pulping liquor that enters the chemical recovery furnace or chemical
recovery combustion unit.

Spent pulping liquor means the residual liquid collected from on-site
pulping operations at chemical pulp facilities that is subsequently
fired in chemical recovery furnaces at kraft and soda pulp facilities or
chemical recovery combustion units at sulfite or semi-chemical pulp
facilities.

Standard conditions or standard temperature and pressure (STP) means 68
degrees Fahrenheit and 14.7 pounds per square inch absolute.

Steam reforming means a catalytic process that involves a reaction
between natural gas or other light hydrocarbons and steam.  The result
is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.

Still gas means any form or mixture of gases produced in refineries by
distillation, cracking, reforming, and other processes.  The principal
constituents are methane, ethane, ethylene, normal butane, butylene,
propane, and propylene.

Storage tank means a vessel (excluding sumps) that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and that is constructed entirely
of non-earthen materials (e.g., wood, concrete, steel, plastic) that
provide structural support.

Sulfur recovery plant means all process units which recover sulfur or
produce sulfuric acid from hydrogen sulfide (H2S) and/or sulfur dioxide
(SO2) from a common source of sour gas at a petroleum refinery.  The
sulfur recovery plant also includes sulfur pits used to store the
recovered sulfur product, but it does not include secondary sulfur
storage vessels or loading facilities downstream of the sulfur pits.
For example, a Claus sulfur recovery plant includes:  reactor furnace
and waste heat boiler, catalytic reactors, sulfur pits, and, if present,
oxidation or reduction control systems, or incinerator, thermal
oxidizer, or similar combustion device.  Multiple sulfur recovery units
are a single sulfur recovery plant only when the units share the same
source of sour gas.  Sulfur recovery units that receive source gas from
completely segregated sour gas treatment systems are separate sulfur
recovery plants.

Supplemental fuel means a fuel burned within a petrochemical process
that is not produced within the process itself.

Supplier means a producer, importer, or exporter of a fossil fuel or an
industrial greenhouse gas.

Taconite iron ore processing means an industrial process that separates
and concentrates iron ore from taconite, a low grade iron ore, and heats
the taconite in an indurating furnace to produce taconite pellets that
are used as the primary feed material for the production of iron in
blast furnaces at integrated iron and steel plants.

TAME means tertiary amyl methyl ether, (CH3)2(C2H5)COCH3).

Trace concentrations means concentrations of less than 0.1 percent by
mass of the process stream.

Transform means to use and entirely consume (except for trace
concentrations) nitrous oxide or fluorinated GHGs in the manufacturing
of other chemicals for commercial purposes.  Transformation does not
include burning of nitrous oxide.

Transshipment means the continuous shipment of nitrous oxide or a
fluorinated GHG from a foreign state of origin through the United States
or its territories to a second foreign state of final destination, as
long as the shipment does not enter into United States jurisdiction.  A
transshipment, as it moves through the United States or its territories,
cannot be re-packaged, sorted or otherwise changed in condition.

Trona means the raw material (mineral) used to manufacture soda ash;
hydrated sodium bicarbonate carbonate (e.g.Na2CO3.NaHCO3.2H2O).

Ultimate analysis means the determination of the percentages of carbon,
hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in
the gaseous products and ash after the complete combustion of a sample
of an organic material.

Unfinished oils are all oils requiring further processing, except those
requiring only mechanical blending.

United States means the 50 states, the District of Columbia, and U.S.
possessions and territories.

Unstabilized crude oil means, for the purposes of this part, crude oil
that is pumped from the well to a pipeline or pressurized storage vessel
for transport to the refinery without intermediate storage in a storage
tank at atmospheric pressures.  Unstabilized crude oil is characterized
by having a true vapor pressure of 5 pounds per square inch absolute
(psia) or greater.

Valve means any device for halting or regulating the flow of a liquid or
gas through a passage, pipeline, inlet, outlet, or orifice; including,
but not limited to, gate, globe, plug, ball, butterfly and needle
valves.

Vegetable Oil means oils extracted from vegetation that are generally
used as a feedstock in making biodiesel.

Volatile solids are the organic material in livestock manure and consist
of both biodegradable and non-biodegradable fractions.

Waelz kiln means an inclined rotary kiln in which zinc–containing
materials are charged together with a carbon reducing agent (e.g.,
petroleum coke, metallurgical coke, or anthracite coal).

Waste oil means a petroleum-derived or synthetically-derived oil whose
physical properties have changed as a result of storage, handling or
use, such that the oil cannot be used for its original purpose.  Waste
oil consists primarily of automotive oils (e.g., used motor oil,
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial
oils (e.g., industrial engine oils, metalworking oils, process oils,
industrial grease, etc).

Waxes means a solid or semi-solid material at 77 °F consisting of a
mixture of hydrocarbons obtained or derived from petroleum fractions, or
through a Fischer-Tropsch type process, in which the straight chained
paraffin series predominates.  This includes all marketable wax, whether
crude or refined, with a congealing point between 80 (or 85) and 240 °F
and a maximum oil content of 50 weight percent.

Wood residuals means wood waste recovered from three principal sources:
municipal solid waste (MSW); construction and demolition debris; and
primary timber processing. Wood residuals recovered from MSW include
wooden furniture, cabinets, pallets and containers, scrap lumber (from
sources other than construction and demolition activities), and urban
tree and landscape residues.  Wood residuals from construction and
demolition debris originate from the construction, repair, remodeling
and demolition of houses and non-residential structures.  Wood residuals
from primary timber processing include bark, sawmill slabs and edgings,
sawdust, and peeler log cores.  Other sources of wood residuals include,
but are not limited to, railroad ties, telephone and utility poles, pier
and dock timbers, wastewater process sludge from paper mills, and
logging residues.

Wool fiberglass means fibrous glass of random texture, including
fiberglass insulation, and other products listed in NAICS 327993.

You means an owner or operator subject to Part 98.

Zinc smelters means a facility engaged in the production of zinc metal,
zinc oxide, or zinc alloy products from zinc sulfide ore concentrates,
zinc calcine, or zinc-bearing scrap and recycled materials through the
use of pyrometallurgical techniques involving the reduction and
volatization of zinc-bearing feed materials charged to a furnace.

§98.7  What standardized methods are incorporated by reference into
this part?

The materials listed in this section are incorporated by reference in
the corresponding sections noted.  These incorporations by reference
were approved by the Director of Federal Register in accordance with 5
U.S.C. 552(a) and 1 CFR part 51.  These materials are incorporated as
they exist on the date of approval, and a notice of any change in the
materials will be published in the Federal Register.  The materials are
available for purchase at the corresponding address in this section.
The materials are available for inspection at the EPA Docket Center,
Public Reading Room, EPA West Building, Room 3334, 1301 Constitution
Avenue, NW, Washington, DC, phone<PHONE_NUMBER> and at the National
Archives and Records Administration (NARA).  For information on the
availability of this material at NARA, call<PHONE_NUMBER>, or go to:
http://www.archives.gov/federal_register/code_of_federal_regulations/ibr
_ locations.html.

(a)  The following material is available for purchase from the
Association of Fertilizer and Phosphate Chemists (AFPC), P. O. Box 1645,
Bartow, Florida 33831, http://afpc.net.

(1)  Phosphate Mining States Methods Used and Adopted by the Association
of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009 -
Version 1.9, incorporation by reference (IBR) approved for §98.264(a)
and §98.264(b).

(b)  [Reserved]The following material is available for purchase from the
American Gas Association (AGA), 400 North Capitol Street, N.W., 4th
Floor, Washington, DC 20001,<PHONE_NUMBER>, http://www.aga.org.

(1)  AGA Report No. 3 Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids Part 1: General Equations & Uncertainty Guidelines
(1990), incorporation by reference (IBR) approved for §98.34(b) and
§98.244(b).(2)  AGA Report No. 3 Orifice Metering of Natural Gas and
Other Related Hydrocarbon Fluids Part 2: Specification and Installation
Requirements (2000), IBR approved for §98.34(b) and §98.244(b). (3)
AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003),
IBR approved for §98.244(b) and §98.254(c).(4)  AGA Transmission
Measurement Committee Report No. 7 Measurement of Natural Gas by Turbine
Meter (2006)/February, IBR approved for §98.34(b) and §98.244(b

(c)  The following material is available for purchase from the ASM
International, 9639 Kinsman Road, Materials Park, OH 44073, (440)
338-5151, http://www.asminternational.org.

(1)  ASM CS-104 UNS No. G10460 - Alloy Digest April 1985 (Carbon Steel
of Medium Carbon Content), incorporation by reference (IBR) approved for
§98.174(b).

(2)  [Reserved]

(d)  The following material is available for purchase from the American
Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY
10016-5990,<PHONE_NUMBER>, http://www.asme.org.

(1)  ASME MFC-3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved
for §98.34(b), §98.244(b), §98.254(c), §98.344(c), and §98.364(e).

(2)  ASME MFC-4M–1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for §98.34(b),  §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(3)  [Reserved]ASME MFC-5M–1985 (Reaffirmed 1994) Measurement of
Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters,
IBR approved for §98.34(b) and §98.244(b).

(4)  ASME MFC-6M–1998 Measurement of Fluid Flow in Pipes Using Vortex
Flowmeters, IBR approved for §98.34(b),  §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(5)  ASME MFC-7M–1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, IBR approved for §98.34(b),
§98.244(b), §98.254(c), §98.344(c), and §98.364(e).

(6)  [Reserved]ASME MFC-9M–1988 (Reaffirmed 2001) Measurement of
Liquid Flow in Closed Conduits by Weighing Method, IBR approved for
§98.34(b) and §98.244(b).

(7)  ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis
Mass Flowmeters, IBR approved for §98.244(b), §98.254(c), and
§98.344(c).

(8)  ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for §98.244(b), §98.254(c),
§98.344(c), and §98.364(e).

(9)  [Reserved]ASME MFC-16-2007 Measurement of Liquid Flow in Closed
Conduits with Electromagnetic Flowmeters, IBR approved for §98.244(b).

(10)  ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area
Meters, IBR approved for §98.244(b), §98.254(c),§98.344(c), and
§98.364(e).

(11)  [Reserved]ASME MFC-22-2007 Measurement of Liquid by Turbine
Flowmeters, IBR approved for §98.244(b).

(e)  The following material is available for purchase from the American
Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959,<PHONE_NUMBER>,
http://www.astm.org.

(1)  ASTM C25-06 Standard Test Method for Chemical Analysis of
Limestone, Quicklime, and Hydrated Lime, incorporation by reference
(IBR) approved for §98.114(b), §98.174(b), §98.184(b), §98.194(c),
and §98.334(b).

(2)  ASTM C114-09 Standard Test Methods for Chemical Analysis of
Hydraulic Cement, IBR approved for §98.84(a), §98.84(b), and
§98.84(c).

(3)  ASTM D235-02 (Reapproved 2007) Standard Specification for Mineral
Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR
approved for §98.6.

(4)  ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved
for §98.34(a) and §98.254(e).

(5)  ASTM D388-05 Standard Classification of Coals by Rank, IBR approved
for §98.6.

(6)  ASTM D910-07a Standard Specification for Aviation Gasolines, IBR
approved for §98.6.

(7)  ASTM D1298-99 (Reapproved 2005) Standard Test Method for Density,
Relative Density (Specific Gravity), or API Gravity of Crude Petroleum
and Liquid Petroleum Products by Hydrometer Method, IBR approved for
§98.33(a).[Reserved]

(8)  ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific
(Heating) Value of Gases in Natural Gas Range by Continuous Recording
Calorimeter, IBR approved for §98.34(a) and §98.254(e).

(9)  ASTM D1836-07 Standard Specification for Commercial Hexanes, IBR
approved for §98.6.

(10)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for §98.34(b), §98.74(c),
§98.164(b), §98.244(b), §98.254(d), and §98.344(b).

(11)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography, IBR approved for §98.34(b),
§98.74(c), §98.164(b), §98.254(d), §98.344(b), and §98.364(c).

(12)  ASTM D2013-07 Standard Practice for Preparing Coal Samples for
Analysis, IBR approved for §98.164(b).

(13)  ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross
Sample of Coal, IBR approved for §98.164(b).

(14)  ASTM D2502-04 Standard Test Method for Estimation of Mean Relative
Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR
approved for §98.34(b) and §98.74(c).

(15)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure, IBR approved for §98.34(b) and
§98.74(c).

(16)  ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene
by Gas Chromatography, IBR approved for §98.244(b).

(17)  ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis
of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and
Carbon Dioxide by Gas Chromatography, IBR approved for §98.164(b).

(18)  ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate
Analysis of Coal and Coke, IBR approved for §98.74(c), §98.164(b),
§98.244(b), §98.254(i), §98.284(c), §98.284(d), §98.314(c),
§98.314(d), and §98.314(f).

(19)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method, IBR approved for §98.34(b),
§98.74(c), and §98.164(b).

(20)  ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and Relative Density of Gaseous
Fuels, IBR approved for §98.34(a) and §98.254(e).

(21)  ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and
Minor Elements in Combustion Residues from Coal Utilization Processes,
IBR approved for §98.144(b).

(22)  ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum
and Petroleum Products, IBR approved for §98.164(b).

(23)  ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum Products, IBR approved for
§98.164(b).

(24)  ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for §98.34(a) and §98.254(e).

(25)  ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating
Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR
approved for §98.34(a) and §98.254(e).

(26)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants, IBR approved for §98.34(b),
§98.74(c), §98.164(b), §98.244(b), and §98.254(i).

(27)  ASTM D5373-08 Standard Test Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR
approved for §98.34(b), §98.74(c), §98.114(b), §98.164(b),
§98.174(b), §98.184(b), §98.244(b), §98.254(i), §98.274(b),
§98.284(c), §98.284(d), §98.314(c), §98.314(d), §98.314(f), and
§98.334(b).

(28)  [Reserved]ASTM D5865-07a Standard Test Method for Gross Calorific
Value of Coal and Coke, IBR approved for §98.34(a).

(29)  ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of
Process Vents With a Portable Gas Chromatograph, IBR approved for
§98.244(b).

(30)  ASTM D6348-03 Standard Test Method for Determination of Gaseous
Compounds by Extractive Direct Interface Fourier Transform Infrared
(FTIR) Spectroscopy, IBR approved for §98.54(b), and §98.224(b), and
§98.414(n).

(31)  ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, IBR
approved for §98.164(b).

(32)  ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels, IBR approved for §98.6.

(33)  ASTM D6866-08 Standard Test Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon
Analysis, IBR approved for §98.33(e), §98.34(d), §98.34(e), and
§98.36(e).

(34)  ASTM D6883-04 Standard Practice for Manual Sampling of Stationary
Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for
§98.164(b).

(35)  ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of
Coal, IBR approved for §98.164(b).

(36)  ASTM D7459-08 Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved
for §98.33(e), §98.34(d), §98.34(e), and §98.36(e).

(37)  ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for
Analysis of Soda Ash (Sodium Carbonate), IBR approved for §98.294(a)
and §98.294(b).

(38)  ASTM E1019-08 Standard Test Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys
by Various Combustion and Fusion Techniques, IBR approved for
§98.174(b).

(39)  ASTM E1747-95 (Reapproved 2005) Standard Guide for Purity of
Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved
for 98.424(b).

(40)  ASTM E1915-07a Standard Test Methods for Analysis of Metal Bearing
Ores and Related Materials by Combustion Infrared-Absorption
Spectrometry, IBR approved for §98.174(b).

(41)  ASTM E1941-04 Standard Test Method for Determination of Carbon in
Refractory and Reactive Metals and Their Alloys, IBR approved for
§98.114(b), §98.184(b), §98.334(b).

(42)  ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR
approved for §98.164(b), §98.244(b), and §98.254(d), and §98.344(b).

(43)  ASTM D2503-92(2007) Standard Test Method for Relative Molecular
Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of
Vapor Pressure, IBR approved for §98.254(d).

(44)  ASTM D2593-93(2009) Standard Test Method for Butadiene Purity and
Hydrocarbon Impurities by Gas Chromatography, IBR approved for
§98.244(b).

(f)  The following material is available for purchase from the Gas
Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma
74143,<PHONE_NUMBER>, http://www.gasprocessors.com.

(1)  [Reserved]GPA 2172-09 Calculation of Gross Heating Value, Relative
Density, Compressibility and Theoretical Hydrocarbon Liquid Content for
Natural Gas Mixtures for Custody Transfer, IBR approved for §98.34(a).

(2)  GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures
by Gas Chromatography, IBR approved for §98.34(a), §98.164(b),
§98.254(d), and §98.344(b).

(g)  The following material is available for purchase from the
International Standards Organization (ISO), 1, ch. de la Voie-Creuse,
Case postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11,
http://www.iso.org/iso/home.htm.

(1)  ISO 3170: Petroleum liquids—Manual sampling - Third Edition
2004-02-01, IBR approved for §98.164(b).

(2)  ISO 3171: Petroleum Liquids—Automatic pipeline sampling - Second
Edition 1988-12-01, IBR approved for §98.164(b).

(3)  [Reserved]ISO 8316: Measurement of Liquid Flow in Closed Conduits -
Method by Collection of the Liquid in a Volumetric Tank (1987-10-01) -
First Edition, IBR approved for §98.244(b).

(4)  ISO/TR 15349-1: 1998, Unalloyed steel—Determination of low carbon
content. Part 1: Infrared absorption method after combustion in an
electric resistance furnace (by peak separation) (1998-10-15) - First
Edition, IBR approved for §98.174(b).

(5)  ISO/TR 15349-3: 1998, Unalloyed steel—Determination of low carbon
content. Part 3: Infrared absorption method after combustion in an
electric resistance furnace (with preheating) (1998-10-15) - First
Edition, IBR approved for §98.174(b).

(h)  The following material is available for purchase from the National
Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington,
Virginia 22203,<PHONE_NUMBER>, http://www.lime.org.

(1)  CO2 Emissions Calculation Protocol for the Lime Industry—English
Units Version, February 5, 2008 Revision—National Lime Association,
incorporation by reference (IBR) approved for §98.194(c) and
§98.194(e).

(i)  The following material is available for purchase from the National
Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop
1070, Gaithersburg, MD 20899-1070,<PHONE_NUMBER>,
http://www.nist.gov/index.html.

(1)  Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation
by reference (IBR) approved for §98.244(b), §98.254(h), and
§98.344(a).

(j)  The following material is available for purchase from the Technical
Association of the Pulp and Paper Industry (TAPPI), 15 Technology
Parkway South, Norcross, GA 30092,<PHONE_NUMBER>, http://www.tappi.org.

(1)  T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by
reference (IBR) approved for §98.276(c) and §98.277(d).

(2)  T684 om-06 Gross Heating Value of Black Liquor, TAPPI,
incorporation by reference (IBR) approved for §98.274(b).

(k)  The following material is available from the U.S. Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C. 20460,
(202) 272-0167, www.epa.gov.

(1)  Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003.

§98.8  What are the compliance and enforcement provisions of this part?

Any violation of any requirement of this part shall be a violation of
the Clean Air Act, including section 114 (42 U.S.C. §7414).  A
violation includes but is not limited to failure to report GHG
emissions, failure to collect data needed to calculate GHG emissions,
failure to continuously monitor and test as required, failure to retain
records needed to verify the amount of GHG emissions, and failure to
calculate GHG emissions following the methodologies specified in this
part.  Each day of a violation constitutes a separate violation.

§98.9  Addresses.

All requests, notifications, and communications to the Administrator
pursuant to this part, other than submittal of the annual GHG report,
shall be submitted to the following address:

(a)  For U.S. mail.

Director, Climate Change Division

1200 Pennsylvania Ave., NW

Mail Code: 6207J

Washington, DC 20460

(b)  For package deliveries.

Director, Climate Change Division

1310 L St, NW

Washington, DC 20005

Table A-1 of Subpart A—Global Warming Potentials (100-Year Time
Horizon)

Name	CAS #	Chemical formula	Global warming potential (100 yr.)

Carbon dioxide	124-38-9	CO2	1

Methane	74-82-8	CH4	21

Nitrous oxide	10024-97-2	N2O	310

HFC-23	75-46-7	CHF3	11,700

HFC-32	75-10-5	CH2F2	650

HFC-41	593-53-3	CH3F	150

HFC-125	354-33-6	C2HF5	2,800

HFC-134	359-35-3	C2H2F4	1,000

HFC-134a	811-97-2	CH2FCF3	1,300

HFC-143	430-66-0	C2H3F3	300

HFC-143a	420-46-2	C2H3F3	3,800

HFC-152	624-72-6	CH2FCH2F	53

HFC-152a	75-37-6	CH3CHF2	140

HFC-161	353-36-6	CH3CH2F	12

HFC-227ea	431-89-0	C3HF7	2,900

HFC-236cb	677-56-5	CH2FCF2CF3	1,340

HFC-236ea	431-63-0	CHF2CHFCF3	1,370

HFC-236fa	690-39-1	C3H2F6	6,300

HFC-245ca	679-86-7	C3H3F5	560

HFC-245fa	460-73-1	CHF2CH2CF3	1,030

HFC-365mfc	406-58-6	CH3CF2CH2CF3	794

HFC-43-10mee	138495-42-8	CF3CFHCFHCF2CF3	1,300

Sulfur hexafluoride	2551-62-4	SF6	23,900

Trifluoromethyl sulphur pentafluoride	373-80-8	SF5CF3	17,700

Nitrogen trifluoride	7783-54-2	NF3	17,200

PFC-14 (Perfluoromethane)	75-73-0	CF4	6,500

PFC-116 (Perfluoroethane)	76-16-4	C2F6	9,200

PFC-218 (Perfluoropropane)	76-19-7	C3F8	7,000

Perfluorocyclopropane	931-91-9	c-C3F6	17,340

PFC-3-1-10 (Perfluorobutane)	355-25-9	C4F10	7,000

Perfluorocyclobutane	115-25-3	c-C4F8	8,700

PFC-4-1-12 (Perfluoropentane)	678-26-2	C5F12	7,500

PFC-5-1-14

(Perfluorohexane)	355-42-0	C6F14	7,400

PFC-9-1-18	306-94-5	C10F18	7,500

HCFE-235da2 (Isoflurane)	26675-46-7	CHF2OCHClCF3  	350

HFE-43-10pccc (H-Galden 1040x)	E1730133	CHF2OCF2OC2F4OCHF2  	1,870

HFE-125  	3822-68-2	CHF2OCF3  	14,900

HFE-134  	1691-17-4	CHF2OCHF2  	6,320

HFE-143a	421-14-7	CH3OCF3  	756

HFE-227ea  	2356-62-9	CF3CHFOCF3  	1,540

HFE-236ca12 (HG-10)	78522-47-1	CHF2OCF2OCHF2  	2,800

HFE-236ea2 (Desflurane)	57041-67-5	CHF2OCHFCF3	989

HFE-236fa	20193-67-3	CF3CH2OCF3  	487

HFE-245cb2	22410-44-2	CH3OCF2CF3  	708

HFE-245fa1	84011-15-4	CHF2CH2OCF3  	286

HFE-245fa2	1885-48-9	CHF2OCH2CF3  	659

HFE-254cb2	425-88-7	CH3OCF2CHF2  	359

HFE-263fb2	460-43-5	CF3CH2OCH3	11

HFE-329mcc2	67490-36-2	CF3CF2OCF2CHF2  	919

HFE-338mcf2	156053-88-2	CF3CF2OCH2CF3  	552

HFE-338pcc13 (HG-01) 	188690-78-0	CHF2OCF2CF2OCHF2  	1,500

HFE-347mcc3	28523-86-6	CH3OCF2CF2CF3  	575

HFE-347mcf2	E1730135	CF3CF2OCH2CHF2  	374

HFE-347pcf2	406-78-0	CHF2CF2OCH2CF3  	580

HFE-356mec3	382-34-3	CH3OCF2CHFCF3  	101

HFE-356pcc3	160620-20-2	CH3OCF2CF2CHF2  	110

HFE-356pcf2	E1730137	CHF2CH2OCF2CHF2  	265

HFE-356pcf3	35042-99-0	CHF2OCH2CF2CHF2  	502

HFE-365mcf3	378-16-5	CF3CF2CH2OCH3	11

HFE-374pc2	512-51-6	CH3CH2OCF2CHF2	557

HFE-449sl (HFE-7100)

Chemical blend	163702-07-6

163702-08-7	C4F9OCH3

(CF3)2CFCF2OCH3	297

HFE-569sf2 (HFE-7200)

Chemical blend	163702-05-4

163702-06-5	C4F9OC2H5

(CF3)2CFCF2OC2H5	59

Sevoflurane	28523-86-6	CH2FOCH(CF3)2	345

HFE-356mm1	13171-18-1	(CF3)2CHOCH3	27

HFE-338mmz1	26103-08-2	CHF2OCH(CF3)2	380

(Octafluorotetramethy-lene)hydroxymethyl group 	NA	X-(CF2)4CH(OH)-X	73

HFE-347mmy1	22052-84-2	CH3OCF(CF3)2	343

Bis(trifluoromethyl)-methanol  	920-66-1	(CF3)2CHOH	195

2,2,3,3,3-pentafluoropropanol  	422-05-9	CF3CF2CH2OH	42

PFPMIE  	NA	CF3OCF(CF3)CF2OCF2OCF3  	10,300

NA = not available

Table A-2 of Subpart A—Units of Measure Conversions.

To convert from	To	Multiply by

Kilograms (kg)	Pounds (lbs)	2.20462

Pounds (lbs)	Kilograms (kg)	0.45359

Pounds (lbs)	Metric tons	4.53592 x 10-4

Short tons	Pounds (lbs)	2,000

Short tons	Metric tons	0.90718

Metric tons	Short tons	1.10231

Metric tons	Kilograms (kg)	1,000

Cubic meters (m3)	Cubic feet (ft3)	35.31467

Cubic feet (ft3)	Cubic meters (m3)	0.028317

Gallons (liquid, US)	Liters (l)	3.78541

Liters (l)	Gallons (liquid, US)	0.26417

Barrels of Liquid Fuel (bbl)	Cubic meters (m3)	0.15891

Cubic meters (m3)	Barrels of Liquid Fuel (bbl)	6.289

Barrels of Liquid Fuel (bbl)	Gallons (liquid, US)	42

Gallons (liquid, US)	Barrels of Liquid Fuel (bbl)	0.023810

Gallons (liquid, US)	Cubic meters (m3)	0.0037854

Liters (l)	Cubic meters (m3)	0.001

Feet (ft)	Meters (m)	0.3048

Meters (m)	Feet (ft)	3.28084

Miles (mi)	Kilometers (km)	1.60934

Kilometers (km)	Miles (mi)	0.62137

Square feet (ft2)	Acres	2.29568 x 10-5

Square meters (m2)	Acres	2.47105 x 10-4

Square miles (mi2)	Square kilometers (km2)	2.58999

Degrees Celsius (ºC)	Degrees Fahrenheit (ºF)	ºC = (5/9) x ( ºF-32)

Degrees Fahrenheit (ºF)	Degrees Celsius (ºC)	ºF = (9/5) x ºC + 32

Degrees Celsius (ºC)	Kelvin (K)	K = ºC + 273.15

Kelvin (K)	Degrees Rankine (ºR)	1.8

Joules	Btu	9.47817 x 10-4

Btu	MMBtu	1 x 10-6

Pascals (Pa)	Inches of Mercury (in Hg)	2.95334 x 10-4

Inches of Mercury (inHg)	Pounds per square inch (psi)	0.49110

Pounds per square inch (psi)	Inches of Mercury (in Hg)	2.03625

Subpart C—General Stationary Fuel Combustion Sources

§98.30  Definition of the source category.

(a)  Stationary fuel combustion sources are devices that combust solid,
liquid, or gaseous fuel, generally for the purposes of producing
electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional  use, or reducing the volume of
waste by removing combustible matter.  Stationary fuel combustion
sources include, but are not limited to, boilers, simple and
combined-cycle combustion turbines, engines, incinerators, and process
heaters.

(b)  This source category does not include:

(1)  Portable equipment, as defined in §98.6.

(2)  Emergency generators and emergency equipment, as defined in §98.6.

(3)  Irrigation pumps at agricultural operations.

(4)  Flares, unless otherwise required by provisions of another subpart
of 40 CFR part 98this part to use methodologies in this subpart.

(5)  Electricity generating units that are subject to subpart D of this
part.

(c)  For a unit that combusts hazardous waste (as defined in 40 CFR
§261.3 of this chapter), reporting of GHG emissions is not required
unless either of the following conditions apply:

(1)  Continuous emission monitors (CEMS) are used to quantify CO2 mass
emissions.

(2)  Any fuel listed in Table C-1 of this subpart is also combusted in
the unit.  In this case, report GHG emissions from combustion of all
fuels listed in Table C-1 of this subpart.

(d)  You are not required to report GHG emissions from pilot lights.  A
pilot light is a small permanent auxiliary flame that ignites the burner
of a combustion device when the control valve opens.

§98.31  Reporting threshold.

You must report GHG emissions under this subpart if your facility
contains one or more stationary fuel combustion sources and the facility
meets the applicability requirements of either §§98.2(a)(1),
98.2(a)(2), or 98.2(a)(3).

§98.32  GHGs to report.

You must report CO2, CH4, and N2O mass emissions from each stationary
fuel combustion unit, except as otherwise indicated in this subpart.

§98.33  Calculating GHG emissions.

You must calculate CO2 emissions according to paragraph (a) of this
section, and calculate CH4 and N2O emissions according to paragraph (c)
of this section.

(a)  CO2 emissions from fuel combustion.  Calculate CO2 mass emissions
by using one of the four calculation methodologies in this paragraphs
(a)(1) through (a)(4) of this section, subject to the applicable
conditions, requirements, and restrictions set forth in paragraph (b) of
this section.  Alternatively, for units that meet the conditions of
paragraph (a)(5) of this section, you may use CO2 mass emissions
calculation methods from part 75 of this chapter, as described in
paragraph (a)(5) of this section.  If you co-fire For units that combust
both biomass fuels with and fossil fuels, you must calculate and report
CO2 emissions from the combustion of biomass separately using the
methods in paragraph (e) of this section, except as otherwise provided
in paragraphs (a)(5)(iv) and (e) of this section and in §98.36(d).

(1)  Tier 1 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each type of fuel by using Equation C-1 or C-1a of this
section (as applicable).

(i)  Use Equation C-1 except when natural gas billing records are used
to quantify fuel usage and gas consumption is expressed in units of
therms.  In that case, use Equation C-1a.

 	(Eq. C-1)

Where:

CO2 	=	Annual CO2 mass emissions for the specific fuel type (metric
tons).

Fuel	=	Mass or volume of fuel combusted per year, from company records
as defined in §98.6 (express mass in short tons for solid fuel, volume
in standard cubic feet for gaseous fuel, and volume in gallons for
liquid fuel).

HHV	=	Default high heat value of the fuel, from Table C-1 of this
subpart (mmBtu per mass or mmBtu per volume, as applicable).

EF	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(ii)  If natural gas consumption is obtained from billing records and
fuel usage is expressed in therms, use Equation C-1a.

 	(Eq. C-1a)

Where:

CO2 	=	Annual CO2 mass emissions from natural gas combustion (metric
tons).

Gas	=	Annual natural gas consumption, from billing records (therms).

EF	=	Fuel-specific default CO2 emission factor for natural gas, from
Table C-1 of this subpart    (kg CO2/mmBtu).

0.1	=	Conversion factor from therms to mmBtu

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(2)  Tier 2 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each type of fuel by using either Equation C2a or C2c of
this section, as appropriate.

(i)  Equation C-2a of this section applies to any type of fuel listed in
Table C-1 of the subpart, except for municipal solid waste (MSW).  For
MSW combustion, use Equation C-2c of this section.

 	(Eq. C-2a)

Where:

CO2  	=	Annual CO2 mass emissions for a specific fuel type (metric
tons).

Fuel		=	Mass or volume of the fuel combusted during the year, from
company records as defined in §98.6 (express mass in short tons for
solid fuel, volume in standard cubic feet for gaseous fuel, and volume
in gallons for liquid fuel).

HHV	=	Annual average high heat value of the fuel from all valid samples
for the year (mmBtu per mass or volume).  The average HHV shall be
calculated according to the requirements of paragraph (a)(2)(ii) of this
section.

EF 	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(ii)  The minimum number of HHV samples required sampling frequency for
determining the annual average HHV is specified (e.g., monthly,
quarterly, semi-annually, or by lot) is specified in §98.34.  The
method for computing the annual average HHV is a function of unit size
and how frequently you perform or receive from the fuel supplier the
results of fuel sampling for HHV.  The method is specified in paragraph
(a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

(A)  If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average HHV shall
be calculated using Equation C-2b of this section.  If multiple HHV
determinations are made in any month, average the values for the month
arithmetically.

 	(Eq. C-2b)

Where:

(HHV)annual =	Weighted annual average high heat value of the fuel (mmBtu
per mass or volume).

(HHV)i	=	HMeasured high heat value of the fuel, for month “i”, or,
if applicable, an appropriate substitute data value (mmBtu per mass or
volume).

(Fuel)i	=	Mass or volume of the fuel combusted during month “i,”
from company records (express mass in short tons for solid fuel, volume
in standard cubic feet for gaseous fuel, and volume in gallons for
liquid fuel).

n		=	Number of months in the year that the fuel is burned in the unit.

(B)  If the results of fuel sampling are received less frequently than
monthly, or, for a unit with a maximum rated heat input capacity less
than 100 mmBtu/hr (or a group of such units) regardless of the HHV
sampling frequency, then the annual average HHV shall be computed as the
arithmetic average HHV for all values for the year (including valid
samples and substitute data values under §98.35).

(iii)  For units that combust municipal solid waste (MSW) and that
produce steam, use Equation C-2c of this section.  Equation C-2c of this
section may also be used for any other solid fuel listed in Table C-1 of
this subpart provided that steam is generated by the unit.

 	(Eq. C-2c)

Where:

CO2  	=	Annual CO2 mass emissions from MSW or solid fuel combustion
(metric tons).

Steam	=	Total mass of steam generated by MSW or solid fuel combustion
during the reporting year (lb steam).

B	=	Ratio of the boiler’s maximum rated heat input capacity to its
design rated steam output capacity (mmBtu/lb steam).

EF 	=	Fuel-specific default CO2 emission factor, from Table C-1 of this
subpart (kg CO2/mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(3)  Tier 3 Calculation Methodology.  Calculate the annual CO2 mass
emissions for each fuel by using either Equation C3, C4, or C5 of this
section, as appropriate.

(i)  For a solid fuel, use Equation C-3 of this section.

 	(Eq. C-3)

Where:

CO2 	=	Annual CO2 mass emissions from the combustion of the specific
solid fuel (metric tons).

Fuel 	=	Annual mass of the solid fuel combusted, from company records as
defined in §98.6 (short tons).

CC 	=	Annual average carbon content of the solid fuel (percent by
weight, expressed as a decimal fraction, e.g., 95% = 0.95).  The annual
average carbon content shall be determined using the same procedures as
specified for HHV in paragraph (a)(2)(ii) of this section.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.91	=	Conversion factor from short tons to metric tons.

(ii)  For a liquid fuel, use Equation C-4 of this section.

 	(Eq. C-4)

Where:

CO2 	=	Annual CO2 mass emissions from the combustion of the specific
liquid fuel (metric tons).

Fuel	=	Annual volume of the liquid fuel combusted (gallons). The volume
of fuel combusted must be measured directly, using fuel flow meters
calibrated according to §98.3(i).  Fuel billing meters may be used for
this purpose.  Tank drop measurements may also be used.

CC 	=	Annual average carbon content of the liquid fuel (kg C per gallon
of fuel).  The annual average carbon content shall be determined using
the same procedures as specified for HHV in paragraph (a)(2)(ii) of this
section.

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(iii)  For a gaseous fuel, use Equation C-5 of this section.

 	(Eq. C-5)

Where:

CO2 	=	Annual CO2 mass emissions from combustion of the specific gaseous
fuel (metric tons).

Fuel	=	Annual volume of the gaseous fuel combusted (scf).  The volume of
fuel combusted must be measured directly, using fuel flow meters
calibrated according to §98.3(i).  Fuel billing meters may be used for
this purpose.

CC 	=	Annual average carbon content of the liquid gaseous fuel (kg C per
gallon kg of fuel).  The annual average carbon content shall be
determined using the same procedures as specified for HHV in paragraph
(a)(2)(ii) of this section.

MW	=	Annual average molecular weight of the gaseous fuel (kg/kg-mole).
The annual average carbon content molecular weight shall be determined
using the same procedures as specified for HHV in paragraph (a)(2)(ii)
of this section.

MVC	=	Molar volume conversion factor (849.5 scf per kg-mole at standard
conditions, as defined in §98.6).

44/12	=	Ratio of molecular weights, CO2 to carbon.

0.001	=	Conversion factor from kg to metric tons.

(iv)  Fuel flow meters that measure mass flow rates may be used for
liquid or gaseous fuels, provided that the fuel density is used to
convert the readings to volumetric flow rates.  The density shall be
measured at the same frequency as the carbon content, using ASTM
D1298-99 (Reapproved 2005) “Standard Test Method for Density, Relative
Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid
Petroleum Products by Hydrometer Method” (incorporated by reference,
see §98.7).  For liquid fuels, you must measure the density using one
of the following appropriate methods.  You may use a method published by
a consensus standards organization, if such a method exists, or you may
use industry standard practice.  Consensus-based standards organizations
include, but are not limited to, the following: ASTM International, the
American National Standards Institute (ANSI), the American Gas
Association (AGA), the American Society of Mechanical Engineers (ASME),
the American Petroleum Institute (API), and the North American Energy
Standards Board (NAESB).  The method(s) used shall be documented in the
Monitoring Plan required under §98.3(g)(5).  Alternatively, for fuel
oil, you may use an applicable default density value provided in
paragraph (a)(3)(v) of this section.  For gaseous fuels, you may
determine the density using any of the following methods.  You may use a
density meter calibrated according to the manufacturer’s instructions,
a method published by a consensus standards organization, or an industry
standard practice.  Document the method used to determine the fuel
density in the Monitoring Plan under §98.3(g)(5).

(v)  The following default density values may be used for fuel oil, in
lieu of using the ASTM method in paragraph (a)(3)(iv) of this section:
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6
oil.

(4)  Tier 4 Calculation Methodology.  Calculate the annual CO2 mass
emissions from all fuels combusted in a unit, by using quality-assured
data from continuous emission monitoring systems (CEMS).

(i)  This methodology requires a CO2 concentration monitor and a stack
gas volumetric flow rate monitor, except as otherwise provided in
paragraph (a)(4)(iv) of this section.  Hourly measurements of CO2
concentration and stack gas flow rate are converted to CO2 mass emission
rates in metric tons per hour.

(ii)  When the CO2 concentration is measured on a wet basis, Equation
C-6 of this section is used to calculate the hourly CO2 emission rates:

 	(Eq. C-6)

Where:

CO2	=	CO2 mass emission rate (metric tons/hr).

CCO2 	=	Hourly average CO2 concentration (% CO2).

Q 	=	Hourly average stack gas volumetric flow 	rate (scfh).

5.18 x 10-7	=	Conversion factor (metric tons/scf/% CO2).

(iii)  If the CO2 concentration is measured on a dry basis, a correction
for the stack gas moisture content is required. You shall either
continuously monitor the stack gas moisture content as described in
§75.11(b)(2) of this chapter or, for certain types of fuel, use an
appropriate default moisture percentage.  For coal, wood, and natural
gas combustion, you may use the default moisture values specified in
from §75.11(b)(1) of this chapter.  Alternatively, for any type of
fuel, you may determine an appropriate site-specific default moisture
value (or values), using measurements made with EPA Method 4 -
Determination Of Moisture Content In Stack Gases, in appendix A-3 to
part 60 of this chapter.  If this option is selected, the site-specific
moisture default value(s) must represent the fuel(s) or fuel blends that
are combusted in the unit during normal, stable operation, and must
account for any distinct difference(s) in the stack gas moisture content
associated with different process operating conditions.  For each
site-specific default moisture percentage, at least nine Method 4 runs
are required.  Moisture data from the relative accuracy test audit
(RATA) of a CEMS may be used for this purpose.  Calculate each
site-specific default moisture value by taking the arithmetic average of
the Method 4 runs.  Each site-specific moisture default value shall be
updated whenever the owner or operator believes the current value is
non-representative, due to changes in unit or process operation, but in
any event no less frequently than annually.  Use the updated moisture
value in the subsequent CO2 emissions calculations.  For each unit
operating hour, a moisture correction must be applied to Equation C-6 of
this section as follows:

 	(Eq. C-7)

Where:

CO2*  	=	Hourly CO2 mass emission rate, corrected for moisture (metric
tons/hr).

CO2 	=	Hourly CO2 mass emission rate from Equation C-6 of this section,
uncorrected (metric tons/hr).

%H2O	=	Hourly moisture percentage in the stack gas (measured or default
value, as appropriate).

(iv)  An oxygen (O2) concentration monitor may be used in lieu of a CO2
concentration monitor to determine the hourly CO2 concentrations, in
accordance with Equation F-14a or F-14b (as applicable) in appendix F to
40 CFR part 75 of this chapter, if the effluent gas stream monitored by
the CEMS consists solely of combustion products (i.e., no process CO2
emissions or CO2 emissions from sorbent are mixed with the combustion
products) and if only fuels that are listed in Table 1 in section 3.3.5
of appendix F to 40 CFR part 75 of this chapter are combusted in the
unit.  If the O2 monitoring option is selected, the F-factors used in
Equations F-14a and F-14b shall be determined according to section 3.3.5
or section 3.3.6 of appendix F to 40 CFR part 75 of this chapter, as
applicable.  If Equation F-14b is used, the hourly moisture percentage
in the stack gas shall be determined in accordance with paragraph
(a)(4)(iii) of this sectioneither a measured value in accordance with
§75.11(b)(2) of this chapter, or, for certain types of fuel, a default
moisture value from §75.11(b)(1) of this chapter.

(v)  Each hourly CO2 mass emission rate from Equation C-6 or C-7 of this
section is multiplied by the operating time to convert it from metric
tons per hour to metric tons.  The operating time is the fraction of the
hour during which fuel is combusted (e.g., the unit operating time is
1.0 if the unit operates for the whole hour and is 0.5 if the unit
operates for 30 minutes in the hour).  For common stack configurations,
the operating time is the fraction of the hour during which effluent
gases flow through the common stack.

(vi)  The hourly CO2 mass emissions are then summed over each calendar
quarter and the quarterly totals are summed to determine the annual CO2
mass emissions.

(vii)  If both biomass and fossil fuel are combusted during the year,
determine and report the biogenic CO2 mass emissions separately, as
described in paragraph (e) of this section.

(viii)  If a portion of the flue gases generated by a unit subject to
Tier 4 (e.g., a slip stream) is continuously diverted from the main flue
gas exhaust system for the purpose of heat recovery or some other
similar process, and then exhausts through a stack that is not equipped
with the continuous emission monitors to measure CO2 mass emissions,
provided that the CO2 concentration in the diverted stream is not
altered in any way (e.g., by chemical reaction or dilution) before the
diverted stream exits to the atmosphere, an estimate of the hourly
average volumetric flow rate (scfh) of the diverted gas stream shall be
made at the point where it exits the main exhaust system, by using the
best available information (e.g., correlations of operating parameters
versus flow measurements made with EPA Method 2 in appendix A-2 to part
60 of this chapter, engineering analysis, or other methods).  Each
hourly average volumetric flow rate (scfh) measured at the main flue gas
stack shall then be added to the corresponding estimate of the hourly
average flow rate of the diverted gas stream, to determine the total
hourly average stack gas volumetric flow rate "Q", for use in Equation
C-6 of this section.  The method use to estimate the hourly flow rate
of the diverted portion of the flue gas exhaust stream shall be
documented in the Monitoring Plan required under §98.3(g)(5).

(5)  Alternative methods for certain units subject to 40 CFR Part 75 of
this chapterwith continuous monitoring systems.  Certain Uunits that are
not subject to the Acid Rain Programsubpart D of this part and that
report data to EPA according to 40 CFR part 75 of this chapter may
qualify to use the alternative methods in this paragraph (a)(5), in lieu
of using any of the four calculation methodology tiers.

(i)  For a unit that combusts only natural gas and/or fuel oil, is not
subject to subpart D of this partthe Acid Rain Program,   monitors and
reports heat input data year-round according to appendix D to 40 CFR
part 75 of this chapter, but is not required by the applicable 40 CFR
part 75 program to report CO2 mass emissions data, calculate the annual
CO2 mass emissions for the purposes of this part as follows:

(A)  Use the hourly heat input data from appendix D to 40 CFR part 75 of
this chapter, together with Equation G-4 in appendix G to 40 CFR part 75
of this chapter to determine the hourly CO2 mass emission rates, in
units of tons/hr;

(B)  Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 of this
chapterto calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons; and

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(ii)  For a unit that combusts only natural gas and/or fuel oil, is not
subject to the Acid Rain Programsubpart D of this part, monitors and
reports heat input data year-round according to 40 CFR §75.19 of this
chapter but is not required by the applicable 40 CFR part 75 program to
report CO2 mass emissions data, calculate the annual CO2 mass emissions
for the purposes of this part as follows:

(A)  Calculate the hourly CO2 mass emissions, in units of short tons,
using Equation LM-11 in 40 CFR §75.19(c)(4)(iii) of this chapter.

(B)  Sum the hourly CO2 mass emissions values over the entire reporting
year to obtain the cumulative annual CO2 mass emissions, in units of
short tons.

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(iii)  For a unit that is not subject to the Acid Rain Programsubpart D
of this part, uses flow rate and CO2 (or O2) CEMS to report heat input
data year-round according to 40 CFR part 75 of this chapter, but is not
required by the applicable 40 CFR part 75 program to report CO2 mass
emissions data, calculate the annual CO2 mass emissions as follows:

(A)  Use Equation F-11 or F-2 (as applicable) in appendix F to 40 CFR
part 75 of this chapter to calculate the hourly CO2 mass emission rates
from the CEMS data.  If an O2 monitor is used, convert the hourly
average O2 readings to CO2 using Equation F-14a or F-14b in appendix F
to 40 CFR part 75 of this chapter (as applicable), before applying
Equation F-11 or F-2.

(B)  Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 of this
chapter to calculate the quarterly and cumulative annual CO2 mass
emissions, respectively, in units of short tons.

(C)  Divide the cumulative annual CO2 mass emissions value by 1.1 to
convert it to metric tons.

(Div)  For units that qualify to use the alternative CO2 emissions
calculation methods in paragraphs (a)(5)(i) through (a)(5)(iii) of this
section, Iif both biomass and fossil fuel are combusted during the year,
separate calculation and reporting of the biogenic CO2 mass emissions
determine and report the biogenic CO2 mass emissions separately, (as
described in paragraph (e) of this section) is optional.

(b)  Use of the four tiers.  Use of the four tiers of CO2 emissions
calculation methodologies described in paragraph (a) of this section is
subject to the following conditions, requirements, and restrictions:

(1)  The Tier 1 Calculation Methodology:

(i)  May be used for any fuel listed in Table C-1 of this subpart that
is combusted in a unit with a maximum rated heat input capacity of 250
mmBtu/hr or less.

(ii)  May be used for MSW in a unit of any size that does not produce
steam, if the use of Tier 4 is not required.

(iii)  May be used for solid, gaseous, or liquid biomass fuels in a unit
of any size provided that the fuel is listed in Table C-1 of this
subpart.

(iv)  May not be used if you routinely perform fuel sampling and
analysis for the fuel high heat value (HHV) or routinely receives the
results of HHV sampling and analysis from the fuel supplier at the
minimum frequency specified in §98.34(a), or at a greater frequency.
In such cases, Tier 2 shall be used.  This restriction does not apply to
paragraphs (b)(1)(ii) and (b)(1)(v) of this section.

(v)  May be used for natural gas combustion in a unit of any size, in
cases where the annual natural gas consumption is obtained from fuel
billing records in units of therms.

(2)  The Tier 2 Calculation Methodology:

(i)  May be used for the combustion of any type of fuel in a unit with a
maximum rated heat input capacity of 250 mmBtu/hr or less provided that
the fuel is listed in Table C-1 of this subpart.

(ii)  May be used in a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr for the combustion of pipeline quality natural
gas and/or distillate fuel oil.

(iii)  May be used for MSW in a unit of any size that produces steam, if
the use of Tier 4 is not required.

(3)  The Tier 3 Calculation Methodology:

(i)  May be used for a unit of any size that combusts any type of fuel
listed in Table C-1 of this subpart (except for MSW), unless the use of
Tier 4 is required.

(ii)  Shall be used for a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr that combusts any type of fuel listed in Table
C-1 of this subpart (except MSW), unless either of the following
conditions apply:

(A)  The use of Tier 1 or 2 is permitted, as described in paragraphs
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.

(B)  The use of Tier 4 is required.

(iii)  Shall be used for a fuel not listed in Table C-1 of this subpart
and are not exempted under §98.30(c), if the fuel is combusted in a
unit with a maximum rated heat input capacity greater than 250 mmBtu/hr
(or, pursuant to §98.36(c)(3), in a group of units served by a common
supply pipe, having at least one unit with a maximum rated heat input
capacity greater than 250 mmBtu/hr), provided that both of the following
conditions apply:

(A)  The use of Tier 4 is not required.

(B)  The fuel provides 10% or more of the annual heat input to the unit
or, if §98.36(c)(3)applies, to athe group of units served by a common
supply pipe.

(iv)  Shall be used when specified in another applicable subpart of this
part, regardless of unit size.

(4)  The Tier 4 Calculation Methodology:

(i)  May be used for a unit of any size, combusting any type of fuel.
Tier 4 may also be used for any group of stationary fuel combustion
units, process units, or manufacturing units that share a common stack
or duct.

(ii)  Shall be used if the unit meets all six of the conditions
specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this
section:

(A)  The unit has a maximum rated heat input capacity greater than 250
mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 600 tons per day of MSW.

(B)  The unit combusts solid fossil fuel or MSW, either as a the primary
or secondary fuel.

(C)  The unit has operated for more than 1,000 hours in any calendar
year since 2005.

(D)  The unit has installed CEMS that are required either by an
applicable Federal or State regulation or the unit’s operating permit.

(E)  The installed CEMS include a gas monitor of any kind or a stack gas
volumetric flow rate monitor, or both and the monitors have been
certified, either in accordance with the requirements of 40 CFR part 75
of this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program.

(F)  The installed gas or stack gas volumetric flow rate monitors are
required, either by an applicable Federal or State regulation or by the
unit’s operating permit, to undergo periodic quality assurance testing
in accordance with either appendix B to 40 CFR part 75 of this chapter,
appendix F to 40 CFR part 60 of this chapter, or an applicable State
continuous monitoring program.

(iii)  Shall be used for a unit with a maximum rated heat input capacity
of 250 mmBtu/hr or less and for a unit that combusts municipal solid
waste with a maximum rated input capacity of 250 600 tons of MSW per day
or less, if the unit meets all of the following three conditions:

(A)  The unit has both a stack gas volumetric flow rate monitor and a
CO2 concentration monitor.

(B)  The unit meets the conditions specified in paragraphs (b)(4)(ii)(B)
through (b)(4)(ii)(D) of this section.

(C)  The CO2 and stack gas volumetric flow rate monitors meet the
conditions specified in paragraphs (b)(4)(ii)(E) and (b)(4)(ii)(F) of
this section.

(iv)  May apply to common stack or duct configurations where:

(A)  The combined effluent gas streams from two or more stationary fuel
combustion units are vented through a monitored common stack or duct.
In this case, Tier 4 shall be used if all of the conditions in paragraph
(b)(4)(iv)(A)(1) of this section or all of the conditions in paragraph
(b)(4)(iv)(A)(2) of this section are met.

(1)  At least one of the units meets the requirements of paragraphs
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS
installed at the common stack (or duct) meet the requirements of
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.

(2)  At least one of the units and the monitors installed at the common
stack or duct meet the requirements of paragraph (b)(4)(iii) of this
section.

(B)  The combined effluent gas streams from a process or manufacturing
unit and a stationary fuel combustion unit are vented through a
monitored common stack or duct.  In this case, Tier 4 shall be used if
the combustion unit and the monitors installed at the common stack or
duct meet the applicability criteria specified in paragraph
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.

(C)  The combined effluent gas streams from two or more manufacturing or
process units are vented through a common stack or duct.  In this case,
if any of the units is required by an applicable subpart of this part to
use Tier 4, the CO2 mass emissions may either be monitored at each
individual unit, or the combined CO2 mass emissions may be monitored at
the common stack or duct.  However, if it is not feasible to monitor the
individual units, the combined CO2 mass emissions shall be monitored at
the common stack or duct.

(5)  The Tier 4 Calculation Methodology shall be used beginning on:

(i)  Starting on January 1, 2010, for a unit that is required to report
CO2 mass emissions beginning on that date, if all of the monitors needed
to measure CO2 mass emissions have been installed and certified by that
date.

(ii)  No later than January 1, 2011, for a unit that is required to
report CO2 mass emissions beginning on January 1, 2010, if  all of the
monitors needed to measure CO2 mass emissions have not been installed
and certified by January 1, 2010.  In this case, you may use Tier 2 or
Tier 3 to report GHG emissions for 2010.  However, if the required CEMS
are certified some time in 2010, you need not wait until January 1, 2011
to begin using Tier 4.  Rather, you may switch from Tier 2 or Tier 3 to
Tier 4 as soon as CEMS certification testing is successfully completed.
If this reporting option is chosen, you must document the change in CO2
calculation methodology in the Monitoring Plan required under
§98.3(g)(5) and in the GHG emissions report under §98.3(c).  Data
recorded by the CEMS during a certification test period in 2010 may be
used for reporting under this part, provided that the following two
conditions are met:

(A)  The certification tests are passed in sequence, with no test
failures.

(B)  No unscheduled maintenance or repair of the CEMS is performed
during the certification test period.

(iii)  No later than 180 days following the date on which a change is
made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or
(b)(4)(iii) of this section (e.g., a change in the primary fuel, manner
of unit operation, or installed continuous monitoring equipment).

(6)  You may elect to use any applicable higher tier for one or more of
the fuels combusted in a unit.  For example, if a 100 mmBtu/hr unit
combusts natural gas and distillate fuel oil, you may elect to use Tier
1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could
have been used for both fuels.  However, for units that use either the
Tier 4 or the alternative calculation methodology specified in paragraph
(a)(5)(iii) of this section, CO2 emissions from the combustion of all
fuels shall be based solely on CEMS measurements.

(c)  Calculation of CH4 and N2O emissions from stationary combustion
sources.  You must calculate annual CH4 and N2O mass emissions only for
units that are required to report CO2 emissions using the calculation
methodologies of this subpart and for only those fuels that are listed
in Table C-2 of this subpart.

(1)  Use Equation C-8 of this section to estimate CH4 and N2O emissions
for any fuels for which you use the Tier 1 or Tier 3 calculation
methodologies for CO2.  Use the same values for fuel combustion
consumption that you use for the Tier 1 or Tier 3 calculation.

  	(Eq. C-8)

Where:

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

Fuel		=	Mass or volume of the fuel combusted, either from company
records or directly measured by a fuel flow meter, as applicable (mass
or volume per year).

HHV		=	Default high heat value of the fuel from Table C-1 of this
subpart; alternatively, for Tier 3, if actual HHV data are available for
the reporting year, you may average these data using the procedures
specified in paragraph (a)(2)(ii) of this section, and use the average
value in Equation C-8 (mmBtu per mass or volume).

EF 		=	Fuel-specific default emission factor for CH4 or N2O, from Table
C-2 of this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3	=	Conversion factor from kilograms to metric tons.

(2)  Use Equation C-9a of this section to estimate CH4 and N2O emissions
for any fuels for which you use the Tier 2 Equation C-2a of this section
to estimate CO2 emissions.  Use the same values for fuel combustion
consumption and HHV that you use for the Tier 21 or Tier 3 calculation.

 	(Eq. C-9a)

Where:

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

Fuel 	=	Mass or volume of the fuel combusted during the reporting year.

HHV 	=	High heat value of the fuel, averaged for all valid measurements
for the reporting year (mmBtu per mass or volume).

EF	=	Fuel-specific default emission factor for CH4 or N2O, from Table
C-2 of this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3 	=	Conversion factor from kilograms to metric tons.

(3)  Use Equation C-9b of this section to estimate CH4 and N2O emissions
for any fuels for which you use Equation C-2c of this section to
calculate the CO2 emissions.  Use the same values for steam generation
and the ratio “B” that you use for Equation C-2c.

 	  (Eq. C-9b)

Where:

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a solid
fuel (metric tons).

Steam	=	Total mass of steam generated by solid fuel combustion during
the reporting year (lb steam).

B	=	Ratio of the boiler’s maximum rated heat input capacity to its
design rated steam output (mmBtu/lb steam).

EF	=	Fuel-specific emission factor for CH4 or N2O, from Table C-2 of
this subpart (kg CH4 or N2O per mmBtu).

1 x 10-3 	=	Conversion factor from kilograms to metric tons.

(4)  Use Equation C-10 of this section for: units in the Acid Rain
Programsubject to subpart D of this part, ; units that qualify for and
elect to use the alternative CO2 mass emissions calculation
methodologies described in paragraph (a)(5) of this section;monitor and
report heat input on a year-round basis according to 40 CFR part 75, and
units that use the Tier 4 Calculation Methodology.

 	(Eq. C-10)

Where:

CH4 or N2O	=	Annual CH4 or N2O emissions from the combustion of a
particular type of fuel (metric tons).

(HI)A 		=	Cumulative annual heat input from combustion of the fuel,
derived from the electronic data reports required under §75.64 of this
chapter or, for Tier 4 units, from the best available information as
described in paragraph (c)(4)(ii) of this section (mmBtu).

EF		=	Fuel-specific emission factor for CH4 or N2O, from Table C-2 of
this section (kg CH4 or N2O per mmBtu).

0.001		=	Conversion factor from kg to metric tons.

(i)  If only one type of fuel listed in Table C-2 of this subpart is
combusted during normal operationthe reporting year, substitute the
cumulative annual heat input from combustion of the fuel into Equation
C-10 of this section to calculate the annual CH4 or N2O emissions.  For
units  in the Acid Rain Program and units that report heat input data to
EPA year-round according to part 75 of this chapter, obtain the
cumulative annual heat input directly from the electronic data reports
required under §75.64 of this chapter.  For Tier 4 units, use the best
available information, as described in paragraph (c)(4)(ii)(C) of this
section, to estimate the cumulative annual heat input (HI)A.

(ii)  If more than one type of fuel listed in Table C-2 of this subpart
is combusted during normal operation the reporting year, use Equation
C-10 of this section separately for each type of fuel, except as
provided in paragraph (c)(4)(ii)(B) of this section.  Determine the
appropriate values of (HI)A as follows:

(A)  For units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter,
obtain (HI)A for each type of fuel from the electronic data reports
required under §75.64 of this chapter, except as otherwise provided in
paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.

(B)  For a unit that uses CEMS to monitor hourly heat input according to
part 75 of this chapter, the value of (HI)A obtained from the electronic
data reports under §75.64 of this chapter may be attributed exclusively
to the fuel with the highest F-factor, when the reporting option in
<IP_ADDRESS> of appendix F to part 75 of this chapter is selected and
implemented.

(C)  For Tier 4 units, use the best available information (e.g., fuel
feed rate measurements, fuel heating values, engineering analysis) to
estimate the value of (HI)A for each type of fuel.  Instrumentation used
to make these estimates is not subject to the calibration requirements
of §98.3(i) or to the QA requirements of §98.34.

(D)  Units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter may
use the best available information described in paragraph (c)(4)(ii)(C)
of this section, to estimate (HI)A for each fuel type, whenever
fuel-specific heat input values cannot be directly obtained from the
electronic data reports under §75.64 of this chapter..  If flow rate
and diluent gas monitors are used to measure the unit heat input, use
the best available information (e.g., fuel feed rate measurements, fuel
heating values, engineering analysis) to estimate the annual heat input
from each type of fuel.

(5)  When multiple fuels are combusted during the reporting year, sum
the fuel-specific results from Equations C-8, C-9a, C-9b, or C-10 of
this section (as applicable) to obtain the total annual CH4 and N2O
emissions, in metric tons.

(6)  Calculate the annual CH4 and N2O mass emissions from the combustion
of blended fuels as follows:

(i)  If the mass or volume of each component fuel in the blend is
measured before the fuels are mixed and combusted, calculate and report
CH4 and N2O emissions separately for each component fuel, using the
applicable procedures in this paragraph (c).

(ii) If the mass or volume of each component fuel in the blend is not
measured before the fuels are mixed and combusted, a reasonable estimate
of the percentage composition of the blend, based on best available
information, is required. Perform the following calculations for each
component fuel, “i”, that is listed in Table C-2:

(A)  Multiply (% Fuel)i, the estimated mass or volume percentage
(decimal fraction) of component fuel “i”, by the total annual mass
or volume of the blended fuel combusted during the reporting year, to
obtain an estimate of the annual consumption of component “i”;

(B)  Multiply the result from paragraph (c)(6)(ii)(A) of this section by
the HHV of the fuel (default value or, if available, the measured annual
average value), to obtain an estimate of the annual heat input from
component “i”;

(C)  Calculate the annual CH4 and N2O emissions from component “i”,
using Equation C-8, C-9a, or C-10 of this section, as applicable;

(D)  Sum the annual CH4 emissions across all component fuels to obtain
the annual CH4 emissions for the blend. Similarly sum the annual N2O
emissions across all component fuels to obtain the annual N2O emissions
for the blend.  Report these annual emissions totals.

(d)  Calculation of CO2 from sorbent.

(1)  When a unit is a fluidized bed boiler, is equipped with a wet flue
gas desulfurization system, or uses other acid gas emission controls
with sorbent injection to remove acid gases, if the chemical reaction
between the acid gas and the sorbent produces CO2 emissions, use
Equation C-11 of this section to calculate the CO2 emissions from the
sorbent, ifexcept when those CO2 emissions are not monitored by CEMS:.
When a sorbent other than CaCO3 is used, determine site-specific values
of R and MWS.

 	(Eq. C-11)

Where:

CO2 	=	CO2 emitted from sorbent for the reporting year (metric tons).

S 	=	Limestone or other sorbent used in the reporting year, from company
records (short tons).

R 	=	1.00, the calcium-to-sulfur stoichiometric ratioThe number of moles
of CO2 released upon capture of one mole of the acid gas species being
removed (R = 1.00 when the sorbent is CaCO3 and the targeted acid gas
species is SO2).

MWCO2 	=	Molecular weight of carbon dioxide (44).

MWS	=	Molecular weight of sorbent (100 if calcium carbonate).

0.91	=	Conversion factor from short tons to metric tons

(2)  The total annual CO2 mass emissions reported for the unit shall be
the sum of include the CO2 emissions from the combustion process and the
CO2 emissions from the sorbent.

(e)  Biogenic CO2 emissions from combustion of biomass with other fuels.
 Use the applicable procedures of this paragraph (e) to estimate
biogenic CO2 emissions from units that combust a combination of biomass
and fossil fuels (i.e., either co-fired or blended fuels).  Separate
rReporting of biogenic CO2 emissions from the combined combustion of
biomass and fossil fuels is required only for those biomass fuels listed
in Table C-1 of this section and for municipal solid waste, unless
emissions are measured using CEMS.  In addition, when a biomass fuel
that is not listed in Table C-1 is combusted in a unit that has a
maximum rated heat input greater than 250 mmBtu/hr, if the biomass fuel
accounts for 10% or more of the annual heat input to the unit, and if
the unit does not use CEMS to quantify its annual CO2 mass emissions,
then, pursuant to §98.33(b)(3)(iii), Tier 3 must be used to determine
the carbon content of the biomass fuel and to calculate the biogenic CO2
emissions from combustion of the fuel.  Notwithstanding these
requirements, separate reporting of biogenic CO2 emissions is optional
for units subject to subpart D of this part and for units that use the
CO2 mass emissions calculation methodologies in part 75 of this chapter,
pursuant to paragraph (a)(5) of this section; however, if the owner or
operator opts to report biogenic CO2 emissions separately for these
units, the appropriate method(s) in this paragraph (e) shall be used.
Separate reporting of biogenic CO2 emissions from the combustion of
tires is also optional, but may be reported by following the provisons
of paragraph (e)(3) of this section.

(1)  If CEMS are not used to measure CO2, You may use Equation C-1 of
this subpart to calculate the annual CO2 mass emissions from the
combustion of the biomass fuels listed in Table C-1 of this subpart
(except MSW and tires), forin a unit of any size, including units
equipped with a CO2 CEMS, except when the use of Tier 2 is required as
specified in paragraph (b)(1)(iv) of this section.  Determine the mass
quantity of biomass combusted using one of the following procedures in
this paragraph (e)(1), as appropriate, and document the selected
procedures in the Monitoring Plan under §98.3(g).:

(i)  Use cCompany records.

(ii)  Follow tThe procedures in paragraph (e)(54) of this section.

(iii)  The best available information, Ffor premixed fuels that contain
biomass and fossil fuels (e.g., liquid fuel mixtures containing
biodiesel), use best available information to determine the mass of
biomass fuels and document the procedure used in the GHG Monitoring Plan
required by §98.3(g)(5).

(2)  You may use the procedures of this paragraph if the following three
conditions are met: first, a If a CO2 CEMS (or a surrogate O2 monitor)
and a stack gas flow rate monitor are used to determine the annual CO2
mass emissions (either according to 40 CFR part 75 of this chapter, the
Tier 4 Calculation Methodology, or the alternative calculation
methodology specified in paragraph (a)(5)(iii) of this section); and if
both fossil fuel and biomass (except for MSW) are combusted in the unit
during the reporting year, you may use the following procedure to
determine the annual biogenic CO2 mass emissions.  If MSW is combusted
in the unit, follow the procedures in paragraph (e)(3) of this
section.second, neither MSW nor tires is combusted in the unit during
the reporting year; and third, the CO2 emissions consist solely of
combustion products (i.e., no process or sorbent emissions included).

(i)  For each operating hour, use Equation C-12 of this section to
determine the volume of CO2 emitted.

  	(Eq. C-12)

Where:

VCO2h 	=	Hourly volume of CO2 emitted (scf).

(%CO2)h	=	Hourly average CO2 concentration, measured by the CO2
concentration monitor, or, if applicable, calculated from the hourly
average O2  concentration (%CO2).

Qh	=	Hourly average stack gas volumetric flow rate, measured by the
stack gas volumetric flow rate monitor (scfh).

th 	=	Source operating time (decimal fraction of the hour during which
the source combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for
30 minutes of operation, etc.).

100 	=	Conversion factor from percent to a decimal fraction.

(ii)  Sum all of the hourly VCO2h values for the reporting year, to
obtain Vtotal, the total annual volume of CO2 emitted.

(iii)  Calculate the annual volume of CO2 emitted from fossil fuel
combustion using Equation C-13 of this section.  If two or more types of
fossil fuel are combusted during the year, perform a separate
calculation with Equation C-13 of this section for each fuel and sum the
results.

  	(Eq. C-13)

Where:

Vff 	=	Annual volume of CO2 emitted from combustion of a particular
fossil fuel (scf).

Fuel 	=	Total quantity of the fossil fuel combusted in the reporting
year, from company records, as defined in §98.6 (lb for solid fuel,
gallons for liquid fuel, and scf for gaseous fuel).

Fc 	=	Fuel-specific carbon based F-factor, either a default value from
Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 of this
chapter, or a site-specific value determined under section 3.3.6 of
appendix F to 40 CFR part 75 (scf CO2/mmBtu).

HHV 	=	High heat value of the fossil fuel, from fuel sampling and
analysis (annual average value in Btu/lb for solid fuel, Btu/gal for
liquid fuel and Btu/scf for gaseous fuel, sampled as specified (e.g.,
monthly, quarterly, semi-annually, or by lot) in §98.34(a)(2)).  The
average HHV shall be calculated according to the requirements of
paragraph (a)(2)(ii) of this section.

106 	=	Conversion factor, Btu per mmBtu.

(iv)  Subtract Vff from Vtotal to obtain Vbio, the annual volume of CO2
from the combustion of biomass.  If a CEMS is being used to measure the
combined combustion and process emissions from a unit that is subject to
another subpart of part 98, then also subtract CO2 process emissions
from Vtotal to determine Vbio.  The CO2 process emissions must be
calculated according to the requirements of the applicable subpart.

(v)  Calculate the biogenic percentage of the annual CO2
emissions,expressed as a decimal fraction, using Equation C-14 of this
section:

 	(Eq. C-14)

(vi)  Calculate the annual biogenic CO2 mass emissions, in metric tons,
by multiplying the results obtained from Equation C-14 of this section
by the annual CO2 mass emissions in metric tons, as determined:

(A)  Under paragraph (a)(4)(vi) of this section, for units using the
Tier 4 Calculation Methodology.

(B)  Under paragraph (a)(5)(iii)(B) of this section, for units using the
alternative calculation methodology specified in paragraph (a)(5)(iii).

(C)  From the electronic data report required under §75.64 of this
chapter, for units in the Acid Rain Program and other units using CEMS
to monitor and report CO2 mass emissions according to 40 CFR part 75 of
this chapter.  However, before calculating the annual biogenic CO2 mass
emissions, multiply the cumulative annual CO2 mass emissions by 0.91 to
convert from short tons to metric tons.

(3)  For a unit that combusts MSW, the annual biogenic CO2 emissions
shall be calculated using You must use the procedures in this paragraphs
(e)(3)(i) through (e)(3)(iii) of this section to determine the annual
biogenic CO2 emissions from the combustion of MSW.  These procedures
also may be used for any unit that co-fires biomass and fossil fuels,
including units equipped with a CO2 CEMS, and units for which optional
separate reporting of biogenic CO2 emissions from the combustion of
tires is selected.

(i)  If the Tier 1 or Tier 2 Use an applicable CO2 emissions calculation
method in this section Calculation Methodology is used to quantify the
total annual CO2 mass emissions from the unit:.

(A)  Use Equation C-1 or C-2c of this subpart, as appropriate, to
calculate the annual CO2 mass emissions from MSW combustion.

(Bii)  Determine the relative proportions of biogenic and non-biogenic
CO2 emissions in the flue gas on a quarterly basis using the method
specified in §98.34(d) (for units that combust MSW as the primary fuel
or as the only fuel with a biogenic component) or in §98.34(e) (for
other units, including units that combust tires).

(Ciii)  Determine the annual biogenic CO2 mass emissions from the
unitMSW combustion by multiplying the total annual CO2 mass emissions by
the annual average biogenic decimal fraction obtained from §98.34(d) or
§98.34(e), as applicable.

(ii)  If the unit uses Tier 4 to quantify CO2 emissions:

(A)  Follow the procedures in paragraphs (e)(2)(i) and (ii) of this
section, to determine Vtotal.

(B)  If any fossil fuel was combusted during the year, follow the
procedures in paragraph (e)(2)(iii) of this section, to determine Vff.

(C)  Subtract Vff from Vtotal, to obtain VMSW , the annual volume of CO2
emissions from MSW combustion.

(D)  Determine the annual volume of biogenic CO2 emissions (Vbio) from
MSW combustion as follows.  Multiply the annual volume of CO2 emissions
from MSW combustion (VMSW) by the annual average biogenic decimal
fraction obtained from ASTM D6866-08 and ASTM D7459-08.

(E)  Calculate the biogenic percentage of the annual CO2 emissions from
the unit, using Equation C-14 of this section.  For the purposes of this
calculation, the term “Vbio” in the numerator of Equation C-14 of
this section shall be the results of the calculation performed under
paragraph (e)(3)(ii)(D) of this section.

(F)  Calculate the annual biogenic CO2 mass emissions according to
paragraph (e)(2)(vi)(A) of this section.

(4)  [Reserved]As an alternative to the procedures in paragraph (e)(2)
of this section, use ASTM Methods D7459-08 and D6866-08 to determine the
biogenic portion of the annual CO2 emissions, as described in
§98.34(e).  If this option is selected, the results of each
determination shall be expressed as a decimal fraction (e.g., 0.30, if
30 percent of the CO2 is biogenic), and the values shall be averaged
over the reporting year.  The annual biogenic CO2 mass emissions shall
be calculated by multiplying the the total annual CO2 mass emissions by
the annual average biogenic fraction obtained from ASTM D6866-08 and
ASTM D7459-08.

(5)  If Equation C-1 or Equation C-2a of this section is selected to
calculate the annual biogenic mass emissions for wood, wood waste, or
other solid biomass-derived fuel, Equation C-15 of this section may be
used to quantify biogenic fuel consumption, provided that all of the
required input parameters are accurately quantified.  Similar equations
and calculation methodologies based on steam generation and boiler
efficiency may be used, provided that they are documented in the GHG
Monitoring Plan required by §98.3(g)(5).

 	(Eq. C-15)

Where:

(Fuel)p	=	Quantity of biomass consumed during the measurement period
“p” (tons/year or tons/month, as applicable).

H	=	Average enthalpy of the boiler steam for the measurement period
(Btu/lb).

S	=	Total boiler steam production for the measurement period (lb/month
or lb/year, as applicable).

(HI)nb	=	Heat input from co-fired fossil fuels and non-biomass-derived
fuels for the measurement period, based on company records of fuel usage
and default or measured HHV values (Btu/month or Btu/year, as
applicable).

(HHV)bio	=	Default or measured high heat value of the biomass fuel
(Btu/lb).

(Eff)bio	=	Percent efficiency of biomass-to-energy conversion, expressed
as a decimal fraction.

2000	=	Conversion factor (lb/ton).

§98.34  Monitoring and QA/QC requirements.

The CO2 mass emissions data for stationary fuel combustion sources shall
be monitored as follows:

(a)  For the Tier 2 Calculation Methodology:

(1)  All fuel samples shall be taken at a location in the fuel handling
system that provides a sample representative of the fuel combusted.  The
fuel sampling and analysis may be performed by either the owner or
operator or the supplier of the fuel.

(2)  The minimum required frequency of the HHV sampling and analysis for
each type of fuel or fuel mixture (blend) is specified in this
paragraph.  When the specified frequency for a particular fuel or blend
is based on a specified time period (ie.eg., weekly, monthly, quarterly,
or semiannuallyhalf-year), fuel sampling and analysis is required only
for those time periods in which the fuel or blend is combustedunit
operates.  The owner or operator may perform fuel sampling and analysis
more often than the minimum required frequency, in order to obtain a
more representative annual average HHV.

(i)  For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at least
four months apart).

(ii)  For coal and fuel oil, and for any other solid or liquid fuel that
is delivered in lots, analysis of at least one representative sample
from each fuel lot is required.  For fuel oil, as an alternative to
sampling each fuel lot, a sample may be taken upon each addition of oil
to the unit’s storage tank.  Flow proportional sampling, continuous
drip sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot.  For the purposes of this section, a fuel lot is
defined as either:

(A)  aA shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via pipeline
from a tank farm, etc.); or.

(B)  If multiple deliveries of a particular type of fuel are received
from the same supply source in a given calendar month, the deliveries
for that month are considered, collectively, to comprise a fuel lot,
requiring only one representative sample.

(iii)  For liquid fuels other than fuel oil, and for gaseous fuels other
than natural gas (including for fossil fuel-derived gaseous fuels, and
for biogas),; sampling and analysis is required at least once per
calendar quarter. To the extent practicable, consecutive quarterly
samples shall be taken at least 30 days apart.

(iv)  For other solid fuels other than coal and(except MSW), weekly
sampling is required to obtain composite samples, which are then
analyzed monthly.

(v)  For fuel blends that are received already mixed, as described in
paragraph (a)(3)(ii) of this section, determine the HHV of the blend as
follows.  For blends of solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are analyzed monthly.  For
blends of liquid or gaseous fuels, sampling and analysis is required at
least once per calendar quarter.  More frequent sampling is recommended
if the composition of the blend varies significantly during the year.

(3)  If different types of fuel (e.g., different ranks of coal or
different grades of fuel oil) are blended prior to combustion, use one
of the following procedures in this paragraph.Special Considerations for
Blending of Fuels.  In situations where different types of fuel listed
in Table C-1 of this subpart (for example, different ranks of coal or
different grades of fuel oil) are in the same state of matter (i.e.,
solid, liquid, or gas), and are blended prior to combustion, use the
following procedures to determine the appropriate CO2 emission factor
and HHV for the blend.

(i)  Use a weighted HHV value in the emission calculations, based on the
relative proportions of each fuel in the blendIf the fuels to be blended
are received separately, and if the quantity (mass or volume) of each
fuel is measured  before the fuels are mixed and combusted, then, for
each component of the blend, calculate the CO2 mass emissions
separately.  Substitute into Equation C-2a of this subpart the total
measured mass or volume of the component fuel (from company records),
together with the appropriate default CO2 emission factor from Table
C-1, and the annual average HHV, calculated according to
§98.33(a)(2)(ii).  In this case, the fact that the fuels are blended
prior to combustion is of no consequence.

(ii)  Take a representative sample of the blend and analyze it for
HHV.If the fuel is received as a blend (i.e., already mixed), a
reasonable estimate of the relative proportions of the components of the
blend must be made, using the best available information (e.g., the
approximate annual average mass or volume percentage of each fuel, based
on the typical or expected range of values). Determine the appropriate
CO2 emission factor and HHV for use in Equation C-2a of this subpart, as
follows:

(A)  Consider the blend to be the “fuel type,” measure its HHV at
the frequency prescribed in paragraph (a)(2)(v) of this section, and
determine the annual average HHV value for the blend according to
§98.33(a)(2)(ii).

(B)  Calculate a heat-weighted CO2 emission factor, (EF)B, for the
blend, using Equation C-16 of this section. The heat-weighting in
Equation C-16 is provided by the default HHVs (from Table C-1) and the
estimated mass or volume percentages of the components of the blend.

(C)  Substitute into Equation C-2a of this subpart, the annual average
HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the
calculated value of (EF)B, along with the total mass or volume of the
blend combusted during the reporting year, to determine the annual CO2
mass emissions from combustion of the blend.

 	(Eq. C-16)

Where:

(EF)B	=	Heat-weighted CO2 emission factor for the blend (kg CO2/mmBtu)

(HHV)I	=	Default high heat value for fuel “i” in the blend, from
Table C-1 (mmBtu per mass or volume)

(%Fuel)I	=	Estimated mass or volume percentage of fuel “i” (mass %
or volume %, as applicable, expressed as a decimal fraction; e.g., 25% =
0.25)

(EF)I	=	Default CO2 emission factor for fuel “i” from Table C-1
(mmBtu per mass or volume)

(HHV)B	=	Annual average high heat value for the blend, calculated
according to §98.33(a)(2)(ii) (mmBtu per mass or volume)

(iii)  Note that for the case described in paragraph (a)(3)(ii) of this
section, if measured HHV values for the individual fuels in the blend or
for the blend itself are not routinely received at the minimum frequency
prescribed in paragraph (a)(2) of this section (or at a greater
frequency), and if the unit qualifies to use Tier 1, calculate (HHV)B*,
the heat-weighted default HHV for the blend, using Equation C-17 of this
section.  Then, use Equation C-16 of this section, replacing the term
(HHV)B with (HHV)B* in the denominator, to determine the heat-weighted
CO2 emission factor for the blend.  Finally, substitute into Equation
C-1 of this subpart, the calculated values of (HHV)B* and (EF)B, along
with the total mass or volume of the blend combusted during the
reporting year, to determine the annual CO2 mass emissions from
combustion of the blend.

 	(Eq. C-17)

Where:

(HHV)B*	=	Heat-weighted default high heat value for the blend (mmBtu per
mass or Volume)

(HHV)I	=	Default high heat value for fuel “i” in the blend, from
Table C-1 (mmBtu per mass or volume)

(%Fuel)I	=	Estimated mass or volume percentage of fuel “i” in the
blend (mass % or volume %, as applicable, expressed as a decimal
fraction)

(iv)  If the fuel blend described in paragraph (a)(3)(ii) of this
section consists of a mixture of fuel(s) listed in Table C-1 of this
subpart and one or more fuels not listed in Table  C-1, calculate CO2
and other GHG emissions only for the Table C-1 fuel(s), using the best
available estimate of the mass or volume percentage(s) of the Table C-1
fuel(s) in the blend.  In this case, Tier 1 shall be used, with the
following modifications to Equations C-17 and C-1, to account for the
fact that not all of the fuels in the blend are listed in Table C-1:

(A)  In Equation C-17, apply the term (Fuel)i only to the Table C-1
fuels.  For each Table C-1 fuel, (Fuel)i will be the estimated mass or
volume percentage of the fuel in the blend, divided by the sum of the
mass or volume percentages of the Table C-1 fuels.  For example, suppose
that a blend consists of two Table C-1 fuels (“A” and “B”) and
one fuel type (“C”) not listed in the Table, and that the volume
percentages of fuels A, B, and C in the blend, expressed as decimal
fractions, are, respectively, 0.50, 0.30, and 0.20.  The term (Fuel)i in
Equation C-17 for fuel A will be 0.50/(0.50 + 0.30) = 0.625, and for
fuel B, (Fuel)i will be 0.30/(0.50 + 0.30) = 0.375.

(B)  In Equation C-1, the term “Fuel” will be equal to the total
mass or volume of the blended fuel combusted during the year multiplied
by the sum of the mass or volume percentages of the Table C-1 fuels in
the blend.  For the example in paragraph (a)(3)(iv)(A) of this section,
  “Fuel” = (Annual volume of the blend combusted)(0.80).

(4)  If, for a particular type of fuel, HHV sampling and analysis is
performed more often than the minimum frequency specified in paragraphs
(a)(2)of this section, the results of all valid fuel analyses shall be
used in the GHG emission calculations.

(5)  If, for a particular type of fuel, valid HHV values are obtained at
less than the minimum frequency specifed in paragraphs (a)(2) of this
section, appropriate substitute data values shall be used in the
emissions calculations, in accordance with missing data procedures of
§98.35.

(6)  You must use one of the following appropriate fuel sampling and
analysis methods.  You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the high heat values.
Consensus-based standards organizations include, but are not limited to,
the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute
(API), and the North American Energy Standards Board (NAESB).   Use any
applicable fuel sampling and analysis methods in this paragraph (a)(6)
to determine the high heat values.  Alternatively, for gaseous fuels,
the HHV may be calculated using chromatographic analysis together with
standard heating values of the fuel constituents, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer’s instructions.  The method(s) used shall be documented
in the Monitoring Plan required under §98.3(g)(5).

(i)  ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid
Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated
by reference, see §98.7).

(ii)  ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated
by reference, see §98.7).

(iii)  ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter (incorporated by reference, see §98.7).

(iv)  ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and Relative Density of Gaseous
Fuels (incorporated by reference, see §98.7).

(v)  ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating
Value of Gases in Natural Gas Range by Stoichiometric Combustion
(incorporated by reference, see §98.7).

(vi)  GPA Standard 2172–09 Calculation of Gross Heating Value,
Relative Density, Compressibility and Theoretical Hydrocarbon Liquid
Content for Natural Gas Mixtures for Custody Transfer (incorporated by
reference, see §98.7).

(vii)  GPA Standard 2261–00, Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see
§98.7).

(viii)  ASTM D5865-07a, Standard Test Method for Gross Calorific Value
of Coal and Coke (incorporated by reference, see §98.7).

(b)  For the Tier 3 Calculation Methodology:

(1)  Calibrate You must calibrate each oil and gas flow meter according
to §98.3(i) and the provisions of this paragraph (b)(1).

(i)  Perform calibrations using any of the test methods and procedures
in this paragraph (b)(1)(i).  The method(s) used shall be documented in
the Monitoring Plan required under §98.3(g)(5).:

(A)  You may use an appropriate flow meter calibration method published
by a consensus standards organization, if such a method exists.
Consensus-based standards organizations include, but are not limited to,
the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum Institute
(API), and the North American Energy Standards Board (NAESB).An
applicable flow meter test method listed in paragraphs (b)(4)(i) through
(b)(4)(viii) of this section.

(B)  You may use Tthe calibration procedures specified by the flow meter
manufacturer.

(C)  You may use aAn industry-accepted or industry consensus standard
calibration practice.

(ii)  In addition to the initial calibration required by §98.3(i),
recalibrate each fuel flow meter (except for qualifying billing meters
under as otherwise provided in paragraph (b)(1)(iii) of this section)
either annually, at the minimum frequency specified by the manufacturer,
or at the interval specified by the industry consensus standard practice
used.

(iii)  Fuel billing meters are exempted from the initial and ongoing
calibration requirements of this paragraph and from the Monitoring Plan
and recordkeeping requirements of §98.3(g)(5)(i)(C) and (g)(7),
provided that the fuel supplier and the unit combusting the fuel do not
have any common owners and are not owned by subsidiaries or affiliates
of the same company.  Meters used exclusively to measure the flow rates
of fuels that are only used for unit startup or ignition are also
exempted from the initial and ongoing calibration requirements of this
paragraph.

(iv)  For the initial calibration of an orifice, nozzle, or venturi
meter; in-situ calibration of the transmitters is sufficient.  A primary
element inspection (PEI) shall be performed at least once every three
years.

(v)  For the continuously-operating units and processes described in
§98.3(i)(6), the required flow meter recalibrations and, if necessary,
the PEIs may be postponed until the next scheduled maintenance outage.

(vi)  If a mixture of liquid or gaseous fuels is transported by a common
pipe (e.g., still gas and supplementary natural gas), you must may
either separately meter each of the fuels prior to mixing, using flow
meters calibrated according to §98.3(i), or consider the fuel mixture
to be the “fuel type” and meter the mixed fuel, using ause flow
meters calibrated according to §98.3(i) to measure the mixed fuel at
the common pipe and to separately meter an appropriate subset of the
fuels prior to mixing.  If the latter option is chosen, quantify the
fuels that are not measured prior to mixing by subtracting out the fuels
measured prior to mixing from the fuel measured at the common pipe.

(2)  Oil tank drop measurements (if used to determine liquid fuel use
volume) shall be performed according to any an appropriate method
published by a consensus-based standards organization (e.g., the
American Petroleum Institute).

(3)  The carbon content and, if applicable, molecular weight of the
fuels shall be determined according to the procedures in paragraph
(b)(3).

(i)  All fuel samples shall be taken at a location in the fuel handling
system that provides a sample representative of the fuel combusted.  The
fuel sampling and analysis may be performed by either the owner or
operator or by the supplier of the fuel.

(ii)  At aFor each type of fuel, the minimum required frequency , fuel
samples shall be for collecteding and analyzing samples for carbon
content and (if applicable) molecular weight at the frequencyis
specified in this paragraph.  When the sampling frequency is required at
based on a specified time interval period (e.g., weekly, monthly,
quarterly, or semiannuallyhalf-year), fuel sampling and analysis is
required for only those time specified periods in which the fuel is
combustedunit operates.

(A)  For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at least
four months apart).

(B)  For coal and fuel oil and for any other solid or liquid fuel that
is delivered in lots, analysis of at least one representative sample
from each fuel lot is required.  For fuel oil, as an alternative to
sampling each fuel lot, a sample may be taken upn each addition of oil
to the storage tank.  Flow proportional sampling, continuous drip
sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot.  For the purposes of this section, a fuel lot is
defined as either of the following:

(1)  aA shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via pipeline
from a tank farm, etc.).

(2)  If multiple deliveries of a particular type of fuel are received
from the same supply source in a given calendar month, the deliveries
for that month are considered, collectively, to comprise a fuel lot,
requiring only one representative sample.

(C)  For other liquid fuels other than fuel oil, for fossil fuel-derived
gaseous fuels, and for biogas; sampling and analysis is required at
least once per calendar quarter.  To the extent practicable, consecutive
quarterly samples shall be taken at least 30 days apart.

(D)  For other solid fuels other than coal(except MSW), weekly sampling
is required to obtain composite samples, which are then analyzed
monthly.

(E)  For gaseous fuels other than natural gas and biogas (e.g., refinery
process gas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if the necessary
continuous, on-line equipment, such as a gas chromatograph, is in place
to make these measurements.  Otherwise, weekly sampling and analysis
shall be performed.

(F)  For mixtures (blends) of solid fuels, weekly sampling is required
to obtain composite samples, which are analyzed monthly.  For blends of
liquid fuels, and for gas mixtures consisting only of natural gas and
biogas, sampling and analysis is required at least once per calendar
quarter.  For gas mixtures that contain gases other than natural gas
(including biogas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if continuous,
on-line equipment is in place to make these measurements.  Otherwise,
weekly sampling and analysis shall be performed.

(iii)  If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed more often than the
minimum frequency specified in paragraph (b)(3) of this section, the
results of all valid fuel analyses shall be used in the GHG emission
calculations.

(iv)  If, for a particular type of fuel, sampling and analysis for
carbon content and molecular weight is performed at less than the
minimum frequency specifed in paragraph (b)(3) of this section,
appropriate substitute data values shall be used in the emissions
calculations, in accordance with the missing data procedures of §98.35.

(v)  To calculate the CO2 mass emissions from combustion of a blend of
fuels in the same state of matter (solid, liquid, or gas), you may
either:

(A)  Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to
each component of the blend, if the mass or volume, the carbon content,
and (if applicable), the molecular weight of each component are
accurately measured prior to blending; or

(B)  Consider the blend to be the “fuel type”.  Then, at the
frequency specified in paragraph (b)(3)(ii)(F) of this section, measure
the carbon content and, if applicable, the molecular weight of the blend
and calculate the annual average value of each parameter in the manner
described in §98.33(a)(2)(ii).  Also measure the mass or volume of the
blended fuel combusted during the reporting year. Substitute these
measured values into Equation C-3, C-4, or C-5 of this subpart (as
applicable).The procedures of paragraphs (a)(3) of this section apply to
carbon content and molecular weight determinations.

(4)  Use any applicable standard method from the following list to
quality assure the data from each fuel flow meter.

(i)  AGA Report No. 3, Orifice Metering of Natural Gas and Other Related
Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines
(1990) and Part 2: Specification and Installation Requirements
(2000)(incorporated by reference, see §98.7).

(ii)  AGA Transmission Measurement Committee Report No. 7, Measurement
of Gas by Turbine Meters (2006) (incorporated by reference, see §98.7).

(iii)  ASME MFC–3M–2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi (incorporated by reference, see §98.7).

(iv)  ASME MFC–4M–1986 (Reaffirmed 1997), Measurement of Gas Flow by
Turbine Meters (incorporated by reference, see §98.7).

(v)  ASME MFC–5M–1985 (Reaffirmed 1994), Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see §98.7).

(vi)  ASME MFC–6M–1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters (incorporated by reference, see §98.7).

(vii)  ASME MFC–7M–1987 (Reaffirmed 1992), Measurement of Gas Flow
by Means of Critical Flow Venturi Nozzles (incorporated by reference,
see §98.7).

(viii)  ASME MFC–9M–1988 (Reaffirmed 2001), Measurement of Liquid
Flow in Closed Conduits by Weighing Method (incorporated by reference,
see §98.7).

(45)  You must use one of the following appropriate fuel sampling and
analysis methods.  You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel.  Consensus-based
standards organizations include, but are not limited to, the following:
ASTM International, the American National Standards Institute (ANSI),
the American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and the North
American Energy Standards Board (NAESB).  Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated,  maintained, and calibrated according to the
manufacturer’s instructions.  The method(s) used shall be documented
in the Monitoring Plan required under §98.3(g)(5).Use any applicable
methods from the following list to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel. Alternatively, the
results of chromatographic analysis of the fuel may be used, provided
that the gas chromatograph is operated,  maintained, and calibrated
according to the manufacturer’s instructions.

(i)  ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by reference, see §98.7).

(ii)  ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography (incorporated by reference, see
§98.7).

(iii)  ASTM D2502-04 (Reapproved 2002) Standard Test Method for
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements (incorporated by reference, see
§98.7).

(iv)  ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative
Molecular Mass (Relative Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure (incorporated by reference,
see §98.7).

(v)  ASTM D3238-95 (Reapproved 2005) Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method (incorporated by reference, see
§98.7).

(vi)  ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (incorporated by reference, see
§98.7).

(vii)  ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of
Coal (incorporated by reference, see §98.7).

(c)  For the Tier 4 Calculation Methodology, the CO2, and flow rate, and
(if applicable) moisture monitors must be certified prior to the
applicable deadline specified in §98.33(b)(5).

(1)  For initial certification, you may use any one of the following
three procedures in this paragraph.

(i)  Sections §75.20(c)(2), and (c)(4), and (c)(5) though (c)(7) of
this chapter and appendix A to 40 CFR part 75 of this chapter.

(ii)  The calibration drift test and relative accuracy test audit (RATA)
procedures of Performance Specification 3 in appendix B to part 60 of
this chapter (for the CO2 concentration monitor) and Performance
Specification 6 in appendix B to part 60 of this chapter (for the
continuous emission rate monitoring system (CERMS)).

(iii)  The provisions of an applicable State continuous monitoring
program.

(2)  If an O2 concentration monitor is used to determine CO2
concentrations, the applicable provisions of 40 CFR part 75 of this
chapter, 40 CFR part 60 of this chapter, or an applicable State
continuous monitoring program shall be followed for initial
certification and on-going quality assurance, and all required RATAs of
the monitor shall be done on a percent CO2 basis.

(3)  For ongoing quality assurance, follow the applicable procedures in
either appendix B to 40 CFR part 75 of this chapter, appendix F to 40
CFR part 60 of this chapter, or an applicable State continuous
monitoring program.  If appendix F to 40 CFR part 60 of this chapter is
selected for on-going quality assurance, perform daily calibration drift
assessments for both the CO2 monitor (or surrogate O2 monitor) and the
flow rate monitor, conduct cylinder gas audits of the CO2 concentration
monitor in three of the four quarters of each year (except for
non-operating quarters), and perform annual RATAs of the CO2
concentration monitor and the CERMS.

(4)  For the purposes of this part, the stack gas volumetric flow rate
monitor RATAs required by appendix B to 40 CFR part 75 of this chapter
and the annual RATAs of the CERMS required by appendix F to 40 CFR part
60 of this chapter need only be done at one operating level,
representing normal load or normal process operating conditions, both
for initial certification and for ongoing quality assurance.

(5)  If, for any source operating hour, quality assured data are not
obtained with a CO2 monitor (or surrogate O2 monitor), flow rate
monitor, or (if applicable) moisture monitor, use appropriate substitute
data values  in accordance with the missing data provisions of §98.35.

(6)  For certain applications where combined process emissions and
combustion emissions are measured, the CO2 concentrations in the flue
gas may be considerably higher than for combustion emissions alone.  In
such cases, the span of the CO2 monitor may, if necessary, be set higher
than the specified levels in the applicable regulations.  If the CO2
span value is set higher than 20 percent CO2, the cylinder gas audits of
the CO2 monitor under appendix F to part 60 of this chapter may be
performed at 40 to 60 percent and 80 to 100 percent of span, in lieu of
the prescribed calibration levels of 5 to 8 percent CO2 and 10 to 14
percent CO2.

(7)  Hourly average data from the CEMS shall be validated in a manner
consistent with one of the following: §§60.13(h)(2)(i) through
(h)(2)(vi) of this chapter; §75.10(d)(1) of this chapter; or the hourly
data validation requirements of an applicable State CEM regulation.

(d)  When municipal solid waste (MSW) is either the primary fuel
combusted in a unit or the only fuel with a biogenic component combusted
in the unit, determine the biogenic portion of the CO2 emissions from
MSW combustion using ASTM D6866-08 Standard Test Methods for Determining
the Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis (incorporated by reference, see §98.7) and ASTM
D7459-08 Standard Practice for Collection of Integrated Samples for the
Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide
Emitted from Stationary Emissions Sources (incorporated by reference,
see §98.7).  Perform the ASTM D7459-08 sampling and the ASTM D6866-08
analysis at least once in every calendar quarter in which MSW is
combusted in the unit.  Collect each gas sample during normal unit
operating conditions while MSW is the only fuel being combusted for at
least 24 consecutive hours or for as long as is deemed necessary to
obtain a representative sample large enough to meet the specifications
of ASTM D6866-08.  One suggested alternative sampling approach would be
to collect an  integrated sample by extracting a small amount of flue
gas (e.g., 1 to 5 cc) in each unit operating hour during the quarter.
Separate the total annual CO2 emissions into the biogenic and
non-biogenic fractions using the average proportion of biogenic
emissions of all samples analyzed during the reporting year.  Express
the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
from MSW combustion is biogenic).  When MSW is the primary fuel for
multiple units at the facility, and the units are fed from aIf there is
a common fuel source of MSW that feeds multiple units at the facility,
performing the testing at only one of the units is sufficient.

(e)  For other units that use CEMS to measure the total CO2 mass
emissions and combust a combinations of biogenic fuelsbiomass fuel(s)
(or heterogeneous fuels that have a biomass component, e.g., tires) and
(other than MSW) with a fossil (or other non-biogenic) fuel(s), in any
proportions, ASTM D6866-08 and ASTM D7459-08 may be used to determine
the biogenic portion of the CO2 emissions.  Perform the ASTM D7459-08
sampling and the ASTM D6866-08 analysis at least once in every calendar
quarter in which biogenic biomass and non-biogenic fuels are co-fired in
the unit.  The relative proportions of the biogenic and non-biogenic
fuels during the sampling shall be representative of the average fuel
blend for a typical operating year.  Collect each gas sample using ASTM
D7459-08 during normal unit operation for at least 24 consecutive hours
or for as long as is necessary to obtain a representative sample large
enough to meet the specifications of ASTM D6866-08.  If the types of
fuels combusted in the unit and their relative proportions are not
consistent throughout the quarter, more frequent, periodic sampling of
the flue gas should be considered.  For example, an integrated sample
could be collected by extracting a small amount of the flue gas (e.g., 1
to 5 cc) in each unit operating hour of the quarter.  If the primary
fuel for multiple units at the facility consists of tires, and the units
are fed from a common fuel source, testing at only one of the units is
sufficient.

(f)  Whenever company records are used in the calculation of CO2
emissions, tThe records required under §98.3(g)(2)(i) shall include an
explanation of how the following parameters are determined fromboth the
company records (or, if applicable, from the best available information)
and an explanation of how those records are used to estimate the
following parameters:

(1)  Fuel consumption, when the Tier 1 and Tier 2 Calculation
Methodologies are used, including cases where §98.36(c)(4) applies.

(2)  Fuel consumption, when solid fuel is combusted and the Tier 3
Calculation Methodology is used.

(3)  Fossil fuel consumption when §98.33(e)(2) applies to a unit that
uses CEMS to quantify CO2 emissions and that combusts both fossil and
biomass fuels.

(4)  Sorbent usage, when §98.33(d) applies.

(5)  Quantity of steam generated by a unit when §98.33(a)(2)(iii)
applies.

(6)  Biogenic fuel consumption under §98.33(e)(5).

(7)  Fuel usage for CH4 and N2O emissions calculations under
§98.33(c)(4)(ii).

(8)  Mass of biomass combusted, for premixed fuels that contain biomass
and fossil fuels under §98.33(e)(1)(iii).(g)  As part of the GHG
Monitoring Plan required under §98.3(g)(5), you must document the
procedures used to ensure the accuracy of the estimates of fuel usage,
sorbent usage, steam production, and boiler efficiency (as applicable)
in paragraph (f) of this section, including but not limited to
calibration of weighing equipment, fuel flow meters, steam flow meters,
and other measurement devices.  The estimated accuracy of measurements
made with these devices shall also be recorded, and the technical basis
for these estimates shall be provided.

§98.35  Procedures for estimating missing data.

Whenever a quality-assured value of a required parameter is unavailable
(e.g., if a CEMS malfunctions during unit operation or if a required
fuel sample is not taken), a substitute data value for the missing
parameter shall be used in the calculations.

(a)  For all units subject to the requirements of the Acid Rain Program,
and all other stationary combustion units subject to the requirements of
this part that monitor and report emissions and heat input data in
accordance with 40 CFR part 75 of this chapter, the missing data
substitution procedures in 40 CFR part 75 of this chapter shall be
followed for CO2 concentration, stack gas flow rate, fuel flow rate,
high heating value, and fuel carbon content.

(b)  For units that use the Tier 1, Tier 2, Tier 3, and Tier 4
Calculation Methodologies, perform missing data substitution as follows
for each parameter:

(1)  For each missing value of the high heating value, carbon content,
or molecular weight of the fuel, substitute the arithmetic average of
the quality-assured values of that parameter immediately preceding and
immediately following the missing data incident.  If the “after”
value has not been obtained by the time that the GHG emissions report is
due, you may use the “before” value for missing data substitution or
the best available estimate of the parameter, based on all available
process data (e.g., electrical load, steam production, operating hours).
 If, for a particular parameter, no quality-assured data are available
prior to the missing data incident, the substitute data value shall be
the first quality-assured value obtained after the missing data period.

(2)  For missing records of CO2 concentration, stack gas flow rate,
percent moisture, fuel usage, and sorbent usage, the substitute data
value shall be the best available estimate of the parameter, based on
all available process data (e.g., electrical load, steam production,
operating hours, etc.).  You must document and retain records of the
procedures used for all such estimates.

§98.36  Data reporting requirements.

(a)  In addition to the facility-level information required under
§98.3, the annual GHG emissions report shall contain the unit-level or
process-level emissions data in paragraphs (b) through (d) of this
section (as applicable) and the emissions verification data in paragraph
(e) of this section.

(b)  Units that use the four tiers.  You shall report the following
information for  stationary combustion units that use the Tier 1, Tier
2, Tier 3, or Tier 4 methodology in §98.33(a) to calculate CO2
emissions, except as otherwise provided in paragraphs (c) and (d) of
this section:

(1)  The unit ID number.

(2)  A code representing the type of unit.

(3)  Maximum rated heat input capacity of the unit, in mmBtu/hr for
boilers and process heaters only and relevant units of measure for other
combustion sources.

(4)  Each type of fuel combusted in the unit during the report year.

(5)  The methodology (i.e., tier) used to calculate the CO2 emissions
for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).

(6)  The methodology start date, for each fuel type.

(7)  The methodology end date, for each fuel type.

(86)  For a unit that uses Tiers 1, 2, and or 3;:

(i)  tThe annual CO2 mass emissions (including biogenic CO2), and the
annual, CH4, and N2O mass emissions for each type of fuel combusted
during the reporting year, expressed in metric tons of each gas and in
metric tons of CO2e; and

(ii)  Metric tons of biogenic CO2 emissions (if applicable).

(97)  For a unit that uses Tier 4:

(i)  For units that burn fossil fuels only, the annual CO2 emissions for
all fuels combined.  Reporting If the total annual CO2 mass emissions
measured by the CEMS consists entirely of non-biogenic CO2 (i.e., CO2
from fossil fuel combustion plus, if applicable, CO2 from sorbent and/or
process CO2), report the total annual CO2 mass emissions, expressed in
metric tons.  You are not required to report the combustion CO2
emissions by fuel type of fuel is not required.

(ii)  For units that burn both fossil fuels and biomass, the annual CO2
emissions from combustion of all fossil fuels combined and the annual
CO2 emissions from combustion of all biomass fuels combined.  Reporting
If the total annual CO2 mass emissions measured by the CEMS includes
both biogenic and non-biogenic CO2, separately report the annual
non-biogenic CO2 mass emissions and the annual CO2 mass emissions from
biomass combustion, each expressed in metric tons.  You are not required
to report the combustion CO2 emissions by fuel type of fuel is not
required.

(iii)  An estimate of the heat input from each type of fuel listed in
Table C-2 of this subpart that was combusted in the unit during the
report year, and the Aannual CH4 and N2O emissions for each type of
these fuels combusted, expressed in metric tons of each gas and in
metric tons of CO2e.

(108)  Annual CO2 emissions from sorbent (if calculated using Equation
C-11 of this subpart), expressed in metric tons.

(9)  Annual GHG emissions from all fossil fuels burned in the unit
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e.

(10)  Customer meter number for units that combust natural gas.

(c)  Reporting alternatives for units using the four Tiers.  You may use
any of the applicable reporting alternatives of this paragraph to
simplify the unit-level reporting required under paragraph (b) of this
section:

(1)  Aggregation of units.  If a facility contains two or more units
(e.g., boilers or combustion turbines), each of which has a maximum
rated heat input capacity of 250 mmBtu/hr or less, you may report the
combined GHG emissions for the group of units in lieu of reporting GHG
emissions from the individual units, provided that the use of Tier 4 is
not required or elected for any of the units and the units use the same
tier for any common fuels combusted.  If this option is selected, the
following information shall be reported instead of the information in
paragraph (b) of this section:

(i)  Group ID number, beginning with the prefix “GP”.

(ii)  TheAn identification number for eachof units in the group.

(iii)  Cumulative maximum rated heat input capacity of the group
(mmBtu/hr).

(iv)  The highest maximum rated heat input capacity of any unit in the
group (mmBtu/hr).

(v)  Each type of fuel combusted in the group of units during the
reporting year.

(vi)  Annual CO2 mass emissions and annual, CH4, and N2O mass emissions
aggregated for each type of fuel combusted in the group of units during
the report year, expressed in metric tons of each gas and in metric tons
of CO2e. If any of the units burn both fossil fuels and biomass, report
also the annual CO2 emissions from combustion of all fossil fuels
combined and annual CO2 emissions from combustion of all biomass fuels
combined, expressed in metric tons.

(vii)  The methodology (i.e., tier) used to calculate the CO2 mass
emissions for each type of fuel combusted in the units (i.e., Tier 1,
Tier 2, or Tier 3).

(viii)  The methodology start date, for each fuel type.

(ix)  The methodology end date, for each fuel type.

(xviii)  The calculated CO2 mass emissions (if any) from sorbent
expressed in metric tons.

(ix)  Annual GHG emissions from all fossil fuels burned in the group
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e.

(2)  Monitored common stack or duct configurations.  When the flue gases
from two or more stationary fuel combustion units at a facility are
discharged throughcombined together in a common stack or duct before
exiting to the atmosphere and if CEMS are used to continuously monitor
CO2 mass emissions at the common stack or duct according to the Tier 4
Calculation Methodology, you may report the combined emissions from the
units sharing the common stack or duct, in lieu of separately reporting
the GHG emissions from the individual units.  This monitoring and
reporting alternative may also be used when process off-gases or a
mixture of combustion products and process gases are combined together
in a common stack or duct before exiting to the atmosphere.  Whenever
the common stack or duct monitoring option is applied, tThe following
information shall be reported instead of the information in paragraph
(b) of this section:

(i)  Common stack or duct identification number, beginning with the
prefix “CS”.

(ii)  Identification nNumbers of the units sharing the common stack or
duct.  Report “1” when the flue gas flowing through the common stack
or duct includes both combustion products and process off-gases, and all
of the effluent comes from a single unit (e.g., a furnace, kiln, or
smelter).

(iii)  MCombined maximum rated heat input capacity of each the units
sharing the common stack or duct (mmBtu/hr).  This data element is
required only when all of the units sharing the common stack are
stationary fuel combustion units.

(iv)  Each type of fuel combusted in the units during the year.

(v)  The methodology (tier) used to calculate the CO2 mass emissions,
i.e., Tier 4.

(vi)  The methodology start date.

(vii)  The methodology end date.

(viiivi)  Total annual CO2 mass emissions measured by the CEMS,
expressed in metric tons.  If the any of the units burn both fossil
fuels and biomass, separately report the annual non-biogenic CO2 mass
emissions (i.e., CO2 from fossil fuel combustion plus, if applicable,
CO2 from sorbent and/or process CO2), annual CO2 emissions from
combustion of fossil fuels, and the annual CO2 mass emissions from
combustion of biomass combustionmeasured at the common stack or duct,
each expressed in metric tons.

(ixvii)  An estimate of the heat input from each type of fuel listed in
Table C-2 of this subpart that was combusted during the report year in
the units sharing the common stack or duct during the report year, and,
for each of these fuels, tThe annual CH4 and N2O mass emissions from the
units sharing the common stack or duct, expressed in metric tons of each
gas and in metric tons of CO2e.

(viii)  Annual GHG emissions from all fossil fuels burned in the group
(i.e., the sum of the CO2 , CH4, and N2O emissions), expressed in metric
tons of CO2e.

(3)  Common pipe configurations.  When two or more  liquid-fired or
gaseous-fired stationary combustion units at a facility combust the same
type of fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting the GHG emissions from the individual units, provided that the
total amount of fuel combusted by the units is accurately measured at
the common pipe or supply line using a fuel flow meter.  For Tier 3
applications, the flow meter shall be that is calibrated in accordance
with §98.34(a) §98.34(b).  If a portion of the fuel measured at the
common pipemain supply line is diverted to either:  a flare; or another
stationary fuel combustion unit (or units), including units that use a
CO2 mass emissions calculation method in part 75 of this chapter; or a
chemical or industrial process (where it is used as a raw material but
not combusted), and the remainder of the fuel is distributed to a group
of combustion units for which you elect to use the common pipe reporting
option, you may use company records to subtract out the diverted portion
of the fuel from the fuel measured at the main supply linecommon pipe
prior to performing the GHG emissions calculations, provided that the
amount of fuel diverted is also measured with a calibrated flow meter
per §98.3(i) for the group of units using the common pipe option.  If
the diverted portion of the fuel is combusted, the GHG emissions from
the diverted portion shall be accounted for in accordance with the
applicable provisions of this part.  When the common pipe option is
selected, the applicable tier shall be used based on the maximum rated
heat input capacity of the largest unit served by the common pipe
configuration, except where the applicable tier is based on criteria
other than unit size. For example, if the maximum rated heat input
capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 will
apply, unless the fuel transported through the common pipe is natural
gas or distillate oil, in which case Tier 2 may be used, in accordance
with §98.33(b)(2)(ii).  As a second example, in accordance with