and CH4 from Stationary Combustion:
    • N2O and CH4 can be calculated or measured via source tests. See 95125(b) or source testing requirements for these gases
  • Acid Gas Scrubbers: CO2 from this process should be picked up if a CEMS is used. If not, they must be calculated using the equation supplied in 95111(e)
  • Determining Fugitive SF6 emissions: These emissions are determined according to EPA standards. Basically, operators must subtract the end of year amount of stored SF6 from the beginning year amount
  • Determining Fugitive HFC emissions: Use the same methodology as above. Service logs detailing installation, maintenance, and retiring of units may also be used as specified on pp 52-43, § 95111(g)(1).
  • Determining Fugitive CH4 emissions: Calculated using formula in 95125(j).
  • Determining Fugitive CO2 emissions from Geothermal Generating: Either calculate using method in 95111(i) or source test.
§ 95112. Data Requirement and Calculation Methods for Cogeneration Facilities.

a) GHG Emissions Data Report Requirements for Cogeneration Facilities: Cogeneration Facilities must report a wide variety of data related to their electricity sold, generated, and consumed, as well as their thermal energy production, indirect electricity usage, and distributed emissions (see below for distributed emissions calculations). These are detailed in pp 55-56, section §95112(a) of the regulatory text.

b) Calculation Methods for CO2, N2O, and CH4. These gases utilize the same standards as those outlined in § 95111(c) for CO2, § 95111(e)-(h) for process and fugitive emissions, and § 95125(b) for N2O and CH4.

(b)(4)(A) and (b)(4)(B) describe distributed emissions calculations. (A) deals with topping cycle plants, and (B) deals with bottoming cycle plants. Distributed emissions are CO2 emissions from fuel combustion that turns into various energy outputs, such as thermal energy and electricity generation.

c) Cogeneraton facilities with a nameplate capacity under 10MW may file an abbreviated GHG report

d) outlines calculation methods for this abbreviated report:

1) CO2 may be calculated or measured with a CEMS or source test if using biomass or waste derived fuels

2) N2O, CH4 may be calculated or source tested as per 95125(b).

§ 95113. Data Requirements and Calculation Methods for Petroleum Refineries.

a) The GHG Data Report:

1) Stationary Combustion for CO2: Operators may choose to use CEMS. If not, they may calculate according to the following standards:

A) Refinery Fuel Gas: 95125(d) or 94125(e)

B) Natural Gas and Associated Gas: 95125(c) or (d)

C) Fuel Mixture: 95125(f)

D) Other fuels: 95125 (a),(c),or (d)

E) Low Btu gases: 95125(f) or 95125(d)(3); flexigas uses 95125(d)(3)(A)

2) Stationary Combustion for CH4 and N2O: Must calculate or measure using 95125(b)

3)-10) Lists the various emission calculation methodologies listed under this section for calculating the following types of emissions: Hydrogen Production Plant, Process, Fugitive, Flaring, Electricity Generating, Cogeneration, and Indirect Energy (pp 62) Process Emissions may be measured by CEMS; if not go to b)

b) Calculation of Process Emissions Calculations of process emissions are based on a formula listed in pp 62-63 of the regs.

1)

A) Need to calculate hourly coke burn rate (CR); Factors required: Volumetric Flow Rate (VFR) of exhaust gas before entering emission control system; VFR of air to regenerator; % CO2, % O2, and % CO concentration in regenerator exhaust by dry basis, VFR of O2 enriched air to regenerator, % O2 concentration in O2 enriched air

B) Need to calculate daily coke burn rate

C) CO2 emissions then use daily coke burn rate, among other factors (pp 64)

2) Other catalyst regeneration calculations on pp 64-65 Required factors (generally) are carbon conversion factors and weight fraction of carbon; provided in regulations at above pages

3) Process Vent calculations Require emissions in metric tonnes, vent rates, molar fraction, molecular weight, molar volume conversion, time duration of venting and number of venting events. See. pp 65

4) Asphalt Production

(A) Where they are not already reported to local AQMD as directed in part 95113(d), operators must calculate and report CO2 and CH4 emissions resulting from asphalt blowing activities

5) Sulfur Recovery:

A) Operator must report sulfur recovery units (SRU) according to calculation on pp 66; these calculations require a molecular fraction % of CO2 in sour gas, which is provided in the regs

B) Operators may define their own molecular fraction of % of CO2 in sour gas using source testing

c) Calculation of Fugitive Emissions These are all calculated based on calculations in the regs on pp 67-71. They also depend on local air quality district regulations for allowable components on storage tanks

d) Calculation of Emissions from Flares and Other Control Devices:

1) Generally, operator may calculate CO2 or measure with CEMS as per 95113(a)(1), and must calculate CH4 and N2O according to 95113(a)(2)

2) Operators who are required to report emissions information to local air quality districts must utilize those reporting methods to create calculations according to equations specified in pp 71-73, the basics of which are below:

A) Operators required to report CH4 and NMHC (non methane hydrocarbons) to a local AQMD shall calculate according to equation on pp 71

B) Those subject to Rule 1118, Control of Emissions from Refinery Flares (SCAQMD) must calculate ROG under their rule and utilize the calculation found on pp 72, 95113(d)(2)(B)

C) All others who use flares but are not required to report must use the equation specified in 95113(d)(2)(C) on pp 72.

3) Operators who use some alternative method for destruction of low Btu gases must report using the calculation under 95113(d)(3) on pp 73

§ 95114. Data Requirements and Calculation Methods for Hydrogen Plants

a) Hydrogen Plant Operators must report emissions from the following sources:

1) Fuel and Feedstock Consumption

2) Hydrogen Production

3) Stationary Combustion,

4) Fugitive Emissions,

5) Flaring Emissions,

6) Transferred CO2 and CO,

7) Process Vent Emissions,

8) Sulfur Recovery Process Emissions,

9) Electricity Generating Units,

10) Cogeneration Emissions,

11) Indirect Energy Purchases,

12) Stationary Combustion and Process CO2 Emissions See 95114(b), pp75

b) Calculation of Stationary Combustion and Process Emissions

1) CEMS as specified in 95125(g)(7)

2) Calculations based on Fuel and Feedstock Mass Balance, see 95114(b)(2), pp75

c) Fuel Stationary Combustion and Feedstock Process Emissions May measure with CEMS or calculate, see calc on pp76, 95114(c)(3)(b)

§ 95115. Data Requirements and Calculation Methods for General Stationary Combustion Facilities

a) Any facility that emits above 25,000 metric tonnes of CO2 per year from stationary combustion must report the following:

1) Stationary Combustion Emissions (all metric tonnes):

A) Total CO2 emissions in metric tonnes

1. CO2 emissions from biomass derived fuels in metric tonnes

B) Total CH4 emissions

C) Total N2O emissions

2) Fuels Information:

A) Fuel Consumed by fuel type, reporting in units of million standard cubic feet for gases, gallons, short tons for non-biomass solids, and bone dry short tons for biomass derived solid fuels. Regulations prefer measurement of fuel usage, and in lieu of measurement, calculate using the following: Fuel Consumed = Total Fuel purchases – Total Fuel Sales + Amount Stored at beginning of year – Amount Stored at end of year Btu fuel consumption value can be converted using heat content values provided either

1) by the supplier;

2) measurement;

3) Table 4 of Appendix A in the regs

B) Average annual Carbon Content as a % by fuel type, if measured or provided by the fuel provider

C) Average annual high heat value by fuel type if measured or provided by fuel supplier, reporting in units of MMBtu per fuel unit as specified in 95115(a)(2)(A)

3) Indirect Energy Usage

A) Electricity purchases from each electricity provider (kWh)

B) Steam, heat, and cooling purchases from each energy provider

b) Calculation of CO2 emissions

1) Operators of crude oil or natural gas production facility identified with NAICS code 211111 (two-eleven-eleven-one) shall report CO2 emissions from stationary combustion according to 95215(c), (d), and (f). (All calculations)

A) Natural gas and associated gas  95125(c) or (d)

B) For low Btu gases  95113 (d)(3) or 95125(f)

C) For fuel mixtures 95125(f)

2) For all other facilities, operator shall measure and report CO2 emissions from stationary combustion using one of the following methods:

A) CEMS

B) 95125(a)

C) 95125(c),(d), or (h) , presumably includes source testing for biomass and waste derived fuels under 95125 (h)(3)

D) If not using CEMS and you are co-firing two or more types of fuels, you must select a method from 95115(b)(1)-(2) to separately report each fuel type. If you use part biomass, use 95125(h)(2) to determine the proportion of CO2 that is the result of biomass emissions.

c) Calculation of N2O and CH4 emissions: Calculate or measure using 95125(b)

d) Electricity Generating Units: If the operator has an electricity generating unit that would come under the requirements of this article (have a nameplate generating capacity equal to or greater than 1 MW, and emit greater than or equal to 2,500 metric tonnes of CO2 after 2007) then they must report it as per §95111

e) Cogeneration: If the operator has a cogeneration facility that would otherwise come under the requirements of this article, (same as electricity generating units above) they must report according to §95112

f) Indirect Energy Usage: Operators of general stationary combustion facilities shall calculate indirect electricity and thermal energy purchased or acquired and consumed as specified in sections 95125(k)-(l)