Mandatory Reporting of Greenhouse Gases, 16448-16731 [E9-5711]
Download as PDF
<![CDATA[
16448
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 86, 87, 89, 90, 94, 98, 600,
1033, 1039, 1042, 1045, 1048, 1051,
1054, and 1065
[EPA–HQ–OAR–2008–0508; FRL–8782–1]
RIN 2060–A079
Mandatory Reporting of Greenhouse
Gases
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Proposed rule.
SUMMARY: EPA is proposing a regulation
to require reporting of greenhouse gas
emissions from all sectors of the
economy. The rule would apply to fossil
fuel suppliers and industrial gas
suppliers, as well as to direct
greenhouse gas emitters. The proposed
rule does not require control of
greenhouse gases, rather it requires only
that sources above certain threshold
levels monitor and report emissions.
DATES: Comments must be received on
or before June 9, 2009. There will be two
public hearings. One hearing was held
on April 6 and 7, 2009, in the
Washington, DC, area (One Potomac
Yard, 2777 S. Crystal Drive, Arlington,
VA 22202). One hearing will be on April
16, 2009 in Sacramento, CA
(Sacramento Convention Center, 1400 J
Street, Sacramento, CA 95814). The
April 16, 2009 hearing will begin at 9
a.m. local time.
ADDRESSES: Submit your comments,
identified by Docket ID No. EPA–HQ–
OAR–2008–0508, by one of the
following methods:
• Federal eRulemaking Portal: https://
www.regulations.gov. Follow the online
instructions for submitting comments.
• E-mail: a-and-r-Docket@epa.gov.
• Fax: (202) 566–1741.
• Mail: Environmental Protection
Agency, EPA Docket Center (EPA/DC),
Mailcode 6102T, Attention Docket ID
No. EPA–HQ–OAR–2008–0508, 1200
Pennsylvania Avenue, NW.,
Washington, DC 20460.
• Hand Delivery: EPA Docket Center,
Public Reading Room, EPA West
Building, Room 3334, 1301 Constitution
Avenue, NW., Washington, DC 20004.
Such deliveries are only accepted
during the Docket’s normal hours of
operation, and special arrangements
should be made for deliveries of boxed
information.
Instructions: Direct your comments to
Docket ID No. EPA–HQ–OAR–2008–
0508. EPA’s policy is that all comments
received will be included in the public
docket without change and may be
made available online at https://
www.regulations.gov, including any
personal information provided, unless
the comment includes information
claimed to be CBI or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through https://
www.regulations.gov or e-mail. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means EPA will not know your identity
or contact information unless you
provide it in the body of your comment.
If you send an e-mail comment directly
to EPA without going through https://
www.regulations.gov your e-mail
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, EPA may not be
able to consider your comment.
Electronic files should avoid the use of
special characters, any form of
encryption, and be free of any defects or
viruses.
Docket: All documents in the docket
are listed in the https://
www.regulations.gov index. Although
listed in the index, some information is
not publicly available, e.g., CBI or other
information whose disclosure is
restricted by statute. Certain other
material, such as copyrighted material,
will be publicly available only in hard
copy. Publicly available docket
materials are available either
electronically in https://
www.regulations.gov or in hard copy at
the Air Docket, EPA/DC, EPA West,
Room B102, 1301 Constitution Ave.,
NW., Washington, DC. This Docket
Facility is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holidays. The telephone number
for the Public Reading Room is (202)
566–1744, and the telephone number for
the Air Docket is (202) 566–1742.
FOR FURTHER INFORMATION CONTACT:
Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC–
6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW.,
Washington, DC 20460; telephone
number: (202) 343–9263; fax number:
(202) 343–2342; e-mail address:
GHGReportingRule@epa.gov. For
technical information, contact the
Greenhouse Gas Reporting Rule Hotline
at telephone number: (877) 444–1188; or
e-mail: ghgmrr@epa.gov. To obtain
information about the public hearings or
to register to speak at the hearings,
please go to https://www.epa.gov/
climatechange/emissions/
ghgrulemaking.html. Alternatively,
contact Carole Cook at 202–343–9263.
SUPPLEMENTARY INFORMATION:
Additional Information on Submitting
Comments: To expedite review of your
comments by Agency staff, you are
encouraged to send a separate copy of
your comments, in addition to the copy
you submit to the official docket, to
Carole Cook, U.S. EPA, Office of
Atmospheric Programs, Climate Change
Division, Mail Code 6207–J,
Washington, DC, 20460, telephone (202)
343–9263, e-mail
GHGReportingRule@epa.gov.
Regulated Entities. The Administrator
determines that this action is subject to
the provisions of CAA section 307(d).
See CAA section 307(d)(1)(V) (the
provisions of section 307(d) apply to
‘‘such other actions as the Administrator
may determine.’’). This is a proposed
regulation. If finalized, these regulations
would affect owners and operators of
fuel and chemicals suppliers, direct
emitters of GHGs and manufacturers of
mobile sources and engines. Regulated
categories and entities would include
those listed in Table 1 of this preamble:
TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY
Category
General Stationary
Sources.
Fuel
NAICS
Combustion
Examples of affected facilities
........................
Facilities operating boilers, process heaters, incinerators, turbines, and internal
combustion engines:
Extractors of crude petroleum and natural gas.
Manufacturers of lumber and wood products.
Pulp and paper mills.
Chemical manufacturers.
Petroleum refineries, and manufacturers of coal products.
211
321
322
325
324
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00002
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
16449
TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued
Category
NAICS
Examples of affected facilities
Electricity Generation ................................
316, 326, 339
331
332
336
221
622
611
221112
Manufacturers of rubber and miscellaneous plastic products.
Steel works, blast furnaces.
Electroplating, plating, polishing, anodizing, and coloring.
Manufacturers of motor vehicle parts and accessories.
Electric, gas, and sanitary services.
Health services.
Educational services.
Fossil-fuel fired electric generating units, including units owned by Federal and municipal governments and units located in Indian Country.
Adipic acid manufacturing facilities.
Primary Aluminum production facilities.
Anhydrous and aqueous ammonia manufacturing facilities.
Owners and operators of Portland Cement manufacturing plants.
Microcomputers manufacturing facilities.
Semiconductor, photovoltaic (solid-state) device manufacturing facilities.
LCD unit screens manufacturing facilities.
MEMS manufacturing facilities.
Ethyl alcohol manufacturing facilities.
Ferroalloys manufacturing facilities.
Industrial gases manufacturing facilities.
Meat processing facilities.
Frozen fruit, juice, and vegetable manufacturing facilities.
Fruit and vegetable canning facilities.
Flat glass manufacturing facilities.
Glass container manufacturing facilities.
Other pressed and blown glass and glassware manufacturing facilities.
Chlorodifluoromethane manufacturing facilities.
Adipic Acid Production ..............................
Aluminum Production ................................
Ammonia Manufacturing ...........................
Cement Production ...................................
Electronics Manufacturing ........................
325199
331312
325311
327310
334111
334413
334419
Ethanol Production ...................................
Ferroalloy Production ................................
Fluorinated GHG Production ....................
Food Processing .......................................
325193
331112
325120
311611
311411
311421
327211
327213
327212
325120
Glass Production ......................................
HCFC–22 Production and HFC–23 Destruction.
Hydrogen Production ................................
Iron and Steel Production .........................
325120
331111
Lead Production ........................................
331419
331492
327410
331419
331492
325311
486210
221210
325212
32511
325199
325110
325182
324110
325312
322110
322121
322130
327910
325181
221121
Lime Production ........................................
Magnesium Production .............................
Nitric Acid Production ...............................
Oil and Natural Gas Systems ...................
Petrochemical Production .........................
Petroleum Refineries ................................
Phosphoric Acid Production .....................
Pulp and Paper Manufacturing .................
Silicon Carbide Production .......................
Soda Ash Manufacturing ..........................
Sulfur Hexafluoride (SF6) from Electrical
Equipment.
Titanium Dioxide Production .....................
Underground Coal Mines ..........................
325188
212113
212112
331419
331492
Zinc Production .........................................
Landfills .....................................................
562212
221320
322110
322121
322122
322130
311611
311411
311421
322110
322121
322122
322130
Wastewater Treatment .............................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Hydrogen manufacturing facilities.
Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, basic
oxygen process furnace shops.
Primary lead smelting and refining facilities.
Secondary lead smelting and refining facilities.
Calcium oxide, calcium hydroxide, dolomitic hydrates manufacturing facilities.
Primary refiners of nonferrous metals by electrolytic methods.
Secondary magnesium processing plants.
Nitric acid manufacturing facilities.
Pipeline transportation of natural gas.
Natural gas distribution facilities.
Synthetic rubber manufacturing facilities.
Ethylene dichloride manufacturing facilities.
Acrylonitrile, ethylene oxide, methanol manufacturing facilities.
Ethylene manufacturing facilities.
Carbon black manufacturing facilities.
Petroleum refineries.
Phosphoric acid manufacturing facilities.
Pulp mills.
Paper mills.
Paperboard mills.
Silicon carbide abrasives manufacturing facilities.
Alkalies and chlorine manufacturing facilities.
Electric bulk power transmission and control facilities.
Titanium dioxide manufacturing facilities.
Underground anthracite coal mining operations.
Underground bituminous coal mining operations.
Primary zinc refining facilities.
Zinc dust reclaiming facilities, recovering from scrap and/or alloying purchased metals.
Solid waste landfills.
Sewage treatment facilities.
Pulp mills.
Paper mills.
Newsprint mills.
Paperboard mills.
Meat processing facilities.
Frozen fruit, juice, and vegetable manufacturing facilities.
Fruit and vegetable canning facilities.
Pulp mills.
Paper mills.
Newsprint mills.
Paperboard mills.
Frm 00003
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16450
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued
Category
NAICS
Examples of affected facilities
311611
311411
311421
325193
324110
112111
112120
112210
112310
112330
112320
212111
212113
212112
211111
324110
221210
211112
325120
325120
336112
333618
Manure Management ................................
Suppliers of Coal and Coal-based Products.
Suppliers of Coal Based Liquids Fuels ....
Suppliers of Petroleum Products ..............
Suppliers of Natural Gas and NGLs .........
Suppliers of Industrial GHGs ....................
Suppliers of Carbon Dioxide (CO2) ..........
Mobile Sources .........................................
Meat processing facilities.
Frozen fruit, juice, and vegetable manufacturing facilities.
Fruit and vegetable canning facilities.
Ethanol manufacturing facilities.
Petroleum refineries.
Beef cattle feedlots.
Dairy cattle and milk production facilities.
Hog and pig farms.
Chicken egg production facilities.
Turkey Production.
Broilers and Other Meat type Chicken Production.
Bituminous, and lignite coal surface mining facilities.
Anthracite coal mining facilities.
Underground bituminous coal mining facilities.
Coal liquefaction at mine sites.
Petroleum refineries.
Natural gas distribution facilities.
Natural gas liquid extraction facilities.
Industrial gas manufacturing facilities.
Industrial gas manufacturing facilities.
Light-duty vehicles and trucks manufacturing facilities.
Heavy-duty, non-road, aircraft, locomotive, and marine diesel engine manufacturing.
Heavy-duty vehicle manufacturing facilities.
Small non-road, and marine spark-ignition engine manufacturing facilities.
Personal watercraft manufacturing facilities.
Motorcycle manufacturing facilities.
336120
336312
336999
336991
Table 1 of this preamble is not
intended to be exhaustive, but rather
provides a guide for readers regarding
facilities likely to be regulated by this
action. Table 1 of this preamble lists the
types of facilities that EPA is now aware
could be potentially affected by this
action. Other types of facilities not
listed in the table could also be subject
to reporting requirements. To determine
whether your facility is affected by this
action, you should carefully examine
the applicability criteria found in
proposed 40 CFR part 98, subpart A. If
you have questions regarding the
applicability of this action to a
particular facility, consult the person
listed in the preceding FOR FURTHER
INFORMATION CONTACT section.
Many facilities that would be affected
by the proposed rule have GHG
emissions from multiple source
categories listed in Table 1 of this
preamble. Table 2 of this preamble has
been developed as a guide to help
potential reporters subject to the
mandatory reporting rule identify the
source categories (by subpart) that they
may need to (1) consider in their facility
applicability determination, and (2)
include in their reporting. For each
source category, activity, or facility type
(e.g., electricity generation, aluminum
production), Table 2 of this preamble
identifies the subparts that are likely to
be relevant. The table should only be
seen as a guide. Additional subparts
may be relevant for a given reporter.
Similarly, not all listed subparts would
be relevant for all reporters.
TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS
Source category (and main applicable subpart)
Subparts recommended for review to determine applicability
General Stationary Fuel Combustion Sources .........................................
Electricity Generation ...............................................................................
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Electricity Generation, Suppliers
of CO2, Electric Power Systems.
Adipic Acid Production, General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Hydrogen, Nitric Acid, Petroleum
Refineries, Suppliers of CO2.
General Stationary Fuel Combustion, Suppliers of CO2.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Landfills, Wastewater Treatment.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Landfills, Wastewater Treatment.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Petrochemicals, Petroleum Refineries, Suppliers of Industrial GHGs, Suppliers of CO2.
General Stationary Fuel Combustion, Suppliers of CO2.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
Adipic Acid Production .............................................................................
Aluminum Production ...............................................................................
Ammonia Manufacturing ...........................................................................
Cement Production ...................................................................................
Electronics Manufacturing ........................................................................
Ethanol Production ...................................................................................
Ferroalloy Production ...............................................................................
Fluorinated GHG Production ....................................................................
Food Processing .......................................................................................
Glass Production ......................................................................................
HCFC–22 Production and HFC–23 Destruction ......................................
Hydrogen Production ................................................................................
Iron and Steel Production .........................................................................
Lead Production .......................................................................................
Lime Manufacturing ..................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00004
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
16451
TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS—Continued
Source category (and main applicable subpart)
Subparts recommended for review to determine applicability
Magnesium Production .............................................................................
Nitric Acid Production ...............................................................................
Oil and Natural Gas Systems ...................................................................
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Adipic Acid.
General Stationary Fuel Combustion, Petroleum Refineries, Suppliers
of Petroleum Products, Suppliers of Natural Gas and NGL, Suppliers
of CO2.
General Stationary Fuel Combustion, Ammonia, Petroleum Refineries.
General Stationary Fuel Combustion, Hydrogen, Landfills, Wastewater
Treatment, Suppliers of Petroleum Products.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Landfills, Wastewater Treatment.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Suppliers of Coal.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Ethanol, Food Processing, Petroleum Refineries, Pulp and Paper.
General Stationary Fuel Combustion, Ethanol, Food Processing, Petroleum Refineries, Pulp and Paper.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Underground Coal Mines.
Suppliers of Coal, Suppliers of Petroleum Products.
General Stationary Fuel Combustion, Oil and Natural Gas Systems.
General Stationary Fuel Combustion, Oil and Natural Gas Systems,
Suppliers of CO2.
General Stationary Fuel Combustion, Hydrogen Production, Suppliers
of CO2.
General Stationary Fuel Combustion, Electricity Generation, Ammonia,
Cement, Hydrogen, Iron and Steel, Suppliers of Industrial GHGs.
General Stationary Fuel Combustion.
Petrochemical Production .........................................................................
Petroleum Refineries ................................................................................
Phosphoric Acid Production .....................................................................
Pulp and Paper Manufacturing .................................................................
Silicon Carbide Production .......................................................................
Soda Ash Manufacturing ..........................................................................
Sulfur Hexafluoride (SF6) from Electrical Equipment ...............................
Titanium Dioxide Production ....................................................................
Underground Coal Mines .........................................................................
Zinc Production .........................................................................................
Landfills .....................................................................................................
Wastewater Treatment .............................................................................
Manure Management ...............................................................................
Suppliers of Coal ......................................................................................
Suppliers of Coal-based Liquid Fuels ......................................................
Suppliers of Petroleum Products ..............................................................
Suppliers of Natural Gas and NGLs ........................................................
Suppliers of Industrial GHGs ....................................................................
Suppliers of Carbon Dioxide (CO2) ..........................................................
Mobile Sources .........................................................................................
Acronyms and Abbreviations. The
following acronyms and abbreviations
are used in this document.
A/C air conditioning
AERR Air Emissions Reporting Rule
ANPR advance notice of proposed
rulemaking
ARP Acid Rain Program
ASME American Society of Mechanical
Engineers
ASTM American Society for Testing and
Materials
BLS Bureau of Labor Statistics
CAA Clean Air Act
CAFE Corporate Average Fuel Economy
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CDX central data exchange
CEMS continuous emission monitoring
system(s)
CERR Consolidated Emissions Reporting
Rule
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CHP combined heat and power
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DE destruction efficiency
DOD U.S. Department of Defense
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
DE destruction efficiency
DRE destruction or removal efficiency
ECOS Environmental Council of the States
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
EGUs electrical generating units
EIA Energy Information Administration
EISA Energy Independence and Security
Act of 2007
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EU European Union
FTP Federal Test Procedure
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC–22 chlorodifluoromethane (or
CHClF2)
HCFCs hydrochlorofluorocarbons
HCl hydrogen chloride
HFC–23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate
Change
ISO International Organization for
Standardization
kg kilograms
LandGEM Landfill Gas Emissions Model
LCD liquid crystal display
LDCs local natural gas distribution
companies
LEDs light emitting diodes
LNG liquified natural gas
LPG liquified petroleum gas
MEMS microelectricomechanical system
mmBtu/hr millions British thermal units
per hour
MMTCO2e million metric tons carbon
dioxide equivalent
PO 00000
Frm 00005
Fmt 4701
Sfmt 4702
MSHA Mine Safety and Health
Administration
MSW municipal solid waste
MW megawatts
N2O nitrous oxide
NAAQS national ambient air quality
standard
NACAA National Association of Clean Air
Agencies
NAICS North American Industry
Classification System
NEI National Emissions Inventory
NESHAP national emission standards for
hazardous air pollutants
NF3 nitrogen trifluoride
NGLs natural gas liquids
NIOSH National Institute for Occupational
Safety and Health
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and
Advancement Act of 1995
O3 ozone
ODS ozone-depleting substance(s)
OMB Office of Management and Budget
ORIS Office of Regulatory Information
Systems
PFCs perfluorocarbons
PIN personal identification number
POTWs publicly owned treatment works
PSD Prevention of Significant Deterioration
PV photovoltaic
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
RFA Regulatory Flexibility Act
RFS Renewable Fuel Standard
RGGI Regional Greenhouse Gas Initiative
E:\FR\FM\10APP2.SGM
10APP2
16452
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
RIA regulatory impact analysis
SAE Society of Automotive Engineers
SAR IPCC Second Assessment Report
SBREFA Small Business Regulatory
Enforcement Fairness Act
SF6 sulfur hexafluoride
SFTP Supplemental Federal Test Procedure
SI international system of units
SIP State Implementation Plan
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TOC total organic carbon
TRI Toxic Release Inventory
TSCA Toxics Substances Control Act
TSD technical support document
U.S. United States
UIC underground injection control
UMRA Unfunded Mandates Reform Act of
1995
UNFCCC United Nations Framework
Convention on Climate Change
USDA U.S. Department of Agriculture
USGS U.S. Geological Survey
VMT vehicle miles traveled
VOC volatile organic compound(s)
WBCSD World Business Council for
Sustainable Development
WCI Western Climate Initiative
WRI World Resources Institute
XML eXtensible Markup Language
Table of Contents
I. Background
A. What Are GHGs?
B. What Is Climate Change?
C. Statutory Authority
D. Inventory of U.S. GHG Emissions and
Sinks
E. How does this proposal relate to U.S.
government and other climate change
efforts?
F. How does this proposal relate to EPA’s
Climate Change ANPR?
G. How was this proposed rule developed?
II. Summary of Existing Federal, State, and
Regional Emission Reporting Programs
A. Federal Voluntary GHG Programs
B. Federal Mandatory Reporting Programs
C. EPA Emissions Inventories
D. Regional and State Voluntary Programs
for GHG Emissions Reporting
E. State and Regional Mandatory Programs
for GHG Emissions Reporting and
Reduction
F. How the Proposed Mandatory GHG
Reporting Program is Different From the
Federal and State Programs EPA
Reviewed
III. Summary of the General Requirements of
the Proposed Rule
A. Who must report?
B. Schedule for Reporting
C. What do I have to report?
D. How do I submit the report?
E. What records must I retain?
IV. Rationale for the General Reporting,
Recordkeeping and Verification
Requirements That Apply to All Source
Categories
A. Rationale for Selection of GHGs To
Report
B. Rationale for Selection of Source
Categories To Report
C. Rationale for Selection of Thresholds
D. Rationale for Selection of Level of
Reporting
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
E. Rationale for Selecting the Reporting
Year
F. Rationale for Selecting the Frequency of
Reporting
G. Rationale for the Emissions Information
to Report
H. Rationale for Monitoring Requirements
I. Rationale for Selecting the
Recordkeeping Requirements
J. Rationale for Verification Requirements
K. Rationale for Selection of Duration of
the Program
V. Rationale for the Reporting,
Recordkeeping and Verification
Requirements for Specific Source
Categories
A. Overview of Reporting for Specific
Source Categories
B. Electricity Purchases
C. General Stationary Fuel Combustion
Sources
D. Electricity Generation
E. Adipic Acid Production
F. Aluminum Production
G. Ammonia Manufacturing
H. Cement Production
I. Electronics Manufacturing
J. Ethanol Production
K. Ferroalloy Production
L. Fluorinated GHG Production
M. Food Processing
N. Glass Production
O. HCFC–22 Production and HFC–23
Destruction
P. Hydrogen Production
Q. Iron and Steel Production
R. Lead Production
S. Lime Manufacturing
T. Magnesium Production
U. Miscellaneous Uses of Carbonates
V. Nitric Acid Production
W. Oil and Natural Gas Systems
X. Petrochemical Production
Y. Petroleum Refineries
Z. Phosphoric Acid Production
AA. Pulp and Paper Manufacturing
BB. Silicon Carbide Production
CC. Soda Ash Manufacturing
DD. Sulfur Hexafluoride (SF6) from
Electrical Equipment
EE. Titanium Dioxide Production
FF. Underground Coal Mines
GG. Zinc Production
HH. Landfills
II. Wastewater Treatment
JJ. Manure Management
KK. Suppliers of Coal
LL. Suppliers of Coal-Based Liquid Fuels
MM. Suppliers of Petroleum Products
NN. Suppliers of Natural Gas and Natural
Gas Liquids
OO. Suppliers of Industrial GHGs
PP. Suppliers of Carbon Dioxide (CO2)
QQ. Mobile Sources
VI. Collection, Management, and
Dissemination of GHG Emissions Data
A. Purpose
B. Data Collection
C. Data Management
D. Data Dissemination
VII. Compliance and Enforcement
A. Compliance Assistance
B. Role of the States
C. Enforcement
VIII. Economic Impacts of the Proposed Rule
A. How are compliance costs estimated?
PO 00000
Frm 00006
Fmt 4701
Sfmt 4702
B. What are the costs of this proposed rule?
C. What are the economic impacts of the
proposed rule?
D. What are the impacts of the proposed
rule on small entities?
E. What are the benefits of the proposed
rule for society?
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory
Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act
(UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
I. National Technology Transfer and
Advancement Act
J. Executive Order 12898: Federal Actions
To Address Environmental Justice in
Minority Populations and Low-Income
Populations
I. Background
The proposed rule would require
reporting of annual emissions of carbon
dioxide (CO2), methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs),
perfluorochemicals (PFCs), and other
fluorinated gases (e.g., nitrogen
trifluoride and hydrofluorinated ethers
(HFEs)). The proposed rule would apply
to certain downstream facilities that
emit GHGs (primarily large facilities
emitting 25,000 tpy of CO2 equivalent
GHG emissions or more) and to
upstream suppliers of fossil fuels and
industrial GHGs, as well as to
manufacturers of vehicles and engines.
Reporting would be at the facility level,
except certain suppliers and vehicle and
engine manufacturers would report at
the corporate level.
This preamble is broken into several
large sections, as detailed above in the
Table of Contents. Throughout the
preamble we explicitly request
comment on a variety of issues. The
paragraph below describes the layout of
the preamble and provides a brief
summary of each section. We also
highlight particular issues on which, as
indicated later in the preamble, we
would specifically be interested in
receiving comments.
The first section of this preamble
contains the basic background
information about greenhouse gases and
climate change. It also describes the
origin of this proposal, our legal
authority and how this proposal relates
to other efforts to address emissions of
greenhouse gases. In this section we
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
would be particularly interested in
receiving comment on the relationship
between this proposal and other
government efforts.
The second section of this preamble
describes existing Federal, State,
Regional mandatory and voluntary GHG
reporting programs and how they are
similar and different to this proposal.
Again, similar to the previous section,
we would like comments on the
interrelationship of this proposal and
existing GHG reporting programs.
The third section of this preamble
provides an overview of the proposal
itself, while the fourth section provides
the rationale for each decision the
Agency made in developing the
proposal, including key design elements
such as: (i) Source categories included,
(ii) the level of reporting, (iii)
applicability thresholds, (iv) reporting
and monitoring methods, (v)
verification, (vi) frequency and (vii)
duration of reporting. Furthermore, in
this section, EPA explains the
distinction between upstream and
downstream reporters, describes why it
is necessary to collect data at multiple
points, and provides information on
how different data would be useful to
inform different policies. As stated in
the fourth section, we solicit comment
on each design element of the proposal
generally.
The fifth section of this preamble
looks at the same key design elements
for each of the source categories covered
by the proposal. Thus, for example,
there is a specific discussion regarding
appropriate applicability thresholds,
reporting and monitoring methodologies
and reporting and recordkeeping
requirements for each source category.
Each source category describes the
proposed options for each design
element, as well as the other options
considered. In addition to the general
solicitation for comment on each design
element generally and for each source
category, throughout the fifth section
there are specific issues highlighted on
which we solicit comment. Please refer
to the specific source category of
interest for more details.
The sixth section of this preamble
explains how EPA would collect,
manage and disseminate the data, while
the seventh section describes the
approach to compliance and
enforcement. In both sections the role of
the States is discussed, as are requests
for comment on that role.
Finally, the eighth section provides
the summary of the impacts and costs
from the Regulatory Impact Analysis
and the last section walks through the
various statutory and executive order
requirements applicable to rulemakings.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
A. What Are GHGs?
The proposed rule would cover the
major GHGs that are directly emitted by
human activities. These include CO2,
CH4, N2O, HFCs, PFCs, SF6, and other
specified fluorinated compounds (e.g.,
HFEs) used in boutique applications
such as electronics and anesthetics.
These gases influence the climate
system by trapping in the atmosphere
heat that would otherwise escape to
space. The GHGs vary in their capacity
to trap heat. The GHGs also vary in
terms of how long they remain in the
atmosphere after being emitted, with the
shortest-lived GHG remaining in the
atmosphere for roughly a decade and
the longest-lived GHG remaining for up
to 50,000 years. Because of these long
atmospheric lifetimes, all of the major
GHGs become well mixed throughout
the global atmosphere regardless of
emission origin.
Global atmospheric CO2 concentration
increased about 35 percent from the preindustrial era to 2005. The global
atmospheric concentration of CH4 has
increased by 148 percent from preindustrial levels, and the N2O
concentration has increased 18 percent.
The observed increase in concentration
of these gases can be attributed
primarily to human activities. The
atmospheric concentration of industrial
fluorinated gases—HFCs, PFCs, SF6—
and other fluorinated compounds are
relatively low but are increasing rapidly;
these gases are entirely anthropogenic in
origin.
Due to sheer quantity of emissions,
CO2 is the largest contributor to GHG
concentrations followed by CH4.
Combustion of fossil fuels (e.g., coal, oil,
gas) is the largest source of CO2
emissions in the U.S. The other GHGs
are emitted from a variety of activities.
These emissions are compiled by EPA
in the Inventory of U.S. Greenhouse Gas
Emissions and Sinks (Inventory) and
reported to the UNFCCC 1 on an annual
basis.2 A more detailed discussion of
1 For more information about the UNFCCC, please
refer to: https://www.unfccc.int. See Articles 4 and
12 of the UNFCCC treaty. Parties to the Convention,
by ratifying, ‘‘shall develop, periodically update,
publish and make available * * * national
inventories of anthropogenic emissions by sources
and removals by sinks of all greenhouse gases not
controlled by the Montreal Protocol, using
comparable methodologies * * *’’.
2 The U.S. submits the Inventory of U.S.
Greenhouse Gas Emissions and Sinks to the
Secretariat of the UNFCCC as an annual reporting
requirement. The UNFCCC treaty, ratified by the
U.S. in 1992, sets an overall framework for
intergovernmental efforts to tackle the challenge
posed by climate change. The U.S. has submitted
the GHG inventory to the United Nations every year
since 1993. The annual Inventory of U.S.
Greenhouse Gas Emissions and Sinks is consistent
with national inventory data submitted by other
PO 00000
Frm 00007
Fmt 4701
Sfmt 4702
16453
the Inventory is provided in Section I.D
below.
Because GHGs have different heat
trapping capacities, they are not directly
comparable without translating them
into common units. The GWP, a metric
that incorporates both the heat-trapping
ability and atmospheric lifetime of each
GHG, can be used to develop
comparable numbers by adjusting all
GHGs relative to the GWP of CO2. When
quantities of the different GHGs are
multiplied by their GWPs, the different
GHGs can be compared on a CO2e basis.
The GWP of CO2 is 1.0, and the GWP
of other GHGs are expressed relative to
CO2. For example, CH4 has a GWP of 21,
meaning each metric ton of CH4
emissions would have 21 times as much
impact on global warming (over a 100year time horizon) as a metric ton of
CO2 emissions. The GWPs of the other
gases are listed in the proposed rule,
and range from the hundreds up to
23,900 for SF6.3 Aggregating all GHGs
on a CO2e basis at the source level
allows a comparison of the total
emissions of all the gases from one
source with emissions from other
sources.
For additional information about
GHGs, climate change, climate science,
etc. please see EPA’s climate change
Web site found at https://www.epa.gov/
climatechange/.
B. What Is Climate Change?
Climate change refers to any
significant changes in measures of
climate (such as temperature,
precipitation, or wind) lasting for an
extended period. Historically, natural
factors such as volcanic eruptions and
changes in the amount of energy
released from the sun have affected the
earth’s climate. Beginning in the late
18th century, human activities
associated with the industrial revolution
UNFCCC Parties, and uses internationally accepted
methods for its emission estimates.
3 EPA has chosen to use GWPs published in the
IPCC SAR (furthermore referenced as ‘‘SAR GWP
values’’). The use of the SAR GWP values allows
comparability of data collected in this proposed
rule to the national GHG inventory that EPA
compiles annually to meet U.S. commitments to the
UNFCCC. To comply with international reporting
standards under the UNFCCC, official emission
estimates are to be reported by the U.S. and other
countries using SAR GWP values. The UNFCCC
reporting guidelines for national inventories were
updated in 2002 but continue to require the use of
GWPs from the SAR. The parties to the UNFCCC
have also agreed to use GWPs based upon a 100year time horizon although other time horizon
values are available. For those fluorinated
compounds included in this proposal that not listed
in the SAR, EPA is using the most recent available
GWPs, either the IPCC Third Assessment Report or
Fourth Assessment Report. For more specific
information about the GWP of specific GHGs, please
see Table A–1 in the proposed 40 CFR part 98,
subpart A.
E:\FR\FM\10APP2.SGM
10APP2
16454
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
have also changed the composition of
the earth’s atmosphere and very likely
are influencing the earth’s climate.4 The
heating effect caused by the buildup of
GHGs in our atmosphere enhances the
Earth’s natural greenhouse effect and
adds to global warming. As global
temperatures increase other elements of
the climate system, such as
precipitation, snow and ice cover, sea
levels, and weather events, change. The
term ‘‘climate change,’’ which
encompasses these broader effects, is
often used instead of ‘‘global warming.’’
According to the IPCC, warming of
the climate system is ‘‘unequivocal,’’ as
is now evident from observations of
increases in global average air and ocean
temperatures, widespread melting of
snow and ice, and rising global average
sea level. Global mean surface
temperatures have risen by 0.74 °C (1.3
°F) over the last 100 years. Global mean
surface temperature was higher during
the last few decades of the 20th century
than during any comparable period
during the preceding four centuries.
U.S. temperatures also warmed during
the 20th and into the 21st century;
temperatures are now approximately
0.56 °C (1.0 °F) warmer than at the start
of the 20th century, with an increased
rate of warming over the past 30 years.
Most of the observed increase in global
average temperatures since the mid-20th
century is very likely due to the
observed increase in anthropogenic
GHG concentrations.
According to different scenarios
assessed by the IPCC, average global
temperature by end of this century is
projected to increase by 1.8 to 4.0 °C
(3.2 to 7.2 °F) compared to the average
temperature in 1990. The uncertainty
range of this estimate is 1.1 to 6.4 °C (2.0
to 11.5 °F). Future projections show
that, for most scenarios assuming no
additional GHG emission reduction
policies, atmospheric concentrations of
GHGs are expected to continue climbing
for most if not all of the remainder of
this century, with associated increases
in average temperature. Overall risk to
human health, society and the
environment increases with increases in
both the rate and magnitude of climate
change.
For additional information about
GHGs, climate change, climate science,
etc. please see EPA’s climate change
Web site found at https://www.epa.gov/
climatechange/.
4 IPCCC: Climate Change 2007: The Physical
Science Basis, February 2, 2007 (https://
www.ipcc.ch/).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
C. Statutory Authority
On December 26, 2007, President
Bush signed the FY2008 Consolidated
Appropriations Act which authorized
funding for EPA to ‘‘develop and
publish a draft rule not later than 9
months after the date of enactment of
this Act, and a final rule not later than
18 months after the date of enactment of
this Act, to require mandatory reporting
of GHG emissions above appropriate
thresholds in all sectors of the economy
of the United States.’’ Consolidated
Appropriations Act, 2008, Public Law
110–161, 121 Stat 1844, 2128 (2008).
The accompanying joint explanatory
statement directed EPA to ‘‘use its
existing authority under the Clean Air
Act’’ to develop a mandatory GHG
reporting rule. ‘‘The Agency is further
directed to include in its rule reporting
of emissions resulting from upstream
production and downstream sources, to
the extent that the Administrator deems
it appropriate.’’ EPA has interpreted that
language to confirm that it may be
appropriate for the Agency to exercise
its CAA authority to require reporting of
the quantity of fuel or chemical that is
produced or imported from upstream
sources such as fuel suppliers, as well
as reporting of emissions from facilities
(downstream sources) that directly emit
GHGs from their processes or from fuel
combustion, as appropriate. The joint
explanatory statement further states that
‘‘[t]he Administrator shall determine
appropriate thresholds of emissions
above which reporting is required, and
how frequently reports shall be
submitted to EPA. The Administrator
shall have discretion to use existing
reporting requirements for electric
generating units’’ under section 821 of
the 1990 CAA Amendments.
EPA is proposing this rule under its
existing CAA authority. EPA also
proposes that the rule require the
reporting of the GHG emissions
resulting from the quantity of fossil fuel
or industrial gas that is produced or
imported from upstream sources such as
fuel suppliers, as well as reporting of
GHG emissions from facilities
(downstream sources) that directly emit
GHGs from their processes or from fuel
combustion, as appropriate. This
proposed rule would also establish
appropriate thresholds and frequency
for reporting.
Section 114(a)(1) of the CAA
authorizes the Administrator to, inter
alia, require certain persons (see below)
on a one-time, periodic or continuous
basis to keep records, make reports,
undertake monitoring, sample
emissions, or provide such other
information as the Administrator may
PO 00000
Frm 00008
Fmt 4701
Sfmt 4702
reasonably require. This information
may be required of any person who (i)
owns or operates an emission source,
(ii) manufactures control or process
equipment, (iii) the Administrator
believes may have information
necessary for the purposes set forth in
this section, or (iv) is subject to any
requirement of the Act (except for
manufacturers subject to certain title II
requirements). The information may be
required for the purposes of developing
an implementation plan, an emission
standard under sections 111, 112 or 129,
determining if any person is in violation
of any standard or requirement of an
implementation plan or emissions
standard, or ‘‘carrying out any
provision’’ of the Act (except for a
provision of title II with respect to
manufacturers of new motor vehicles or
new motor vehicle engines).5 Section
208 of the CAA provides EPA with
similar broad authority regarding the
manufacturers of new motor vehicles or
new motor vehicle engines, and other
persons subject to the requirements of
parts A and C of title II.
The scope of the persons potentially
subject to a section 114(a)(1)
information request (e.g., a person ‘‘who
the Administrator believes may have
information necessary for the purposes
set forth in’’ section 114(a)) and the
reach of the phrase ‘‘carrying out any
provision’’ of the Act are quite broad.
EPA’s authority to request information
reaches to a source not subject to the
CAA, and may be used for purposes
relevant to any provision of the Act.
Thus, for example, utilizing sections
114 and 208, EPA could gather
information relevant to carrying out
provisions involving research (e.g.,
section 103(g)); evaluating and setting
standards (e.g., section 111); and
endangerment determinations contained
in specific provisions of the Act (e.g.,
202); as well as other programs.
Given the broad scope of sections 114
and 208 of the CAA, it is appropriate for
EPA to gather the information required
by this rule because such information is
relevant to EPA’s carrying out a wide
variety of CAA provisions. For example,
emissions from direct emitters should
inform decisions about whether and
how to use section 111 to establish
NSPS for various source categories
emitting GHGs, including whether there
are any additional categories of sources
that should be listed under section
111(b). Similarly, the information
required of manufacturers of mobile
5 Although there are exclusions in section
114(a)(1) regarding certain title II requirements
applicable to manufacturers of new motor vehicle
and motor vehicle engines, section 208 authorizes
the gathering of information related to those areas.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
sources should support decisions
regarding treatment of those sources
under sections 202, 213 or 231 of the
CAA. In addition, the information from
fuel suppliers would be relevant in
analyzing whether to proceed, and
particular options for how to proceed,
under section 211(c) regarding fuels, or
to inform action concerning
downstream sources under a variety of
Title I or Title II provisions. For
example, the geographic distribution,
production volumes and characteristics
of various fuel types and subtypes may
also prove useful is setting NSPS or Best
Available Control Technology limits for
some combustion sources.
Transportation distances from fuel
sources to end users may be useful in
evaluating cost effectiveness of various
fuel choices, increases in transportation
emissions that may be associated with
various fuel choices, as well as the
overall impact on energy usage and
availability. The data overall also would
inform EPA’s implementation of section
103(g) of the CAA regarding
improvements in nonregulatory
strategies and technologies for
preventing or reducing air pollutants.
This section, which specifically
mentions CO2, highlights energy
conservation, end-use efficiency and
fuel-switching as possible strategies for
consideration and the type of
information collected under this rule
would be relevant. The above
discussion is not a comprehensive
listing of all the possible ways the
information collected under this rule
could assist EPA in carrying out any
provision of the CAA. Rather it
illustrates how the information request
fits within the parameters of EPA’s CAA
authority.
D. Inventory of U.S. GHG Emissions and
Sinks
The Inventory of U.S. Greenhouse Gas
Emissions and Sinks (Inventory),
prepared by EPA’s Office of
Atmospheric Programs in coordination
with the Office of Transportation and
Air Quality, is an impartial, policyneutral report that tracks annual GHG
emissions. The annual report presents
historical U.S. emissions of CO2, CH4,
N2O, HFCs, PFCs, and SF6.
The U.S. submits the Inventory to the
Secretariat of the UNFCCC as an annual
reporting requirement. The UNFCCC
treaty, ratified by the U.S. in 1992, sets
an overall framework for
intergovernmental efforts to tackle the
challenge posed by climate change. The
U.S. has submitted the GHG inventory
to the United Nations every year since
1993. The annual Inventory is
consistent with national inventory data
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
submitted by other UNFCCC Parties,
and uses internationally accepted
methods for its emission estimates.
In preparing the annual Inventory,
EPA leads an interagency team that
includes DOE, USDA, DOT, DOD, the
State Department, and others. EPA
collaborates with hundreds of experts
representing more than a dozen Federal
agencies, academic institutions,
industry associations, consultants, and
environmental organizations. The
Inventory is peer-reviewed annually by
domestic experts, undergoes a 30-day
public comment period, and is also
peer-reviewed annually by UNFCCC
review teams.
The most recent GHG inventory
submitted to the UNFCCC, the Inventory
of U.S. Greenhouse Gas Emissions and
Sinks: 1990–2006 (April 2008),
estimated that total U.S. GHG emissions
were 7,054.2 million metric tons of
CO2e in 2006. Overall emissions have
grown by 15 percent from 1990 to 2006.
CO2 emissions have increased by 18
percent since 1990. CH4 emissions have
decreased by 8 percent since 1990,
while N2O emissions have decreased by
4 percent since 1990. Emissions of
HFCs, PFCs, and SF6 have increased by
64 percent since 1990. The combustion
of fossil fuels (i.e., petroleum, coal, and
natural gas) was the largest source of
GHG emissions in the U.S., and
accounted for approximately 80 percent
of total CO2e emissions.
The Inventory is a comprehensive
top-down national assessment of
national GHG emissions, and it uses
top-down national energy data and
other national statistics (e.g., on
agriculture). To achieve the goal of
comprehensive national emissions
coverage for reporting under the
UNFCCC, most GHG emissions in the
report are calculated via activity data
from national-level databases, statistics,
and surveys. The use of the aggregated
national data means that the national
emissions estimates are not brokendown at the geographic or facility level.
In contrast, this reporting rule focuses
on bottom-up data and individual
sources above appropriate thresholds.
Although it would provide more
specific data, it would not provide full
coverage of total annual U.S. GHG
emissions, as is required in the
development of the Inventory in
reporting to the UNFCCC.
The mandatory GHG reporting rule
would help to improve the development
of future national inventories for
particular source categories or sectors by
advancing the understanding of
emission processes and monitoring
methodologies. Facility, unit, and
process level GHG emissions data for
PO 00000
Frm 00009
Fmt 4701
Sfmt 4702
16455
industrial sources would improve the
accuracy of the Inventory by confirming
the national statistics and emission
estimation methodologies used to
develop the top-down inventory. The
results can indicate shortcomings in the
national statistics and identify where
adjustments may be needed.
Therefore, although the data collected
under this rule would not replace the
system in place to produce the
comprehensive annual national
Inventory, it can serve as a useful tool
to better improve the accuracy of future
national-level inventories.
At the same time, EPA solicits
comment on whether the submission of
the Inventory to the UNFCCC could be
utilized to satisfy the requirements of
the rule promulgated by EPA pursuant
to the FY2008 Consolidated
Appropriations Act.
For more information about the
Inventory, please refer to the following
Web site: https://www.epa.gov/
climatechange/emissions/
usinventoryreport.html.
E. How does this proposal relate to U.S.
government and other climate change
efforts?
The proposed mandatory GHG
reporting program would provide EPA,
other government agencies, and outside
stakeholders with economy-wide data
on facility-level (and in some cases
corporate-level) GHG emissions.
Accurate and timely information on
GHG emissions is essential for
informing some future climate change
policy decisions. Although additional
data collection (e.g., for other source
categories such as indirect emissions or
offsets) may be required as the
development of climate policies
evolves, the data collected in this rule
would provide useful information for a
variety of policies. For example, through
data collected under this rule, EPA
would gain a better understanding of the
relative emissions of specific industries,
and the distribution of emissions from
individual facilities within those
industries. The facility-specific data
would also improve our understanding
of the factors that influence GHG
emission rates and actions that facilities
are already taking to reduce emissions.
In addition, the data collected on some
source categories such as landfills and
manure management, which can be
covered by the CAA, could also
potentially help inform offset program
design by providing fundamental data
on current baseline emissions for these
categories.
Through this rulemaking, EPA would
be able to track the trend of emissions
from industries and facilities within
E:\FR\FM\10APP2.SGM
10APP2
16456
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
industries over time, particularly in
response to policies and potential
regulations. The data collected by this
rule would also improve the U.S.
government’s ability to formulate a set
of climate change policy options and to
assess which industries would be
affected, and how these industries
would be affected by the options.
Finally, EPA’s experience with other
reporting programs is that such
programs raise awareness of emissions
among reporters and other stakeholders,
and thus contribute to efforts to identify
reduction opportunities and carry them
out.
The goal is to have this GHG reporting
program supplement and complement,
rather than duplicate, U.S. government
and other GHG programs (e.g., State and
Regional based programs). As discussed
in Section I.D of this preamble, EPA
anticipates that facility-level GHG
emissions data would lead to
improvements in the quality of the
Inventory.
As discussed in Section II of this
preamble, a number of EPA voluntary
partnership programs include a GHG
emissions and/or reductions reporting
component (e.g., Climate Leaders, the
Natural Gas STAR program). Because
this mandatory reporting program
would have much broader coverage than
the voluntary programs, it would help
EPA learn more about emissions from
facilities not currently included in these
programs and broaden coverage of these
industries.
Also discussed in Section II of this
preamble, DOE EIA implements a
voluntary GHG registry under section
1605(b) of the Energy Policy Act. Under
EIA’s ‘‘1605(b) program,’’ reporters can
choose to prepare an entity-wide GHG
inventory and identify specific GHG
reductions made by the entity.6 EPA’s
proposed mandatory GHG program
would have a much broader set of
reporters included, primarily at the
facility 7 rather than entity-level, but
this proposed rule is not designed with
6 Under the 1605(b) program an ‘‘entity’’ is
defined as ‘‘the whole or part of any business,
institution, organization or household that is
recognized as an entity under any U.S. Federal,
State or local law that applies to it; is located, at
least in part, in the U.S.; and whose operations
affect U.S. greenhouse gas emissions.’’ (https://
www.pi.energy.gov/enhancingGHGregistry/)
7 For the purposes of this proposal, facility means
any physical property, plant, building, structure,
source, or stationary equipment located on one or
more contiguous or adjacent properties in actual
physical contact or separated solely by a public
roadway or other public right-of-way and under
common ownership or common control, that emits
or may emit any greenhouse gas. Operators of
military installations may classify such installations
as more than a single facility based on distinct and
independent functional groupings within
contiguous military properties.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
the specific intent of reporting of
emission reductions, as is the 1605(b)
program.
Again, in Section II, existing State and
Regional GHG reporting and reduction
programs are summarized. Many of
those programs may be broader in scope
and more aggressive in implementation.
States collecting that additional
information may have determined that
types of data not collected by this
proposal are necessary to implement a
variety of climate efforts. While EPA’s
proposal was specifically developed in
response to the Appropriations Act, we
also acknowledge, similar to the States,
there may be a need to collect additional
data from sources subject to this rule as
well as other sources depending on the
types of policies the Agency is
developing and implementing (e.g.,
indirect emissions and offsets).
Addressing climate change may require
a suite of policies and programs and this
proposal for a mandatory reporting
program is just one effort to collect
information necessary to inform those
policies. There may well be subsequent
efforts depending on future policy
direction and/or requests from Congress.
F. How does this proposal relate to
EPA’s Climate Change ANPR?
On July 30, 2008, EPA published an
ANPR on ‘‘Regulating Greenhouse Gas
Emissions under the Clean Air Act’’ (73
FR 44354). The ANPR presented
information relevant to, and solicited
public comment on, issues regarding the
potential regulation of GHGs under the
CAA, including EPA’s response to the
U.S. Supreme Court’s decision in
Massachusetts v. EPA. 127 S.Ct. 1438
(2007). EPA’s proposing the mandatory
GHG reporting rule does not indicate
that EPA has made any final decisions
related to the questions identified in the
ANPR. Any information collected under
the mandatory GHG reporting program
would assist EPA and others in
developing future climate policy.8
8 At this time, a regulation requiring the reporting
of GHG emissions and emissions-related data under
CAA sections 114 and 208 does not trigger the need
for EPA to develop or revise regulations under any
other section of the CAA, including the PSD
program. See memorandum entitled ‘‘EPA’s
Interpretation of Regulations that Determine
Pollutants Covered By Federal Prevention of
Significant Deterioration (PSD) Permit Program’’
(Dec. 18, 2008). EPA is reconsidering this
memorandum and will be seeking public comment
on the issues raised in it. That proceeding, not this
rulemaking, would be the appropriate venue for
submitting comments on the issue of whether
monitoring regulations under the CAA should
trigger the PSD program.
PO 00000
Frm 00010
Fmt 4701
Sfmt 4702
G. How was this proposed rule
developed?
In response to the FY2008
Consolidated Appropriations
Amendment, EPA has developed this
proposed rulemaking. The components
of this development are explained in the
following subsections.
1. Identifying the Goals of the GHG
Reporting System
The mandatory reporting program
would provide comprehensive and
accurate data which would inform
future climate change policies. Potential
future climate policies include research
and development initiatives, economic
incentives, new or expanded voluntary
programs, adaptation strategies,
emission standards, a carbon tax, or a
cap-and-trade program. Because we do
not know at this time the specific
policies that may be adopted, the data
reported through the mandatory
reporting system should be of sufficient
quality to support a range of
approaches. Also, consistent with the
Appropriations Act, the reporting rule
proposes to cover a broad range of
sectors of the economy.
To these ends, we identified the
following goals of the mandatory
reporting system:
• Obtain data that is of sufficient
quality that it can be used to support a
range of future climate change policies
and regulations.
• Balance the rule coverage to
maximize the amount of emissions
reported while excluding small emitters.
• Create reporting requirements that
are consistent with existing GHG
reporting programs by using existing
GHG emission estimation and reporting
methodologies to reduce reporting
burden, where feasible.
2. Developing the Proposed Rule
In order to ensure a comprehensive
consideration of GHG emissions, EPA
organized the development of the
proposal around seven categories of
processes that emit GHGs: Downstream
sources of emissions: (1) Fossil Fuel
Combustion: Stationary, (2) Fossil Fuel
Combustion: Mobile, (3) Industrial
Processes, (4) Fossil Fuel Fugitive 9
Emissions, (5) Biological Processes and
Upstream sources of emissions: (6) Fuel
9 The term ‘‘fugitive’’ often refers to emissions
that cannot reasonably pass through a stack,
chimney, vent or other functionally equivalent
opening. This definition of fugitives is used
throughout the preamble, except in Section W Oil
and Natural Gas Systems, which uses a slightly
modified definition based on the Intergovernmental
Panel on Climate Change.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Suppliers, and (7) Industrial GHG
Suppliers.
For each category, EPA evaluated the
requirements of existing GHG reporting
programs, obtained input from
stakeholders, analyzed reporting
options, and developed the general
reporting requirements and specific
requirements for each of the GHG
emitting processes.
3. Evaluation of Existing GHG Reporting
Programs
A number of State and regional GHG
reporting systems currently are in place
or under development. EPA’s goal is to
develop a reporting rule that, to the
extent possible and appropriate, would
rely on similar protocols and formats of
the existing programs and, therefore,
reduce the burden of reporting for all
parties involved. Therefore, each of the
work groups performed a
comprehensive review of existing
voluntary and mandatory GHG reporting
programs, as well as guidance
documents for quantifying GHG
emissions from specific sources. These
GHG reporting programs and guidance
documents included the following:
• International programs, including
the IPCC, the EU Emissions Trading
System, and the Environment Canada
reporting rule;
• U.S. national programs, such as the
U.S. GHG inventory, the ARP, voluntary
GHG partnership programs (e.g., Natural
Gas STAR), and the DOE 1605(b)
voluntary GHG registry;
• State and regional GHG reporting
programs, such as TCR, RGGI, and
programs in California, New Mexico,
and New Jersey;
• Reporting protocols developed by
nongovernmental organizations, such as
WRI/WBCSD; and
• Programs from industrial trade
organizations, such as the American
Petroleum Institute’s Compendium of
GHG Estimation Methodologies for the
Oil and Gas Industry and the Cement
Sustainability Initiative’s CO2
Accounting and Reporting Standard for
the Cement Industry, developed by
WBCSD.
In reviewing these programs, we
analyzed the sectors covered, thresholds
for reporting, approach to indirect
emissions reporting, the monitoring or
emission estimating methods used, the
measures to assure the quality of the
reported data, the point of monitoring,
data input needs, and information
required to be reported and/or retained.
We analyzed these provisions for
suitability to a mandatory, Federal GHG
reporting program, and compiled the
information. The full review of existing
GHG reporting programs and guidance
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
may be found in the docket at EPA–HQ–
OAR–2008–0508–054. Section II of this
preamble summarizes the fundamental
elements of these programs.
4. Stakeholder Outreach To Identify
Reporting Issues
Early in the development process, we
conducted a proactive communications
outreach program to inform the public
about the rule development effort. We
solicited input and maintained an open
door policy for those interested in
discussing the rulemaking. Since
January 2008, EPA staff held more than
100 meetings with over 250
stakeholders. These stakeholders
included:
• Trade associations and firms in
potentially affected industries/sectors;
• State, local, and Tribal
environmental control agencies and
regional air quality planning
organizations;
• State and regional organizations
already involved in GHG emissions
reporting, such as TCR, CARB, and WCI;
• Environmental groups and other
nongovernmental organizations.
• We also met with DOE and USDA
which have programs relevant to GHG
emissions.
During the meetings, we shared
information about the statutory
requirements and timetable for
developing a rule. Stakeholders were
encouraged to provide input on key
issues. Examples of topics discussed
were, existing GHG monitoring and
reporting programs and lessons learned,
thresholds for reporting, schedule for
reporting, scope of reporting, handling
of confidential data, data verification,
and the role of States in administering
the program. As needed, the technical
work groups followed up with these
stakeholder groups on a variety of
methodological, technical, and policy
issues. EPA staff also provided
information to Tribes through
conference calls with different Indian
working groups and organizations at
EPA and through individual calls with
Tribal board members of TCR.
For a full list of organizations EPA
met with during development of this
proposal, see the memo found at EPA–
HQ–OAR–2008–0508–055.
II. Summary of Existing Federal, State,
and Regional Emission Reporting
Programs
A number of voluntary and
mandatory GHG programs already exist
or are being developed at the State,
Regional, and Federal levels. These
programs have different scopes and
purposes. Many focus on GHG emission
reduction, whereas others are purely
PO 00000
Frm 00011
Fmt 4701
Sfmt 4702
16457
reporting programs. In addition to the
GHG programs, other Federal emission
reporting programs and emission
inventories are relevant to the proposed
GHG reporting rule. Several of these
programs are summarized in this
section.
In developing the proposed rule, we
carefully reviewed the existing reporting
programs, particularly with respect to
emissions sources covered, thresholds,
monitoring methods, frequency of
reporting and verification. States may
have, or intend to develop, reporting
programs that are broader in scope or
are more aggressive in implementation
because those programs are either
components of established reduction
programs (e.g., cap and trade) or being
used to design and inform specific
complementary measures (e.g., energy
efficiency). EPA has benefitted from the
leadership the States have shown in
developing these programs and their
experiences. Discussions with States
that have already implemented
programs have been especially
instructive. Where possible, we built
upon concepts in existing Federal and
State programs in developing the
mandatory GHG reporting rule.
A. Federal Voluntary GHG Programs
EPA and other Federal agencies
operate a number of voluntary GHG
reporting and reduction programs that
EPA reviewed when developing this
proposal, including Climate Leaders,
several Non-CO2 voluntary programs,
the CHP partnership, the SmartWay
Transport Partnership program, the
National Environmental Performance
Track Partnership, and the DOE 1605(b)
voluntary GHG registry. There are
several other Federal voluntary
programs to encourage emissions
reductions, clean energy, or energy
efficiency, and this summary does not
cover them all. This summary focuses
on programs that include voluntary
GHG emission inventories or reporting
of GHG emission reduction activities for
sectors covered by this proposed
rulemaking.
Climate Leaders.10 Climate Leaders is
an EPA partnership program that works
with companies to develop GHG
reduction strategies. Over 250 industry
partners in a wide range of sectors have
joined. Partner companies complete a
corporate-wide inventory of GHG
emissions and develop an inventory
management plan using Climate Leaders
protocols. Each company sets GHG
reductions goals and submits to EPA an
10 For more information about the Climate
Leaders program please see: https://www.epa.gov/
climateleaders/.
E:\FR\FM\10APP2.SGM
10APP2
16458
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
annual GHG emissions inventory
documenting their progress. The annual
reporting form provides corporate-wide
emissions by type of emissions source.
Non-CO2 Voluntary Partnership
Programs.11 Since the 1990s, EPA has
operated a number of non-CO2
voluntary partnership programs aimed
at reducing emissions from GHGs such
as CH4, SF66, and PFCs. There are four
sector-specific voluntary CH4 reduction
programs: Natural Gas STAR, Landfill
Methane Outreach Program, Coalbed
Methane Outreach Program and
AgSTAR. In addition, there are sectorspecific voluntary emission reduction
partnerships for high GWP gases. The
Natural Gas STAR partnership
encourages companies across the
natural gas and oil industries to adopt
practices that reduce CH4 emissions.
The Landfill Methane Outreach Program
and Coalbed Methane Outreach Program
encourage voluntary capture and use of
landfill and coal mine CH4, respectively,
to generate electricity or other useful
energy. These partnerships focus on
achieving CH4 reductions. Industry
partners voluntarily provide technical
information on projects they undertake
to reduce CH4 emissions on an annual
basis, but they do not submit CH4
emissions inventories. AgSTAR
encourages beneficial use of agricultural
CH4 but does not have partner reporting
requirements.
There are two sector specific
partnerships to reduce SF6 emissions:
The SF6 Emission Reduction
Partnership for Electric Power Systems,
with over 80 participating utilities, and
an SF6 Emission Reduction Partnership
for the Magnesium Industry. Partners in
these programs implement practices to
reduce SF6 emissions and prepare
corporate-wide annual inventories of
SF6 emissions using protocols and
reporting tools developed by EPA. There
are also two partnerships focused on
PFCs. The Voluntary Aluminum
Industrial Partnership promotes
technically feasible and cost effective
actions to reduce PFC emissions.
Industry partners track and report PFC
emissions reductions. Similarly, the
Semiconductor Industry Association
and EPA formed a partnership to reduce
PFC emissions. A third party compiles
data from participating semiconductor
companies and submits an aggregate
(not company-specific) annual PFC
emissions report.
11 For more information about the Non-CO
2
Voluntary Partnership Programs please see: https://
www.epa.gov/nonco2/voluntaryprograms.html.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
CHP Partnership.12 The CHP
Partnership is an EPA partnership that
cuts across sectors. It encourages use of
CHP technologies to generate electricity
and heat from the same fuel source,
thereby increasing energy efficiency and
reducing GHG emissions from fuel
combustion. Corporate and institutional
partners provide data on existing and
new CHP projects, but do not submit
emissions inventories.
SmartWay Transport Partnership.13
The SmartWay Transport Partnership
program is a voluntary partnership
between freight industry stakeholders
and EPA to promote fuel efficiency
improvements and GHG emissions
reductions. Over 900 companies have
joined including freight carriers
(railroads and trucking fleets) and
shipping companies. Carrier and
shipping companies commit to
measuring and improving the efficiency
of their freight operations using EPAdeveloped tools that quantify the
benefits of a number of fuel-saving
strategies. Companies report progress
annually. The GHG data that carrier
companies report to EPA is discussed
further in Section V.QQ.4b of this
preamble.
National Environmental Performance
Track Partnership.14 The Performance
Track Partnership is a voluntary
partnership that recognizes and rewards
private and public facilities that
demonstrate strong environmental
performance beyond current
requirements. Performance Track is
designed to augment the existing
regulatory system by creating incentives
for facilities to achieve environmental
results beyond those required by law.
To qualify, applicants must have
implemented an independentlyassessed environmental management
system, have a record of sustained
compliance with environmental laws
and regulations, commit to achieving
measurable environmental results that
go beyond compliance, and provide
information to the local community on
their environmental activities. Members
are subject to the same legal
requirements as other regulated
facilities. In some cases, EPA and states
have reduced routine reporting or given
some flexibility to program members in
how they meet regulatory requirements.
This approach is recognized by more
than 20 states that have adopted similar
performance-based leadership programs.
12 For more information about the CHP
Partnership please see: https://www.epa.gov/chp/.
13 For more information about SmartWay please
see: https://www.epa.gov/smartway/.
14 For more information about Performance Track
please see: https://www.epa.gov/perftrac/index.htm.
PO 00000
Frm 00012
Fmt 4701
Sfmt 4702
1605(b) Voluntary Registry.15 The
DOE EIA established a voluntary GHG
registry under section 1605(b) of the
Energy Policy Act of 1992. The program
was recently enhanced and a final rule
containing general reporting guidelines
was published on April 21, 2006 (71 FR
20784). The rule is contained in 10 CFR
part 300. Unlike EPA’s proposal which
requires of reporting of GHG emissions
from facilities over a specific threshold,
the DOE 1605(b) registry allows anyone
(e.g., a public entity, private company,
or an individual) to report on their
emissions and their emission reduction
projects to the registry. Large emitters
(e.g., anyone that emits over 10,000 tons
of CO2e per year) that wish to register
emissions reductions must submit
annual company-wide GHG emissions
inventories following technical
guidelines published by DOE and must
calculate and report net GHG emissions
reductions. The program offers a range
of reporting methodologies from
stringent direct measurement to
simplified calculations using default
factors and allows the reporters to report
using the methodological option they
choose. In addition, as mentioned
above, unlike EPA’s proposal,
sequestration and offset projects can
also be reported under the 1605(b)
program. There is additional flexibility
offered to small sources who can choose
to limit annual inventories and emission
reduction reports to just a single type of
activity rather than reporting companywide GHG emissions, but must still
follow the technical guidelines.
Reported data are made available on the
Web in a public use database.
Summary. These voluntary programs
are different in nature from the
proposed mandatory GHG emissions
reporting rule. Industry participation in
the programs and reporting to the
programs is entirely voluntary. A small
number of sources report, compared to
the number of facilities that would
likely be affected by the proposed
mandatory GHG reporting rule. Most of
the EPA voluntary programs do not
require reporting of annual emissions
data, but are instead intended to
encourage GHG reduction projects/
activities and track partner’s successes
in implementing such projects. For the
programs that do include annual
emissions reporting (e.g., Climate
Leaders, DOE 1605(b)) the scope and
level of detail are different. For
example, Climate Leaders annual
reports are generally corporate-wide and
do not contain the facility and process15 For more information about DOE’s 1605(b)
programs please see: https://www.pi.energy.gov/
enhancingGHGregistry/.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
level details that would be needed by a
mandatory program to verify the
accuracy of the emissions reports.
At the same time, aspects of the
voluntary programs serve as useful
starting points for the mandatory GHG
reporting rules. GHG emission
calculation principles and protocols
have been developed for various types
of emission sources by Climate Leaders,
the DOE 1605(b) program, and some
partnerships such as the SF6 reduction
partnerships and SmartWay. Under
these protocols, reporting companies
monitor process or operating parameters
to estimate GHG emissions, report
annually, and retain records to
document their GHG estimates. Through
the voluntary programs, EPA, DOE, and
participating companies have gained
understanding of processes that emit
GHGs and experience in developing and
reviewing GHG emission inventories.
B. Federal Mandatory Reporting
Programs
Sulfur Dioxide (SO2) and Nitrogen
Oxides (NOX) Trading Programs. The
ARP and the NOX Budget Trading
Program are cap-and-trade programs
designed to reduce emissions of SO2
and NOX16. As a part of those programs
facilities with EGUs that serve a
generator larger than 25 MW are
required to report emissions. The 40
CFR part 75 CEMS rule establishes
monitoring and reporting requirements
under these programs. The regulations
in 40 CFR part 75 require continuous
monitoring and quarterly and annual
emissions reporting of CO2 mass
emissions,17 SO2 mass emissions, NOX
emission rate, and heat input. Part 75
contains specifications for the types of
monitoring systems that may be used to
determine CO2 emissions and sets forth
operations, maintenance, and QA/QC
requirement for each system. In some
cases, EGUs are allowed to use
simplified procedures other than CEMS
(e.g., monitoring fuel feed rates and
conducting periodic sampling and
analyses of fuel carbon content) to
determine CO2 emissions. Under the
regulations, affected EGUs must submit
detailed quarterly and annual CO2
emissions reports using standardized
electronic reporting formats. If CEMS
are used, the quarterly reports include
hourly CEMS data and other
information used to calculate emissions
(e.g., monitor downtime). If alternative
monitoring programs are used, detailed
16 For
more information about these cap and trade
programs see https://www.epa.gov/airmarkt/.
17 The requirements regarding CO emissions
2
reporting apply only to ARP sources and are
pursuant to section 821 of the CAA Amendments
of 1990, Public Law 101–549.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
16459
data used to calculate CO2 emissions
must be reported.
The joint explanatory statement
accompanying the FY2008 Consolidated
Appropriations Amendment specified
that EPA could use the existing
reporting requirements for electric
generating units under section 821 of
the 1990 CAA Amendments.18 As
described in Sections V.C. and V.D. of
this preamble, because the part 75
regulations already require reporting of
high quality CO2 data from EGUs, the
GHG reporting rule proposes to use the
same CO2 data rather than require
additional reporting of CO2 from EGUs.
They would, however, have to include
reporting of the other GHG emissions,
such as CH4 and N2O, at their facilities.
TRI. TRI requires facility-level
reporting of annual mass emissions of
approximately 650 toxic chemicals.19 If
they are above established thresholds,
facilities in a wide range of industries
report including manufacturing
industries, metal and coal mining,
electric utilities, and other industrial
sectors. Facilities must submit annual
reports of total stack and fugitive
emissions of the listed toxic chemicals
using a standardized form which can be
submitted electronically. No
information is reported on the processes
and emissions points included in the
total emissions. The data reported to
TRI are not directly useful for the GHG
rule because TRI does not include GHG
emissions and does not identify
processes or emissions sources.
However, the TRI program is similar to
the proposed GHG reporting rule in that
it requires direct emissions reporting
from a large number of facilities
(roughly 23,000) across all major
industrial sectors. Therefore, EPA
reviewed the TRI program for ideas
regarding program structure and
implementation.
Vehicle Reporting. EPA’s existing
criteria pollutant emissions certification
regulations, as well as the fuel economy
testing regulations which EPA
administers as part of the CAFE
program, require vehicle manufacturers
to measure and report CO2 for
essentially all of their light duty
vehicles. In addition, many engine
manufacturers currently measure CO2 as
an integral part of calculating emissions
of criteria pollutants, and some report
CO2 emissions to EPA in some form.
C. EPA Emissions Inventories
U.S. Inventory of Greenhouse Gas
Emissions and Sinks. As discussed in
Section I.D of this preamble, EPA
prepares the U.S. Inventory of
Greenhouse Gas Emissions and Sinks
every year. The details of this Inventory,
the methodologies used to calculate
emissions and its relationship to this
proposal are discussed in Section I.D of
this preamble.
NEI. 20 EPA compiles the NEI, a
database of air emissions information
provided primarily by State and local
air agencies and Tribes. The database
contains information on stationary and
mobile sources that emit criteria air
pollutants and their precursors, as well
as hazardous air pollutants. Stationary
point source emissions that must be
inventoried and reported are those that
emit over a threshold amount of at least
one criteria pollutant. Many States also
inventory and report stationary sources
that emit amounts below the thresholds
for each pollutant. The NEI includes
over 60,000 facilities. The information
that is required consists of facility
identification information; process
information detailing the types of air
pollution emission sources; air
pollution emission estimates (including
annual emissions); control devices in
place; stack parameters; and location
information. The NEI differs from the
proposed GHG reporting rule in that the
NEI contains no GHG data, and the data
are reported primarily by State agencies
rather than directly reported by
industries.21 However, in developing
the proposed rule, EPA used the NEI to
help determine sources that might need
to report under the GHG reporting rule.
We considered the types of facility,
process and activity data reported in
NEI to support the emissions data as a
possible model for the types of data to
be reported under the GHG reporting
rule. We also considered systems that
could be used to link data reported
under the GHG rule with data for the
same facilities in the NEI.
18 The joint explanatory statement refers to
‘‘Section 821 of the Clean Air Act’’ but section 821
was part of the 1990 CAA Amendments not
codified into the CAA itself.
19 For more information about TRI and what
chemicals are on the list, please see: https://
www.epa.gov/tri/.
20 For more information about the NEI please see:
https://www.epa.gov/ttn/chief/net/.
21 As discussed in section IV of the preamble,
tropospheric ozone (O3) is a GHG. The precursors
to tropospheric O3 (e.g., NOX, VOCs, etc) are
reported to the NEI by States and then EPA models
tropospheric O3 based on that precursor data.
PO 00000
Frm 00013
Fmt 4701
Sfmt 4702
D. Regional and State Voluntary
Programs for GHG Emissions Reporting
A number of States have
demonstrated leadership and developed
corporate voluntary GHG reporting
programs individually or joined with
other States to develop GHG reporting
programs as part of their approaches to
addressing GHG emissions. EPA has
E:\FR\FM\10APP2.SGM
10APP2
16460
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
benefitted from this leadership and the
States’ experiences; discussions with
those that have already implemented
programs have been especially
instructive. Section V of the preamble
describes the proposed methods for
each source category. The different
options considered have been
particularly informed by the States’
expertise. This section of the preamble
summarizes two prominent voluntary
efforts. In developing the greenhouse
rules, EPA reviewed the relevant
protocols used by these programs as a
starting point. We recognize that these
programs may have additional
monitoring and reporting requirements
than those outlined in the proposed rule
in order to provide distinct program
benefits.
CCAR.22 CCAR is a voluntary GHG
registry already in use in California.
CCAR has released several methodology
documents including a general reporting
protocol, general certification
(verification) protocol, and several
sector-specific protocols. Companies
submit emissions reports using a
standardized electronic system.
Emission reports may be aggregated at
the company level or reported at the
facility level.
TCR.23 TCR is a partnership formed
by U.S. and Mexican States, Canadian
provinces, and Tribes to develop
standard GHG emissions measurement
and verification protocols and a
reporting system capable of supporting
mandatory or voluntary GHG emission
reporting rules and policies for its
member States. TCR has released a
General Reporting Protocol that contains
procedures to measure and calculate
GHG emissions from a wide range of
source categories. They have also
released a general verification protocol,
and an electronic reporting system.
Founding reporters (companies and
other organizations that have agreed to
voluntarily report their GHG emissions)
implemented a pilot reporting program
in 2008. Annual reports would be
submitted covering six GHGs.
Corporations must report facilityspecific emissions, broken out by type
of emission source (e.g., stationary
combustion, electricity use, direct
process emissions) within the facility.
E. State and Regional Mandatory
Programs for GHG Emissions Reporting
and Reduction
Several individual States and regional
groups of States have demonstrated
22 For
more information about CCAR please see:
https://www.climateregistry.org/.
23 For more information about TCR please see:
https://www.theclimateregistry.org/.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
leadership and are developing or have
developed mandatory GHG reporting
programs and GHG emissions control
programs. This section of the preamble
summarizes two regional cap-and-trade
programs and several State mandatory
reporting rules. We recognize that, like
the current voluntary regional and State
programs, State and regional mandatory
reporting programs may evolve or
develop to include additional
monitoring and reporting requirements
than those included in the proposed
rule. In fact, these programs may be
broader in scope or more aggressive in
implementation because the programs
are either components of established
reduction programs (e.g., cap and trade)
or being used to design and inform
specific complementary measures (e.g.,
energy efficiency).
RGGI.24 RGGI is a regional cap-andtrade program that covers CO2 emissions
from EGUs that serve a generator greater
than 25 MW in member States in the
mid-Atlantic and Northeast. The
program goal is to reduce CO2 emissions
to 10 percent below 1990 levels by the
year 2020. RGGI will utilize the CO2
reported to and verified by EPA under
40 CFR part 75 to determine compliance
of the EGUs in the cap-and-trade
program. In addition, the EGUs in RGGI
that are not currently reporting to EPA
under the ARP and NOX Budget
program (e.g., co-generation facilities)
will start reporting their CO2 data to
EPA for QA/QC, similar to the sources
already reporting. Certain types of offset
projects will be allowed, and GHG offset
protocols have been developed. The
States participating in RGGI have
adopted State rules (based on the model
rule) to implement RGGI in each State.
The RGGI cap-and-trade program took
effect on January 1, 2009.
WCI.25 WCI is another regional capand-trade program being developed by a
group of Western States and Canadian
provinces. The goal is to reduce GHG
emissions to 15 percent below 2005
levels by the year 2020. Draft options
papers and program scope papers were
released in early 2008, public comments
were reviewed, and final program
design recommendations were made in
September 2008. Other elements of the
program, such as reporting
requirements, market operations, and
offset program development continues.
Several source categories are being
considered for inclusion in the cap and
trade framework. The program might be
phased in, starting with a few source
24 For
more information about RGGI please see:
https://www.rggi.org/.
25 For more information about WCI please see:
https://www.westernclimateinitiative.org/.
PO 00000
Frm 00014
Fmt 4701
Sfmt 4702
categories and adding others over time.
Points of regulation for some source
categories, calculation methodologies,
and other reporting program elements
are under development. The WCI is also
analyzing alternative or complementary
policies other than cap-and-trade that
could help reach GHG reduction goals.
Options for rule implementation and for
coordination with other rules and
programs such as TCR are being
investigated.
A key difference between the Federal
mandatory GHG reporting rule and the
RGGI and WCI programs is that the
Federal mandatory GHG rule is solely a
reporting requirement. It does not in any
way regulate GHG emissions or require
any emissions reductions.
State Mandatory GHG Reporting
Rules. Seventeen States have developed,
or are developing, mandatory GHG
reporting rules.26 The docket contains a
summary of these State mandatory rules
(EPA–HQ–OAR–2008–0508–056). Final
rules have not yet been developed by
some of the States, so details of some
programs are unknown. Reporting
requirements have taken effect in twelve
States as of 2009; the rest start between
2010 and 2012. Reporting is typically
annual, although some States require
quarterly reporting for EGUs, consistent
with RGGI and the ARP.
State rules differ with regard to which
facilities must report and which GHGs
must be reported. Some States require
all facilities that must obtain Title V
permits to report GHG emissions. Others
require reporting for particular sectors
(e.g., large EGUs, cement plants,
refineries). Some State rules apply to
any facility with stationary combustion
sources that emit a threshold level of
CO2. Some apply to any facility, or to
facilities within listed industries, if their
emissions exceed a specified threshold
level of CO2e. Many of the State rules
apply to six GHGs (CO2, CH4, N2O,
HFCs, PFCs, SF6); others apply only to
CO2 or a subset of the six gases. Most
require reporting at the facility level, or
by unit or process within a facility.
The level of specificity regarding GHG
monitoring and calculation methods
varies. Some of the States refer to use of
protocols established by TCR or CCAR.
Others look to industry-specific
protocols (such as methods developed
by the American Petroleum Institute), to
accepted international methodologies
such as IPCC, and/or to emission factors
in EPA’s Compilation of Air Pollutant
26 These include: California, Colorado,
Connecticut, Delaware, Hawaii, Iowa, Maine,
Maryland, Massachusetts, New Jersey, New Mexico,
North Carolina, Oregon, Virginia, Washington, West
Virginia, and Wisconsin.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Emission Factors (known as AP–42 27)
or other EPA guidance.
California Mandatory GHG Reporting
Rule.28 CARB’s mandatory reporting
rule is an example of a State rule that
covers multiple source categories and
contains relatively detailed
requirements, similar to this proposal
developed by EPA. According to the
CARB proposed rule (originally
proposed October 19, 2007, and revised
on December 5, 2007), monitoring must
start on January 1, 2009, and the first
reports will be submitted in 2010. The
rule requires facility-level reporting of
all GHGs, except PFCs, from cement
manufacturing plants, electric power
generation and retail, cogeneration
plants, petroleum refineries, hydrogen
plants, and facilities with stationary
combustion sources emitting greater
than 25,000 tons CO2 per year.
California requires 40 CFR part 75 data
for EGUs. The California rule contains
specific GHG estimation methods that
are largely consistent with CCAR
protocols, and also rely on American
Petroleum Institute protocols and IPCC/
EU protocols for certain types of
sources. California continues to
participate in other national and
regional efforts, such as TCR and WCI,
to assist with developing consistent
reporting tools and procedures on a
national and regional basis.
F. How the Proposed Mandatory GHG
Reporting Program Is Different From the
Federal and State Programs EPA
Reviewed
The various existing State and Federal
programs EPA reviewed are diverse.
They apply to different industries, have
different thresholds, require different
pollutants and different types of
emissions sources to be reported, rely
on different monitoring protocols, and
require different types of data to be
reported, depending on the purposes of
each program. None of the existing
programs require nationwide,
mandatory GHG reporting by facilities
in a large number of sectors, so EPA’s
proposed mandatory GHG rule
development effort is unique in this
regard.
Although the mandatory GHG rule is
unique, EPA carefully considered other
Federal and State programs during
development of the proposed rule.
Documentation of our review of GHG
monitoring protocols for each source
category used by Federal, State, and
27 See Compilation of Air Pollutant Emission
Factors, Fifth Edition: https://www.epa.gov/ttn/
chief/ap42/_ac/.
28 For more information about CA mandatory
reporting program please see: https://
www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
international voluntary and mandatory
GHG programs, and our review of State
mandatory GHG rules can be found at
EPA–HQ–OAR–2008–0508–056. The
proposed monitoring and GHG
calculation methodologies for many
source categories are the same as, or
similar to, the methodologies contained
in State reporting programs such as
TCR, CCAR, and State mandatory GHG
reporting rules and similar to
methodologies developed by EPA
voluntary programs such as Climate
Leaders. The reporting requirements set
forth in 40 CFR part 75 are also being
used for this proposed rule. Similarity
in proposed methods would help
maximize the ability of individual
reporters to submit the emissions
calculations to multiple programs, if
desired. EPA also continues to work
closely with States and State-based
groups to ensure that the data
management approach in this proposal
would lead to efficient submission of
data to multiple programs. Section V of
this preamble includes further
information on the selection of
monitoring methods for each source
category.
The intent of this proposed rule is to
collect accurate and consistent GHG
emissions data that can be used to
inform future decisions. One goal in
developing the rule is to utilize and be
consistent with the GHG protocols and
requirements of other State and Federal
programs, where appropriate, to make
use of existing cooperative efforts and
reduce the burden to facilities
submitting reports to other programs.
However, we also need to be sure the
mandatory reporting rule collects
facility-specific data of sufficient quality
to achieve the Agency’s objectives for
this rule. Therefore, some reporting
requirements of this proposed rule are
different from the State programs. The
remaining sections of this preamble
further describe the proposed rule
requirements and EPA’s rationale for all
of the requirements.
EPA seeks comment on whether the
conclusions drawn during its review of
existing programs are accurate and
invites data to demonstrate if, and if so
how, the goals and objectives of this
proposed mandatory reporting system
could be met through existing programs.
In particular, comments should address
how existing programs meet the breadth
of sources reporting, thresholds for
reporting, consistency and stringency of
methods for reporting, level of
reporting, frequency of reporting and
verification of reports included in this
proposal.
PO 00000
Frm 00015
Fmt 4701
Sfmt 4702
16461
III. Summary of the General
Requirements of the Proposed Rule
The proposed rule would require
reporting of annual emissions of CO2,
CH4, N2O, SF6, HFCs, PFCs, and other
fluorinated gases (as defined in
proposed 40 CFR part 98, subpart A).
The rule would apply to certain
downstream facilities that emit GHGs,
upstream suppliers of fossil fuels and
industrial GHGs, and manufacturers of
vehicles and engines.29 We are
proposing that reporting be at the
facility 30 level, except that certain
suppliers of fossil fuels and industrial
gases and manufacturers of vehicles and
engines would report at the corporate
level.
A. Who must report?
Owners and operators of the following
facilities and supply operations would
submit annual GHG emission reports
under the proposal:
• A facility that contains any of the
source categories listed below in any
calendar year starting in 2010. For
these facilities, the GHG emission
report would cover all sources in any
source category for which calculation
methodologies are provided in
proposed 40 CFR part 98, subparts B
through JJ.
—Electricity generating facilities that
are subject to the ARP, or that
contain electric generating units
that collectively emit 25,000 metric
tons of CO2e or more per year.31
—Adipic acid production.
—Aluminum production.
—Ammonia manufacturing.
—Cement production.
—Electronics—Semiconductor,
MEMS, and LCD (LCD)
manufacturing facilities with an
annual production capacity that
exceeds any of the thresholds listed
in this paragraph—Semiconductors:
29 We are proposing to incorporate the reporting
requirements for manufacturers of motor vehicles
and engines into the existing reporting
requirements of 40 CFR parts 86, 89, 90, 91, 92, 94,
1033, 1039, 1042, 1045, 1048, 1051, and 1054.
30 For the purposes of this proposal, facility
means any physical property, plant, building,
structure, source, or stationary equipment located
on one or more contiguous or adjacent properties
in actual physical contact or separated solely by a
public roadway or other public right-of-way and
under common ownership or common control, that
emits or may emit any greenhouse gas. Operators
of military installations may classify such
installations as more than a single facility based on
distinct and independent functional groupings
within contiguous military properties.
31 This does not include portable equipment or
generating units designated as emergency
generators in a permit issued by a state or local air
pollution control agency. As described in section
V.C of the preamble we are taking comment on
whether or not a permit should be required.
E:\FR\FM\10APP2.SGM
10APP2
16462
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
1,080 m2 silicon, MEMS: 1,202 m2
silicon, LCD: 235,700 m2 LCD.
—Electric power systems that include
electrical equipment with a total
nameplace capacity that exceeds
17,820 lbs (7,838 kg) of SF6 or PFCs.
—HCFC–22 production.
—HFC–23 destruction processes that
are not colocated with a HCFC–22
production facility and that destroy
more than 2.14 metric tons of HFC–
23 per year.
—Lime manufacturing.
—Nitric acid production.
—Petrochemical production.
—Petroleum refineries.
—Phosphoric acid production.
—Silicon carbide production.
—Soda ash production.
—Titanium dioxide production.
—Underground coal mines that are
subject to quarterly or more
frequent sampling by MSHA of
ventilation systems.
—Municipal landfills that generate
CH4 in amounts equivalent to
25,000 metric tons CO2e or more
per year.
—Manure management systems that
emit CH4 and N2O in amounts
equivalent to 25,000 metric tons
CO2e or more per year.
• Any facility that emits 25,000 metric
tons CO2e or more per year in
combined emissions from stationary
fuel combustion units, miscellaneous
use of carbonates and all of the source
categories listed below that are
located at the facility in any calendar
year starting in 2010. For these
facilities, the GHG emission report
would cover all source categories for
which calculation methodologies are
provided in proposed 40 CFR part 98,
subparts B through JJ of the rule.
—Electricity Generation 32
—Electronics—Photovoltaic
Manufacturing
—Ethanol Production
—Ferroalloy Production
—Fluorinated Greenhouse Gas
Production
—Food Processing
—Glass Production
—Hydrogen Production
—Iron and Steel Production
—Lead Production
—Magnesium Production
—Oil and Natural Gas Systems
—Pulp and Paper Manufacturing
—Zinc Production
—Industrial Landfills
—Wastewater
32 This does not include portable equipment or
generating units designated as emergency
generators in a permit issued by a state or local air
pollution control agency. As described in section
V.C of the preamble we are taking comment on
whether or not a permit should be required.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
• Any facility that in any calendar year
starting in 2010 meets all three of the
conditions listed in this paragraph.
For these facilities, the GHG emission
report would cover emissions from
stationary fuel combustion sources
only. For 2010 only, the facilities can
submit an abbreviated emissions
report according to proposed 40 CFR
98.3(d).
—The facility does not contain any
source in any source category
designated in the above two
paragraphs;
—The aggregate maximum rated heat
input capacity of the stationary fuel
combustion units at the facility is
30 mmBtu/hr or greater; and
—The facility emits 25,000 metric
tons CO2e or more per year from all
stationary fuel combustion
sources.33
• Any supplier of any of the products
listed below in any calendar year
starting in 2010. For these suppliers,
the GHG emissions report would
cover all applicable products for
which calculation methodologies are
provided in proposed 40 CFR part 98,
subparts KK through PP.
—Coal.
—Coal-based liquid fuels.
—Petroleum products.
—Natural gas and NGLs.
—Industrial GHGs: All producers of
industrial GHGs, importers and
exporters of industrial GHGs with
total bulk imports or total bulk
exports that exceed 25,000 metric
tons CO2e per year.
—CO2: All producers of CO2,
importers and exporters of CO2 or a
combination of CO2 and other
industrial GHGs with total bulk
imports or total bulk exports that
exceed 25,000 metric tons CO2e per
year.
• Manufacturers of mobile sources and
engines would be required to report
emissions from the vehicles and
engines they produce, generally in
terms of an emission rate.34 These
requirements would apply to
emissions of CO2, CH4, N2O, and,
where appropriate, HFCs.
Manufacturers of the following
vehicle and engine types would need
to report: (1) Manufacturers of
passenger cars, light trucks, and
medium-duty passenger vehicles, (2)
manufacturers of highway heavy-duty
33 This does not include portable equipment or
generating units designated as emergency
generators in a permit issued by a state or local air
pollution control agency. As described in section V.
C of the preamble we are taking comment on
whether or not a permit should be required.
34 As discussed in Section V.QQ, manufacturers
below a size threshold would be exempt.
PO 00000
Frm 00016
Fmt 4701
Sfmt 4702
engines and complete vehicles, (3)
manufacturers of nonroad diesel
engines and nonroad large sparkignition engines, (4) manufacturers of
nonroad small spark-ignition engines,
marine spark-ignition engines,
personal watercraft, highway
motorcycles, and recreational engines
and vehicles, (5) manufacturers of
locomotive and marine diesel engines,
and (6) manufacturers of jet and
turboprop aircraft engines.
B. Schedule for Reporting
Facilities and suppliers would begin
collecting data on January 1, 2010. The
first emissions report would be due on
March 31, 2011, for emissions during
2010.35 36 Reports would be submitted
annually. Facilities with EGUs that are
subject to the ARP would continue to
report CO2 mass emissions quarterly, as
required by the ARP, in addition to
providing the annual GHG emissions
reports under this rule. EPA is
proposing that the rule require the
submission of GHG emissions data on
an ongoing, annual basis. The snapshot
of information provided by a one-time
information collection request would
not provide the type of ongoing
information which could inform the
variety of potential policy options being
evaluated for addressing climate change.
EPA is taking comment on other
possible options, including a
commitment to review the continued
need for the information at a specific
later date, or a sunset provision. Once
subject to this reporting rule, a facility
or supply operation would continue to
submit reports even if it falls below the
reporting thresholds in future years.
C. What do I have to report?
The report would include total annual
GHG emissions in metric tons of CO2e
aggregated for all the source categories
and for all supply categories for which
emission calculation methods are
provided in part 98. The report would
also separately present annual mass
GHG emissions for each source category
and supply category, by gas. Separate
reporting requirements are provided for
vehicle and engine manufacturers.
These sources would be required to
report emissions from the vehicles and
engines they produce, generally in terms
of an emission rate.
Within a given source category, the
report also would break out emissions at
the level required by the respective
subpart (e.g., reporting could be
35 Unless otherwise noted, years and dates in this
notice refer to calendar years and dates.
36 There is a discussion in section I.IV of this
preamble that takes comment on alternative
reporting schedules.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
required for each individual unit for
some source categories and for each
process line for other source categories).
In addition to GHG emissions, you
would report certain activity data (e.g.,
fuel use, feedstock inputs) that were
used to generate the emissions data. The
required activity data are specified in
each subpart. For some source
categories, additional data would be
reported to support QA/QC and
verification.
EPA would protect any information
claimed as CBI in accordance with
regulations in 40 CFR part 2, subpart B.
However, note that in general, emission
data collected under CAA sections 114
and 208 cannot be considered CBI.37
D. How do I submit the report?
The reports would be submitted
electronically, in a format to be
specified by the Administrator after
publication of the final rule.38 To the
extent practicable, we plan to adapt
existing facility reporting programs to
accept GHG emissions data. We are
developing a new electronic data
reporting system for source categories or
suppliers for which it is not feasible to
use existing reporting mechanisms.
Each report would contain a signed
certification by a Designated
Representative of the facility. On behalf
of the owner or operator, the Designated
Representative would certify under
penalty of law that the report has been
prepared in accordance with the
requirements of 40 CFR part 98 and that
the information contained in the report
is true and accurate, based on a
reasonable inquiry of individuals
responsible for obtaining the
information.
E. What records must I retain?
Each facility or supplier would also
have to retain and make available to
EPA upon request the following records
for five years in an electronic or hardcopy format as appropriate:
• A list of all units, operations,
processes and activities for which GHG
emissions are calculated;
• The data used to calculate the GHG
emissions for each unit, operation,
process, and activity, categorized by fuel
or material type;
• Documentation of the process used
to collect the necessary data for the GHG
emissions calculations;
37 Although CBI determinations are usually made
on a case-by-case basis, EPA has issued guidance
in an earlier Federal Register notice on what
constitutes emissions data that cannot be
considered CBI (956 FR 7042–7043, February 21,
1991).
38 For more information about the reporting
format please see section VI of this preamble.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
• The GHG emissions calculations
and methods used;
• All emission factors used for the
GHG emissions calculations;
• Any facility operating data or
process information used for the GHG
emissions calculations;
• Names and documentation of key
facility personnel involved in
calculating and reporting the GHG
emissions;
• The annual GHG emissions reports;
• A log book documenting any
procedural changes to the GHG
emissions accounting methods and any
changes to the instrumentation critical
to GHG emissions calculations;
• Missing data computations;
• A written QAPP;
• Any other data specified in any
applicable subpart of proposed 40 CFR
part 98. Examples of such data could
include the results of sampling and
analysis procedures required by the
subparts (e.g., fuel heat content, carbon
content of raw materials, and flow rate)
and other data used to calculate
emissions.
IV. Rationale for the General Reporting,
Recordkeeping and Verification
Requirements That Apply to All Source
Categories
This section of the preamble explains
the rationales for EPA’s proposals for
various aspects of the rule. This section
applies to all of the source categories in
the preamble (further discussed in
Sections V.B through V.PP of this
preamble) with the exception of mobile
sources (discussed in Section V.QQ of
this preamble). The proposals EPA is
making with regard to mobile sources
are extensions of existing EPA programs
and therefore the rationales and
decisions are discussed wholly within
that section. With respect to the source
categories B through PP, EPA is
particularly interested in receiving
comments on the following issues:
(1) Reporting thresholds. EPA is
interested in receiving data and analyses
on thresholds. In particular, we solicit
comment on whether the thresholds
proposed are appropriate for each
source category or whether other
emissions or capacity based thresholds
should be applied. If suggesting
alternative thresholds, please discuss
whether and how they would achieve
broad emissions coverage and result in
a reasonable number of reporters.
(2) Methodologies. EPA is interested
in receiving data, technical information
and analyses relevant to the
methodology approach. We solicit
comment on whether the methodologies
selected by EPA are appropriate for each
source category or whether alternative
PO 00000
Frm 00017
Fmt 4701
Sfmt 4702
16463
approaches should be adopted. In
particular, EPA would like information
on the technical feasibility, costs, and
relative improvement in accuracy of
direct measurement at facilities. If
suggesting an alternative methodology
(e.g., using established industry default
factors or allowing industry groups to
propose an industry specific emission
factor to EPA), please discuss whether
and how it provides complete and
accurate emissions data, comparable to
other source categories, and also reflects
broadly agreed upon calculation
procedures for that source category.
(3) Frequency and year of reporting.
EPA is interested in receiving data and
analyses regarding frequency of
reporting and the schedule for reporting.
In particular, we solicit information
regarding whether the frequency of data
collection and reporting selected by
EPA is appropriate for each source
category or whether alternative
frequencies should be considered (e.g.,
quarterly or every few years). If
suggesting an alternative frequency,
please discuss whether and how it
ensures that EPA and the public receive
the data in a timely fashion that allow
it to be relevant for future policy
decisions. EPA is proposing 2010 data
collection and 2011 reporting, however,
we are interested in receiving comment
on alternative schedules if we are
unable to meet our goal.
(4) Verification. EPA is interested in
receiving data and analyses regarding
verification options. We solicit input on
whether the verification approach
selected by EPA is appropriate for each
source category or whether an
alternative approach should be adopted.
If suggesting an alternative verification
approach, please discuss how it weighs
the costs and burden to the reporter and
EPA as well as the need to ensure the
data are complete, accurate, and
available in the timely fashion.
(5) Duration of the program. EPA is
interested in receiving data and analyses
regarding options for the duration of the
GHG emissions information collection
program in this proposed rule. By
duration, EPA means for how many
years the program should require the
submission of information. EPA solicits
input on whether the duration selected
by EPA is appropriate for each source
category or whether an alternative
approach should be adopted. If
suggesting an alternative duration,
please discuss how it impacts the need
to ensure the data are sufficient to
inform the variety of potential policy
decisions regarding climate change
under consideration.
E:\FR\FM\10APP2.SGM
10APP2
16464
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
A. Rationale for Selection of GHGs To
Report
The proposed rule would require
reporting of CO2, CH4, N2O, HFCs, PFCs,
SF6, and other fluorinated compounds
(e.g., NF3 and HFEs) as defined in the
rule 39. These are the most abundantly
emitted GHGs that result from human
activity. They are not currently
controlled by other mandatory Federal
programs and, with the exception of the
CO2 emissions data reported by EGUs
subject to the ARP 40, GHG emissions
data are also not reported under other
mandatory Federal programs. CO2 is the
largest contributor of GHGs directly
emitted by human activities, and is a
significant driver of climate change. The
anthropogenic combined heating effect
of CH4, N2O, HFCs, PFCs, SF6, and the
other fluorinated compounds are also
significant: About 40 percent as large as
the CO2 heating effect according to the
Fourth Assessment Report of the IPCC.
The IPCC focuses on CO2, CH4, N2O,
HFCs, PFCs, and SF6 for both scientific
assessments and emissions inventory
purposes because these are long-lived,
well-mixed GHGs not controlled by the
Montreal Protocol as Substances that
Deplete the Ozone Layer. These GHGs
are directly emitted by human activities,
are reported annually in EPA’s
Inventory of U.S. Greenhouse Gas
Emissions and Sinks, and are the
common focus of the climate change
research community. The IPCC also
included methods for accounting for
emissions from several specified
fluorinated gases in the 2006 IPCC
Guidelines for National Greenhouse Gas
Inventories.41 These gases include
fluorinated ethers, which are used in
electronics, anesthetics, and as heat
transfer fluids. Like the other six GHGs
for which emissions would be reported,
these fluorinated compounds are longlived in the atmosphere and have high
GWP. In many cases these fluorinated
gases are used in expanding industries
(e.g., electronics) or as substitutes for
39 The GWPs for the GHGs to be reported are
found in Table A–1 of proposed 40 CFR part 98,
subpart A.
40 Pursuant to regulations established under
section 821 of the CAA Amendments of 1990,
hourly CO2 emissions are monitored and reported
quarterly to EPA. EPA performs a series of QA/QC
checks on the data and then makes it available on
the Web site (https://epa.gov/camddataandmaps/)
usually within 30 days after receipt.
41 2006 IPCC Guidelines for National Greenhouse
Gas Inventories. The National Greenhouse Gas
Inventories Programme, H.S. Eggleston, L. Buendia,
K. Miwa, T. Ngara, and K. Tanabe (eds), hereafter
referred to as the ‘‘2006 IPCC Guidelines’’ are found
at: https://www.ipcc.ch/ipccreports/methodologyreports.htm. For additional information on these
gases please see Table A–1 in proposed 40 CFR part
98, subpart A and the Suppliers of Industrial GHGs
TSD (EPA–HQ–OAR–2008–0508–041).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
HFCs. As such, EPA is proposing to
include reporting of these gases to
ensure that the Agency has an accurate
understanding of the emissions and uses
of these gases, particularly as those uses
expand.
There are other GHGs and aerosols
that have climatic warming effects that
we are not proposing to include in this
rule: Water vapor, CFCs, HCFCs, halons,
tropospheric O3, and black carbon.
There are a number of reasons why we
are not proposing to require reporting of
these gases and aerosols under this rule.
For example, these GHGs and aerosols
are not covered under any State or
Federal voluntary or mandatory GHG
program, the UNFCCC or the Inventory
of U.S. Greenhouse Gas Emissions and
Sinks. Nonetheless, we request
comment on the selection of GHGs that
are or are not included in the proposed
rule; include data supporting your
position on why a GHG should or
should not be included. More detailed
discussions for particular substances
that we do not propose including in this
rule follow.
Water Vapor. Water vapor is the most
abundant naturally occurring GHG and,
therefore, makes up a significant share
of the natural, background greenhouse
effect. However, water vapor emissions
from human activities have only a
negligible effect on atmospheric
concentrations of water vapor.
Significant changes to global
atmospheric concentrations of water
vapor occur indirectly through humaninduced global warming, which then
increases the amount of water vapor in
the atmosphere because a warmer
atmosphere can hold more moisture.
Therefore, changes in water vapor
concentrations are not an initial driver
of climate change, but rather an effect of
climate change which then acts as a
positive feedback that further enhances
warming. For this reason, the IPCC does
not list direct emissions of water vapor
as an anthropogenic forcing agent of
climate change, but does include this
water vapor feedback mechanism in
response to human-induced warming in
all modeling scenarios of future climate
change. Based on this recognition that
anthropogenic emissions of water vapor
are not a significant driver of
anthropogenic climate change, EPA’s
annual Inventory of U.S. Greenhouse
Gas Emissions and Sinks does not
include water vapor, and GHG
inventory reporting guidelines under
the UNFCCC do not require data on
water vapor emissions.
ODS. The CFCs, HCFCs, and halons
are all strong anthropogenic GHGs that
are long-lived in the atmosphere and are
adding to the global anthropogenic
PO 00000
Frm 00018
Fmt 4701
Sfmt 4702
heating effect. Therefore, these gases
share common climatic properties with
the other GHGs discussed in this
preamble. The production and
consumption of these substances (and,
hence, their anthropogenic emissions)
are being controlled and phased out, not
because of their effects on climate
change, but because they deplete
stratospheric O3, which protects against
harmful ultraviolet B radiation. The
control and phase-out of these
substances in the U.S. and globally is
occurring under the Montreal Protocol
on Substances that Deplete the Ozone
Layer, and in the U.S. under Title VI of
the CAA as well.42 Therefore, the
climate change research and policy
community typically does not focus on
these substances, precisely because they
are essentially already being addressed
with non-climate policy mechanisms.
The UNFCCC does not cover these
substances, and instead defers their
treatment to the Montreal Protocol.
Tropospheric Ozone. Increased
concentrations of tropospheric O3 are
causing a significant anthropogenic
warming effect, but, unlike the longlived GHGs, tropospheric O3 has a short
atmospheric lifetime (hours to weeks),
and therefore its concentrations are
more variable over space and time. For
these reasons, its global heating effect
and relevance to climate change tends to
entail greater uncertainty compared to
the well-mixed, long-lived GHGs.
Tropospheric O3 is not addressed under
the UNFCCC. Moreover, tropospheric O3
is already listed as a NAAQS pollutant
and its precursors are reported to States.
Tropospheric O3 is subsequently
modeled based on the precursor data
reported to the NEI.
Black Carbon. Black carbon is an
aerosol particle that results from
incomplete combustion of the carbon
contained in fossil fuels, and it remains
in the atmosphere for about a week.
There is some evidence that black
carbon emissions may contribute to
climate warming by absorbing incoming
and reflected sunlight in the atmosphere
and by darkening clouds, snow and ice.
While the net effect of anthropogenic
aerosols has a cooling effect (CCSP
2009), there is considerable uncertainty
42 Under the Montreal Protocol, production and
consumption of CFCs were phased out in developed
countries in 1996 (with some essential use
exemptions) and are scheduled for phase-out by
2010 in developing countries (with some essential
use exemptions). For halons the schedule was 1994
for phase out in developed countries and 2010 for
developing countries; HCFC production was frozen
in 2004 in developed countries, and in 2016
production will be frozen in developing countries;
and HCFC consumption phase-out dates are 2030
for developed countries and 2040 in developing
countries.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
in quantifying the effects of black
carbon on radiative forcing and whether
black carbon specifically has direct or
indirect warming effects. The National
Academy of Sciences states
‘‘Regulations targeting black carbon
emissions or ozone precursors would
have combined benefits for public
health and climate’’ 43 while also
indicating that the level of scientific
understanding regarding the effect of
black carbon on climate is ‘‘very low.’’
The direct and indirect radiative forcing
properties of multiple aerosols,
including sulphates, organic carbon,
and black carbon, are not well
understood. While mobile diesel
engines have been the largest black
carbon source in the U.S., these
emissions are expected to be reduced
significantly over the next several
decades based on CDPFs for new
vehicles.
B. Rationale for Selection of Source
Categories To Report
Section III of this preamble lists the
source categories that would submit
reports under the proposed rule. The
source categories identified in this list
were selected after considering the
language of the Appropriations Act and
the accompanying explanatory
statement, and EPA’s experience in
developing the U.S. GHG Inventory. The
Appropriations Act referred to reporting
‘‘in all sectors of the economy’’ and the
explanatory statement directed EPA to
include ‘‘emissions from upstream
production and downstream sources to
the extent the Administrator deems it
appropriate.’’ 44 In developing the
proposed list, we also used our
significant experience in quantifying
GHG emissions from source categories
across the economy for the Inventory of
U.S. Greenhouse Gas Emissions and
Sinks.
As a starting point, EPA first
considered all anthropogenic sources of
GHG emissions. The term
‘‘anthropogenic’’ refers to emissions that
are produced as a result of human
activities (e.g., combustion of coal in an
electric utility or CH4 emissions from a
landfill). This is in contrast to GHGs
that are emitted to the atmosphere as a
result of natural activities, such as
volcanoes. Anthropogenic emissions
may be of biogenic origin (manure
lagoons) or non-biogenic origin (e.g.,
coal mines). Consistent with existing
43 National Academy of Sciences, ‘‘Radiative
Forcing of Climate Change: Expanding the Concept
and Addressing Uncertainties,’’ October 2005.
44 To read the full appropriations language please
refer to the links on this Web site: https://
www.epa.gov/climatechange/emissions/
ghgrulemaking.html.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
international, national, regional, and
corporate-level GHG reporting
programs, this proposal includes only
anthropogenic sources.
As a second step, EPA considered all
of the source categories in the Inventory
of U.S. Greenhouse Gas Emissions and
Sinks because, as described in Section
I.D of this preamble, it is a top-down
assessment of anthropogenic sources of
emissions in the U.S. Furthermore, the
Inventory has been independently
reviewed by national and international
experts and is considered to be a
comprehensive representation of
national-level GHG emissions and
source categories relevant for the U.S.
As a third step, EPA also carefully
reviewed the recently completed 2006
IPCC Guidelines for National
Greenhouse Gas Inventories for
additional source categories that may be
relevant for the U.S. These international
guidelines are just beginning to be
incorporated into national inventories.
The 2006 IPCC Guidelines identified
one additional source category for
consideration (fugitive emissions from
fluorinated GHG production).
As a fourth step, once EPA had a
complete list of source categories
relevant to the U.S., the Agency
systematically reviewed those source
categories against the following criteria
to develop the list to the source
categories included in the proposal:
(1) Include source categories that emit
the most significant amounts of GHG
emissions, while also minimizing the
number of reporters, and
(2) Include source categories that can
be measured with an appropriate level
of accuracy.
To accomplish the first criterion, EPA
set reporting thresholds, as described in
Section IV.C of this preamble, that are
designed to target large emitters. When
the proposed thresholds are applied, the
source categories included in this
proposal meet the criterion of balancing
the emissions coverage with a
reasonable number of reporters. For
more detailed information about the
coverage of emissions and number of
reporters see the Thresholds TSD (EPA–
HQ–OAR–2008–0508–046) and the RIA
(EPA–HQ–OAR–2008–0508–002).
The second criterion was to require
reporting for only those sources for
which measurement capabilities are
sufficiently accurate and consistent.
Under this criterion, EPA considered
whether or not facility reporting would
be as effective as other means of
obtaining emissions data. For some
sources, our understanding of emissions
is limited by lack of knowledge of
source-specific factors. In instances
where facility-specific calculations are
PO 00000
Frm 00019
Fmt 4701
Sfmt 4702
16465
feasible and result in sufficiently
accurate and consistent estimates,
facility-level reporting would improve
current inventory estimates and EPA’s
understanding of the types and levels of
emissions coming from large facilities,
particularly in the industrial sector.
These source categories have been
included in the proposal. For other
source categories, uncertainty about
emissions is related more to the
unavailability of emission factors or
simple models to estimate emissions
accurately and at a reasonable cost at
the facility-level. Under this criterion,
we would require facility-level reporting
only if reporting would provide more
accurate estimates than can be obtained
by other means, such as national or
regional-level modeling. For an
example, please refer to the discussion
below on emissions from agricultural
sources and other land uses.
As the Agency completed its four step
evaluation of source categories to
include in the proposal, some source
categories were excluded from
consideration and some were added.
The reasons for the additions and
deletions are explained below. In
general, the proposed reporting rule
covers almost all of the source
categories in the Inventory of U.S.
Greenhouse Gas Emissions and Sinks
and the 2006 IPCC Guidelines for
National Greenhouse Gas Inventories.
Reporting by direct emitters.
Consistent with the appropriations
language regarding reporting of
emissions from ‘‘downstream sources,’’
EPA is proposing reporting
requirements from facilities that directly
emit GHGs above a certain threshold as
a result of combustion of fuel or
processes. The majority of the direct
emitters included in this proposal are
large facilities in the electricity
generation or industrial sectors. In
addition, many of the electricity
generation facilities are already
reporting their CO2 emissions to EPA
under existing regulations. As such,
these facilities have only a minimal
increase in the amount of data they have
to provide EPA on their CH4 and N2O
emissions. The typical industrial
facilities that are required to report
under this proposal have emissions that
are substantially higher than the
proposed thresholds and are already
doing many of the measurements and
quantifications of emissions required by
this proposal through existing business
practices, voluntary programs, or
mandatory State-level GHG reporting
programs.
For more information about the
thresholds included in this proposal
please refer to Section IV.C of this
E:\FR\FM\10APP2.SGM
10APP2
16466
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
preamble and for more information
about the requirements for specific
sources refer to Section V of this
preamble.
Reporting by fuel and industrial GHG
suppliers. 45 Consistent with the
appropriations language regarding
reporting of emissions from ‘‘upstream
production,’’ EPA is proposing reporting
requirements from upstream suppliers
of fossil fuel and industrial GHGs. In the
context of GHG reporting, ‘‘upstream
emissions’’ refers to the GHG emissions
potential of a quantity of industrial gas
or fossil fuel supplied into the economy.
For fossil fuels, the emissions potential
is the amount of CO2 that would be
produced from complete combustion or
oxidation of the carbon in the fuel. In
many cases, the fossil fuels and
industrial GHGs supplied by producers
and importers are used and ultimately
emitted by a large number of small
sources, particularly in the commercial
and residential sectors (e.g., HFCs
emitted from home A/C units or GHG
emissions from individual motor
vehicles).46 To cover these direct
emissions would require reporting by
hundreds or thousands of small
facilities. To avoid this impact, the
proposed rule does not include all of
those emitters, but instead requires
reporting by the suppliers of industrial
gases and suppliers of fossil fuels.
Because the GHGs in these products are
almost always fully emitted during use,
reporting these supply data would
provide an accurate estimate of national
emissions while substantially reducing
the number of reporters.47 For this
reason, the proposed rule requires
reporting by suppliers of coal and coalbased products, petroleum products,
natural gas and NGLs, CO2 gas, and
other industrial GHGs. We are not
proposing to require reporting by
suppliers of biomass-based fuels, or
renewable fuels, due to the fact that
GHGs emitted upon combustion of these
fuels are traditionally taken into account
at the point of biomass production.
However, we seek comment on this
approach and note that producers of
some biomass-based fuels (e.g., ethanol)
would be subject to reporting
requirements for their on-site emissions
45 In this context, suppliers include producers,
importers, and exporters of fossil fuels and
industrial GHGs.
46 While EPA is not proposing any reporting
requirements in this rule for operators of mobile
source fleets, we are requesting comment in Section
V.QQ.4.b of the Preamble.
47 As an example of estimating the CO emissions
2
that result from the combustion of fossil fuels,
please see, 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, Volume 2—Energy,
Chapter 1—Introduction (https://www.ipccnggip.iges.or.jp/public/2006gl/).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
under this proposal, similar to other fuel
producers. For more information about
these source categories please see the
source-specific discussions in Section V
of this preamble.
There is inherent double-reporting of
emissions in a program that includes
both upstream and downstream sources.
For example, coal mines would report
CO2 emissions that would be produced
from combustion of the coal supplied
into the economy, and the receiving
power plants are already reporting CO2
emissions to EPA from burning the coal
to generate electricity. This doublereporting is nevertheless consistent with
the appropriations language, and
provides valuable information to EPA
and stakeholders in the development of
climate change policy and programs.
Policies such as low-carbon fuel
standards can only be applied upstream,
whereas end-use emission standards can
only be applied downstream. Data from
upstream and downstream sources
would be necessary to formulate and
assess the impacts of such potential
policies. EPA recognizes the doublereporting and as discussed in Section
I.D of this preamble does not intend to
use the upstream and downstream
emissions data as a replacement for the
national emissions estimates found in
the Inventory.
It is possible to construct a reporting
system with no double-reporting. For
example, such a system could include
fossil fuel combustion-related emissions
upstream only, based on the fuel
suppliers, supplemented by emissions
reported downstream for industrial
processes at select industries (e.g., CO2
process emissions from the production
of cement); fugitive emissions from coal,
oil, and gas operations; biological
processes and mobile source
manufacturers. Industrial GHG
suppliers could be captured completely
upstream, thereby removing reporting
obligations from the use of the
industrial gases by large downstream
users (e.g., magnesium production and
SF6 in electric power systems). Under
this option, the total number of facilities
affected is approximately 32% lower
than the proposed option, and the
private sector costs are approximately
26% lower than the proposed option.
The emissions coverage remains largely
the same as the proposed option
although it is important to note that
some process related emissions may not
be captured due to the fact that
downstream combustion sources would
not be covered under this option. A
source with process emission plus
combustion emissions would only have
to report their process emission, thus
the exclusion of downstream
PO 00000
Frm 00020
Fmt 4701
Sfmt 4702
combustion could result in some
sources being under the threshold. For
more information about this analysis
and the differences in the number of
reporters and coverage of emissions,
please see the RIA (EPA–HQ–OAR–
2008–0508–002).
Emissions from agricultural sources
and other land uses. The proposed rule
does not require reporting of GHG
emissions from enteric fermentation,
rice cultivation, field burning of
agricultural residues, composting (other
than as part of a manure management
system), agricultural soil management,
or other land uses and land-use changes,
such as emissions associated with
deforestation, and carbon storage in
living biomass or harvested wood
products. As discussed in Section V of
this preamble, the proposal does
include reporting of emissions from
manure management systems.
EPA reports on the GHG emissions
and sinks associated with agricultural
and land-use sources in the Inventory of
U.S. Greenhouse Gas Emissions and
Sinks. In the agriculture sector, the U.S.
GHG inventory report estimated that
agricultural soil management, which
includes fertilizer application
(including synthetic and manure
fertilizers, etc.), contributed N2O
emissions of 265 million metric tons
CO2e in 2006 and enteric fermentation
contributed CH4 emissions of 126
million metric tons CO2e in 2006. These
amounts reflect 3.8 percent and 1.8
percent of total GHG emissions from
anthropogenic sources in 2006. Rice
cultivation, agricultural field burning,
and composting (other than as part of a
manure management system)
contributed emissions of 5.9, 1.2, and
3.3 million metric tons CO2e,
respectively in 2006. Total carbon
fluxes, rather than specific emissions
from deforestation, for U.S. forestlands
and other land uses and land-use
changes were also reported in the U.S.
GHG inventory report.
The challenges to including these
direct emission source categories in the
rule are that practical reporting methods
to estimate facility-level emissions for
these sources can be difficult to
implement and can yield uncertain
results. For more information on
uncertainty for these sources, please
refer to the TSD for Biological Process
Sources Excluded from this Rule (EPA–
HQ–OAR–2008–0508–045).
Furthermore, these sources are
characterized by a large number of small
emitters. In light of these challenges, we
have determined that it is impractical to
require reporting of emissions from
these sources in the proposed rule at
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
this time for the reasons explained
below.
For these sources, currently, there are
no direct greenhouse gas emission
measurement methods available except
for research methods that are
prohibitively expensive and require
sophisticated equipment. Instead,
limited modeling-based methods have
been developed for voluntary GHG
reporting protocols which use general
emission factors, and large-scale models
have been developed to produce
comprehensive national-level emissions
estimates, such as those reported in the
U.S. GHG inventory report.
To calculate emissions using emission
factor or carbon stock change
approaches, it would be necessary for
landowners to report on management
practices, and a variety of data inputs.
Activity data collection and emission
factor development necessary for
emissions calculations at the scale of
individual reporters can be complex and
costly.
For example, for calculating
emissions of N2O from agricultural soils,
data on nitrogen inputs necessary for
accurate emissions calculations include:
Synthetic fertilizer, organic
amendments (manure and sludge),
waste from grazing animals, crop
residues, and mineralization of soil
organic matter. While some activity data
can be collected with reasonable
certainty, the emissions estimates could
still have a high degree of uncertainty
because the emission factors available
for individual reporters do not reflect
the variety of conditions (e.g., soil type,
moisture) that need to be considered for
accurate estimates.
Without reasonably accurate facilitylevel emissions factors and the ability to
accurately measure all facility-level
calculation variables at a reasonable cost
to reporters, facility-level emissions
reporting would not improve our
knowledge of GHG emissions relative to
national or regional-level emissions
models and data available from national
databases. While a systematic
measurement program of these sources
could improve understanding of the
environmental factors and management
practices that influence emissions, this
type of measurement program is
technically difficult and expensive to
implement, and would be better
accomplished through an empirical
research program that establishes and
maintains rigorous measurements over
time.
Despite the issues associated with
reporting by the agriculture and land
use sectors, threshold analyses were
conducted for several source categories
within these sectors as part of their
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
consideration for inclusion in this rule.
For some agricultural source categories,
the number of individual farms covered
at various thresholds was estimated.
The resulting analyses showed that for
most of these sources no facilities would
exceed any of the thresholds evaluated.
Because facility-level reporting is
impracticable, the proposed rule
contains other provisions to improve
our understanding of emissions from
these source categories. For example,
agricultural soil management is a
significant source of N2O. Activity data,
including synthetic nitrogen-based
fertilizer applications, influence N2O
emissions from this agricultural source
category. To gain additional information
on synthetic nitrogen-based fertilizers,
EPA is proposing that the industrial
facilities reporting under this rule
include information on the production
and nitrogen content of fertilizers as
part of their annual reports to EPA. It is
estimated that all of the synthetic
nitrogen-based fertilizer produced in the
U.S. is manufactured by industrial
facilities that are covered under this rule
due to onsite combustion-related and
industrial process emissions (e.g.,
ammonia manufacturing facilities). The
reporting requirements are contained in
proposed 40 CFR part 98, subpart A.
EPA is requesting comment on this
approach. In particular, the Agency is
looking for information on the
usefulness of the fertilizer data for
estimating N2O emissions from
agricultural soils, and also on including
other possible reporters of synthetic
nitrogen-based fertilizers, such as
fertilizer wholesalers or distributors, or
importers in order to develop a better
understanding of the source of N2O
emissions from fertilizer use.
For additional background
information on emissions from
agricultural sources and other land use,
please refer to the TSD for Biological
Process Sources Excluded from this
Rule (EPA–HQ–OAR–2008–0508–045).
C. Rationale for Selection of Thresholds
The proposed rule would establish
reporting thresholds at the facility
level.48 49 50 Only those facilities that
48 Facilities reporting under this rule will likely
have more than one source category within their
facility (e.g., a petroleum refinery would have to
report on its refinery process, combustion, landfill
and wastewater emissions).
49 For the purposes of this rule, facility means any
physical property, plant, building, structure, source,
or stationary equipment located on one or more
contiguous or adjacent properties in actual physical
contact or separated solely by a public roadway or
other public right-of-way and under common
ownership or common control, that emits or may
emit any greenhouse gas. Operators of military
installations may classify such installations as more
PO 00000
Frm 00021
Fmt 4701
Sfmt 4702
16467
exceed a threshold as specified in
proposed 40 CFR part 98, subpart A
would be required to submit annual
GHG reports.
The thresholds are expressed in
several ways (e.g., actual emissions or
capacity). The use of these different
types of thresholds is discussed later in
this section, but most correspond to an
annual facility-wide emission level of
25,000 metric tons of CO2e, and the
thresholds result in covering
approximately 85–90 percent of U.S.
emissions. That level is largely
consistent with many of the existing
GHG reporting programs, including
California, which also has a 25,000
metric ton of CO2e threshold.
Furthermore, many industry
stakeholders that EPA met with
expressed support for a 25,000 metric
ton of CO2e threshold because it
sufficiently captures the majority of
GHG emissions in the U.S., while
excluding smaller facilities and
sources.51 The three exceptions to the
25,000 metric ton of CO2e threshold are
electricity production at selected units
subject to existing Federal programs,
fugitive emissions from coal mining,
and emissions from mobile sources.
These thresholds were selected to be
consistent with existing thresholds for
reporting similar data to EPA and the
MSHA. The proposed thresholds
maximized the rule coverage with over
85 percent of U.S. emissions reported by
approximately 13,000 reporters, while
keeping reporting burden to a minimum
and excluding small emitters.
Consideration of alternative emissions
thresholds. In selecting the proposed
threshold level, we considered two
lower emission threshold alternatives
and one higher alternative. We collected
available data on each industry and
analyzed the implication of various
thresholds in terms of number of
facilities and level of emissions covered
at both the industry level and the
national level. We also performed a
similar analysis for each proposed
source category to determine if there
were reasons to develop a different
threshold in specific industry sectors.
From these analyses, we concluded that
a 25,000 metric ton threshold suited the
needs of the reporting program by
providing comprehensive coverage of
than a single facility based on distinct and
independent functional groupings within
contiguous military properties.
50 A different threshold approach is proposed for
vehicle and engine manufacturers (when reporting
emissions from the vehicles and engines the
produce). Here, EPA proposes to exempt small
businesses from reporting requirements, instead of
applying an emission-based threshold.
51 To view a summary of EPA’s outreach efforts
please refer to EPA–HQ–OAR–2008–0508–055.
E:\FR\FM\10APP2.SGM
10APP2
16468
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
emissions with a reasonable number of
reporters and that having a uniform
threshold was an equitable approach.
This conclusion took into account our
finding that a threshold other than
25,000 metric tons of CO2e might appear
to achieve an appropriate balance
between number of facilities and
emissions covered for a limited number
of source categories. Our conclusions
about the alternative thresholds are
summarized below and in the
Thresholds TSD (EPA–HQ–OAR–2008–
0508–046), and the considerations for
individual source categories are
explained in Section V of this preamble.
The lower threshold alternatives that
we considered were 1,000 metric tons of
CO2e per year, and 10,000 metric tons
of CO2e per year. Both broaden national
emissions coverage but do so by
disproportionately increasing the
number of affected facilities (e.g.,
increasing the number of reporters by an
order of magnitude in the case of a 1,000
metric tons CO2e/yr threshold and
doubling the number of reporters in the
case of a 10,000 metric tons CO2e/yr
threshold). The majority of stakeholders
were opposed to these lower thresholds
for that reason—the gains in emissions
coverage are not adequately balanced
against the increased number of affected
facilities.
A 1,000 metric ton of CO2e per year
threshold would increase the number of
affected facilities by an order of
magnitude over the proposed threshold.
The effect of a 1,000 metric ton
threshold would be to change the focus
of the program from large to small
emitters. This threshold would impose
reporting costs on tens of thousands of
small businesses that in total would
amount to less than 10 percent of
national GHG emissions.
A 10,000 metric ton of CO2e per year
threshold approximately doubles the
number of facilities affected compared
to a 25,000 metric ton threshold. The
effect of a 10,000 metric ton threshold
would only improve national emissions
coverage by approximately 1 percent.
The extra data that would result from a
10,000 metric ton threshold would do
little to further the objectives of the
program. EPA believes the 25,000 metric
ton threshold more effectively targets
large industrial emitters, which are
responsible for some 90 percent of U.S.
emissions. Similarly, California’s
mandatory GHG reporting program also
based their selection of a 25,000 metric
ton threshold on similar results at the
State level.52
52 For more information on CA analysis please see
https://www.arb.ca.gov/regact/2007/ghg2007/
isor.pdf.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
We also considered 100,000 metric
tons of CO2e per year as an alternative
threshold but concluded that it fails to
satisfy two key objectives. First, it may
exclude enough emitters in certain
source categories such that the
emissions data would not adequately
cover key sectors of the economy. At
100,000 metric tons CO2e per year,
reporting for several large industry
sectors would be rather significantly
fragmented, resulting in an incomplete
picture of direct emissions from that
sector. For example, at a 100,000 metric
ton of CO2e threshold in ammonia
manufacturing, approximately 22 out of
24 facilities would have to report; in
nitric acid production, approximately
40 out of 45 facilities would have to
report; in lime manufacturing, 52 out of
89 facilities would have to report; and
in pulp and paper, 410 out of 425
facilities would have to report. Several
stakeholders we met with stressed this
potential fragmentation as a concern
and requested that EPA include all
facilities in a particular sector to
simplify compliance, even if there was
some uncertainty about whether all
facilities in an industry would
technically meet a particular threshold.
For more information about the impact
of thresholds on different industries,
please see the source-specific discussion
in Section V of this preamble.
The data collected by this rulemaking
is intended to support analyses of future
policy options. Those options may
depend on harmonization with State or
even international reporting programs.
Several States and regional GHG
programs are using thresholds that are
comparable in scope to a 25,000 metric
ton of CO2e per year threshold.53 As
noted earlier, California specifically
chose a threshold of 25,000 metric ton
of CO2e after analyzing CO2 data from
the air quality management districts
because they concluded that level
provided the correct balance of
emissions coverage and number of
reporters. Implementing a national
reporting program using a 100,000,
10,000 or 1,000 metric ton of CO2e per
year limit would result in a fragmentary
dataset insufficient in detail or coverage,
or a more burdensome reporting
requirement, and these options would
be inconsistent with what many other
GHG programs are requiring today.
In addition to the typical emissions
thresholds associated with GHG
reporting and reduction programs (e.g.,
53 For more information about what different
States are requiring, see section II of this preamble,
the ‘‘Summary of Existing State GHG Rules’’
memorandum and ‘‘Review of Existing Programs’’
memorandum found at EPA–HQ–OAR–2008–0508–
056 and 054.
PO 00000
Frm 00022
Fmt 4701
Sfmt 4702
25,000 metric tons CO2e), under the
CAA, there are (1) the Title V program
that requires all major stationary
sources, including all sources that emit
or have the potential to emit over 100
tons per year of an air pollutant, to hold
an operating permit 54 and (2) the PSD/
NSR program that requires new major
sources and sources that are undergoing
major modifications to obtain a permit.
A major source for PSD is defined as
any source that emits or has the
potential to emit either 100 or 250 tons
per year of a regulated pollutant,
dependent on the source category.55 In
nonattainment areas, the major source
threshold for NSR is at most 100 tons
per year, and is less in some areas
depending on the pollutant and the
nonattainment classification of the area.
EPA performed some preliminary
analyses to generally estimate the
existing stock of major sources in order
to then estimate the approximate
number of new facilities that could be
required to obtain NSR/PSD permits.56
For example, if the 100 and 250 tons per
year thresholds were applied in the
context of GHGs, the Agency estimates
the number of PSD permits required to
be issued each year would increase by
more than a factor of 10 (i.e., more than
2,000 to 3,000 permits per year). The
additional permits would generally be
issued to smaller industrial sources, as
well as large office and residential
buildings, hotels, large retail
establishments, and similar facilities.
For more information about the affect
of thresholds considered for this rule on
the number of reporters, emissions
coverage and costs, please see Table
VIII–2 in Section VIII of this preamble
and Table IV–47 of the RIA found at
EPA–HQ–OAR–2008–0508–002.
Determining applicability to the rule.
The thresholds listed in proposed 40
CFR part 98, subpart A fall into three
groups: Capacity, emissions, or ‘‘all in.’’
The thresholds developed are generally
equivalent to a threshold of 25,000
metric tons of CO2e per year of actual
emissions.
EPA carefully examined thresholds
and source categories that might be able
54 Other sources required to obtain Title V
operating permits include all sources that are
required to have PSD permits, ‘‘affected sources’’
under the ARP, and sources subject to NSPS or
NESHAP (although non-major sources under those
programs can be exempted by rule).
55 The 100 tons per year level is the level at which
existing sources in 28 industry categories listed in
the CAA are classified as major sources for the PSD
program. The 250 tons per year level is the level
at which existing sources in all other categories are
classified as major sources for PSD purposes.
56 For more information about the major source
analysis please see docket number EPA–HQ–OAR–
2008–0318.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
to report utilizing a capacity metric, for
example, tons of product produced per
year. A capacity-based threshold could
be the least burdensome alternative for
reporting because a facility would not
have to estimate emissions to determine
if the rule applies. However, EPA faced
two key challenges in trying to develop
capacity thresholds. First, in most cases
we did not have sufficient data to
determine an appropriate capacity
threshold. Secondly, for some source
categories defining the appropriate
capacity metric was not feasible. For
example, for some source categories,
GHG emissions are not related to
production capacity, but are more
affected by design and operating factors.
The scope of the proposed emission
threshold is emissions from all
applicable source categories located
within the physical boundary of a
facility. To determine emissions to
compare to the threshold, a facility that
directly emits GHGs would estimate
total emissions from all source
categories for which emission
estimation methods are provided in
proposed 40 CFR part 98, subparts C
through JJ. The use of total emissions is
necessary because some facilities are
comprised of multiple process units or
collocated source categories that
individually may not be large emitters,
but that emit significant levels of GHGs
collectively. The calculation of total
emissions for the purposes of
determining whether a facility exceeds
the threshold should not include
biogenic CO2 emissions (e.g., those
resulting from combustion of biofuels).
Therefore, these emissions, while
accounted for and reported separately,
are not considered in a facility’s
emissions totals.
In order to ensure that the reporting
of GHG emissions from all source
categories within a facility’s boundaries
is not unduly burdensome, EPA has
proposed flexibility in two ways. First,
a facility would only have to report on
the source categories for which there are
methods provided in this rule. EPA has
proposed methods only for source
categories that typically contribute a
relatively significant amount to a
facility’s total GHG emissions (e.g., EPA
has not provided a method for a facility
to account for the CH4 emissions from
coal piles). Second, for small facilities,
EPA has proposed simplified emission
estimation methods where feasible (e.g.,
stationary combustion equipment under
a certain rating can use a simplified
mass balance approach as opposed to
more rigorous direct monitoring).
The proposed emissions threshold is
based on actual emissions, with a few
exceptions described below. An actual
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
emission metric accounts for actual
operating practices at each facility. A
threshold based on potential emissions
would bring in far more facilities
including many small emitters. For
example, under a potential emissions
threshold, a facility that operates one
shift a day would have to estimate
emissions assuming three shifts per day,
and would have to assume continuous
use of feedstocks or fuels that result in
the highest rate of GHG emissions
absent enforceable limitations. Such an
approach would be inconsistent with
the twin goals of collecting accurate
data on actual GHG emissions to the
atmosphere and excluding small
emitters from the rule. However, we
note that emissions thresholds in some
CAA rules are based on actual or
potential emissions. Moreover, although
actual emissions may change year to
year due to fluctuations in the market
and other factors, potential emissions
are less subject to yearly fluctuations.
We solicit comment on how
considerations of actual and potential
emissions should be incorporated into
the proposed threshold.
There is one source category that has
a proposed threshold based on GHG
generation instead of emissions—
municipal landfills. In this case, a GHG
generation threshold is more
appropriate because some landfills have
installed CH4 gas recovery systems. A
gas recovery system collects a
percentage of the generated CH4, and
destroys it, through flaring or use in
energy recovery equipment. The use of
a threshold based on GHG generation
prior to recovery is proposed because it
ensures reporting from landfills that
have similar CH4 emission generating
activities (e.g., ensures that landfills of
similar size and management practices
are reporting).
As described in Section III of this
preamble, in the case of 19 source
categories all of the facilities that have
that particular source category within
their boundaries would be subject to the
proposed rule. For these facilities, our
analysis indicated that all facilities with
that source category emit more than
25,000 metric tons of CO2e per year or
that only a few facilities emit marginally
below this level. These source categories
include large manufacturing operations
such as petroleum refineries and cement
production. This simplifies the
applicability determination for facilities
with these source categories.
When determining if a facility passes
a relevant applicability threshold, direct
emissions from the source categories
would be assessed separately from the
emissions from the supplier categories.
For example, a company that produces
PO 00000
Frm 00023
Fmt 4701
Sfmt 4702
16469
and supplies coal would be subject to
reporting as a supplier of coal (40 CFR
part 98, subpart KK), because coal
suppliers is an ‘‘all in’’ supplier
category. But the company would
separately evaluate whether or not
emissions from their underground coal
mines (40 CFR part 98, subpart FF)
would also be reported.
In addition, the source categories
listed in proposed 40 CFR 98.2(a)(1) and
(2) and the supply operations listed in
proposed 40 CFR 98.2(a)(4) represent
EPA’s best estimate of the large emitters
of GHGs or large suppliers of fuel and
industrial GHGs. In order to ensure that
all large emitters are included in this
reporting program, proposed 40 CFR
98.2(a)(3) also covers any facility that
emits more than 25,000 metric tons of
CO2e per year from stationary fuel
combustion units at source categories
that are not listed in proposed 40 CFR
98.2(a)(2). To minimize the reporting
burden, such facilities would be
required to submit an annual report that
covers stationary combustion emissions.
Furthermore, we recognize that a
potentially large number of facilities
would need to calculate their emissions
in order to determine whether or not
they had to report under proposed 40
CFR 98.2(a)(3). Therefore, to further
minimize the burden on those facilities,
we are proposing that any facility that
has an aggregate maximum rated heat
input capacity of the stationary fuel
combustion units less than 30 mmBtu/
hr may presume it has emissions below
the threshold. According to our
analysis, a facility with stationary
combustion units that have a maximum
rated heat input capacity of less that 30
mmBtu/hr, operating full time (e.g.,
8,760 hours per year) with all types of
fossil fuel would not exceed 25,000
metric tons CO2e/yr (EPA–HQ–OAR–
2008–0508–049). Under this approach,
we estimate that approximately 30,000
facilities would have to assess whether
or not they had to report according to
proposed 40 CFR 98.2(a)(3).57 Of the
30,000, approximately 13,000 facilities
would likely meet the threshold and
have to report. Therefore, an additional
17,000 facilities may have to assess their
applicability but potentially not meet
the threshold for reporting. We
concluded that is a reasonable number
of assessments in order to ensure all
57 This estimate is based on the Energy and
Environmental Analysis, ‘‘Characterization of the
U.S. Industrial/Commercial Boiler Population’’
(2005) (EPA–HQ–OAR–2008–0508–050). We
assumed 3 boilers per manufacturing facility and 1
boiler per commercial facility. For additional
information on the impact to these 30,000 facilities,
please see the ICR and RIA (EPA–HQ–OAR–2008–
0508–002).
E:\FR\FM\10APP2.SGM
10APP2
16470
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
large emitters in the U.S. are included
in this reporting program. We are
seeking comment on (1) whether the
presumption for maximum rated heat
input capacity of 30 mmBtu/hr is
appropriate, (2) whether a different
(lower or higher) mmBtu/hr capacity
presumption should be set and (3)
whether other capacity thresholds
should be developed for different types
of facilities. The comments should
contain data and analysis to support the
use of different thresholds.
We are proposing that once a facility
is subject to this reporting rule, it would
continue to submit annual reports even
if it falls below the reporting thresholds
in future years. (As discussed in section
IV.K. of this preamble, EPA is proposing
that this rule require the submission of
data into the foreseeable future,
although EPA is soliciting comment on
other options.) The purpose of the
thresholds is to exclude small sources
from reporting. For sources that trigger
the thresholds, it is important for the
purpose of policy analysis to be able to
track trends in emissions and
understand factors that influence
emission levels. The data would be most
useful if the population of reporting
sources is consistent, complete and not
varying over time.
The one exception to the proposed
requirement to continue submitting
reports even if a facility falls below the
reporting threshold is active
underground coal mines. When coal is
no longer produced at a mine, the mine
often becomes abandoned. As discussed
in Section V.FF of this preamble, we are
proposing to exclude abandoned coal
mines from the proposed rule, and
therefore methods are not proposed for
this source category.
We recognize that in some cases, this
provision of ‘‘once in, always in’’ could
potentially act as a disincentive for
some facilities to reduce their emissions
because under this proposal those
facilities that did lower their emissions
below the treshold would have to
continue to report. To address this issue
in California, CARB’s mandatory
reporting rule offers a facility that has
emissions under the threshold for three
consecutive years the opportunity to be
exempt from the reporting program. We
request comment on whether EPA
should develop a similar process for this
reporting program. Comments should
include specifics on how the exemption
process could work, e.g., the number of
years a facility is under the threshold
before they could be exempt, the
quantity of emissions reductions
required before a facility could be
exempt, whether a facility should
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
formally apply to EPA for an exemption
or if it is automatic, etc.
EPA requests comment on the need
for developing simplified emissions
calculation tools for certain source
categories to assist potential reporters in
determining applicability. These
simplified calculation tools would
provide conservatively high emission
estimates as an aid in identifying
facilities that could be subject to the
rule. Actual facility applicability would
be determined using the methods
presented for each source category in
the rule.
For additional information about the
threshold analysis EPA conducted see
the Thresholds TSD (EPA–HQ–OAR–
2008–0508–046) and the individual
source category discussions in Section V
of this preamble. In addition, Section
V.QQ of this preamble describes the
threshold for vehicle and engine
manufacturers, which is a different
approach from what is described in this
section.
D. Rationale for Selection of Level of
Reporting
EPA is proposing facility-level
reporting for most source categories
under this program. Specifically, the
owner or operator of a facility would be
required to report its GHG emissions
from all source categories for which
there are methods developed and listed
in this proposal. For example, a
petroleum refinery would have to report
its emissions resulting from stationary
combustion, production processes, and
any fugitive or biological emissions.
Facility-level reporting by owners or
operators is consistent with other CAA
or State-level regulatory programs that
typically require facility or unit level
data and compliance (e.g., ARP, NSPS,
RGGI, and the California and New
Mexico mandatory GHG reporting
rules). This approach allows flexibility
for firms to determine whether the
owner or operator of the facility would
report and avoid the challenges of
establishing complex reporting rules
based on equity or operational control.
In addition to reporting emissions at
the total facility level, the emissions
would also be broken out by source
category (e.g., a petroleum refinery
would separately identify its emissions
for refinery production processes,
wastewater, onsite landfills, and any
other source categories listed in
proposed 40 CFR part 98, subpart A that
are located onsite). This would enable
EPA to understand what types of
emission sources are being reported,
determine that the facility is reporting
for all required source categories, and
use the source-category specific
PO 00000
Frm 00024
Fmt 4701
Sfmt 4702
estimates for future policy development.
Within each source category, further
breakout of emissions by process or unit
may be specified. Information on
process or unit-level reporting and
associated rationale is contained in the
source category sections within Section
V of this preamble.
Although many voluntary programs
such as Climate Leaders or TCR have
corporate-level reporting systems, EPA
concluded that corporate-level reporting
is overly complex under a mandatory
system involving many reporters and
thus is not appropriate for this rule,
except where discussed below. Complex
ownership structures and the frequent
changes in ownership structure make it
difficult to establish accountability over
time and ensure consistent and uniform
data collection at the facility-level.
Because the best technical knowledge of
emitting processes and emission levels
exists at the facility level, this is where
responsibility for reporting should be
placed. Furthermore, the ability to
differentiate and track the level and type
of emissions by facility, unit or process,
is essential for development of certain
types of future policy (e.g., NSPS).
The only exception to facility level
reporting is for some supplier source
categories (e.g., importers of fuels and
industrial GHGs or manufacturers of
motor vehicles and engines). Importers
are not individual facilities in the
traditional sense of the word. The type
of information reported by motor
vehicle and engine manufacturers is an
extension of long-standing existing
reporting requirements (e.g., reporting of
criteria emissions rates from vehicle and
engine manufacturers) and as such does
not necessitate a change in reporting
level. The reporting level for these
source categories is specified in Section
V of this preamble.
E. Rationale for Selecting the Reporting
Year
EPA is proposing that the monitoring
and reporting requirements would start
on January 1, 2010.58 The first report to
EPA would be submitted by March 31,
2011, and would cover calendar year
2010. The year 2011 is therefore referred
to as the first reporting year, and
includes 2010 data (there is a discussion
later in this section that takes comment
on alternative approaches to the
reporting year). EPA is requesting
comment on whether or not we should
select an alternative reporting date that
58 The exception is for vehicle and engine
manufacturers when reporting emissions from the
vehicles and engines they produce. For these
sources, reporting requirements would apply
beginning with the 2011 model year.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
corresponds with the requirements of an
existing reporting system.
For existing facilities that meet the
applicability criteria in proposed 40
CFR part 98, subpart A, monitoring
would begin on January 1, 2010. For
new facilities that begin operation after
January 1, 2010, monitoring would
begin with the first month that the
facility is operating and end on
December 31 of that same calendar year
in which they start operating. Each
subsequent monitoring year would
begin on January 1 and end on
December 31 of each calendar year. EPA
is proposing that new facilities monitor
and report emissions for the first partial
year after they begin operating so that
EPA has as complete an inventory as
possible of GHG emissions for each
calendar year.
Due to the comprehensive reporting
and monitoring requirements in this
proposal, the Agency has concluded
that it is not appropriate to require
reporting of historical emissions data for
years before 2010. Compiling,
submitting, and verifying historical data
according to the methodologies
specified in this rule would create
additional burdens on both the affected
facilities and the Agency, and much of
the needed data might not be available.
Because Federal policy for GHG
emissions is still being developed, the
Agency’s focus is on collecting data of
known quality that is generated on a
consistent basis. Collecting historic
emissions data would introduce data of
unknown quality that would not be
comparable to the data reported under
the program for years 2011 and beyond.
The first year of monitoring for
existing facilities would begin on
January 1, 2010. This schedule would
give existing facilities lead time after the
date the rule is promulgated to prepare
for monitoring and reporting.
Preparation would include studying the
final rule, determining whether it
applies to the facility, identifying the
requirements with which the facility
must comply, and preparing to monitor
and collect the required data needed to
calculate and report GHG emissions.
A beginning date of January 1, 2010
would allow sufficient time to begin
monitoring and collecting data because
many of the parameters that would need
to be monitored under the proposed rule
are already monitored by facilities for
process management and accounting
reasons (e.g., feedstock input rates,
production output, fuel purchases). In
addition, the monitoring methods
specified by the rule are already wellknown and documented; and
monitoring devices required by the rule
are routinely available, in ready supply
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(e.g., flow meters, automatic data
recorders), and in some cases already
installed. These same monitoring
devices are already required by other air
quality programs with which many of
these same facilities are already
complying.
It is reasonable for new sources that
start operation after January 1, 2010, to
begin monitoring the first month of
operation because new sources would
be aware of the rule requirements when
they design the facility and its processes
and obtain permits. They can plan the
data collection and reporting processes
and install needed monitoring
equipment as they build the facility and
begin operating the monitoring
equipment when they begin operating
the facility.
We recognize that although the
Agency plans to issue the final rule in
sufficient time to begin monitoring on
January 1, 2010, we may be unable to
meet that goal. Therefore, we are
interested in receiving comments on
alternative effective dates, including the
following two options:
• Report 2010 data in 2011 using best
available data: Under this scenario, the
rule would be effective January 1, 2010,
allowing affected facilities to use either
the methods in proposed 40 CFR part 98
or best available data. As in the current
proposal, the report would be submitted
on March 31, 2011, and then full data
collection, using the methods in 40 CFR
part 98 would begin in 2011, with that
report sent to EPA on March 31, 2012.
Under this approach, EPA solicits
comment on the types of best available
data and methods that should be
allowed in 2010, by source category,
(e.g., fuel consumption, emissions by
process, default emissions factors, fuel
receipts, etc.) as well as additional basic
data that should be reported (e.g.,
facility name, location). This approach
is similar to the CARB mandatory
reporting rule, which allowed affected
facilities to report 2009 emissions in
2010 using best available data, and then
requires 2010 data collection in 2011
using the methods in the rule. The
advantages of this approach are that the
dates of the proposal remain intact and
EPA receives basic information,
including emissions and fuel data from
all affected facilities in 2011.
Furthermore, this approach can ease
facilities into the program by giving
them potentially a full year to
implement the required methods and
install any necessary equipment. For
example, this option encourages the use
of the methods in 40 CFR part 98 but if
that is not possible, it allows the use of
best available data (e.g., if a facility does
not have a required flow meter installed
PO 00000
Frm 00025
Fmt 4701
Sfmt 4702
16471
for 2010 they can substitute the data
from their fuel receipts in the
calculation). The disadvantage of this
approach is that it delays full data
collection using the methods in the rule
by 1 year from what is proposed.
Further, in some cases, this approach
could lead to data that is of lesser
quality than the data we would receive
using the methods in 40 CFR part 98. In
other cases, because sources are already
following the methods in 40 CFR part 98
(e.g., stationary combustion units in the
ARP), the quality of the data would
remain unchanged under this option.
Given the objective of this rule to collect
comprehensive and accurate data to
inform future policies and the interest
in Congress in developing climate
change legislation, any delay in
receiving that data could adversely
affect the ability to inform those
policies. That said, the data we would
receive in 2011 under this option would
at least provide basic information about
the types, locations, emissions and fuel
consumption from facilities in the
United States.
• Report 2011 data in 2012: Under
this scenario, the rule would require
that affected facilities begin collecting
data January 1, 2011 and submit the first
reports to EPA on March 31, 2012. The
methods in the proposed rule would
remain unchanged and the only
difference is that this option would
delay implementation of the rule by one
year. The advantages of this approach
are that affected facilities would have a
substantial amount of time to prepare
for this reporting rule, including
implementing the method and installing
equipment. In addition, we would have
even more time to conduct outreach and
guidance to affected facilities. The
disadvantages of this approach are that
it delays implementation of this rule by
a year and does not offer a mechanism
for EPA to receive crucial data, even
basic data, necessary to inform future
policy and regulatory development.
Furthermore, in some cases affected
facilities are already implementing the
methods required by proposed 40 CFR
part 98 (e.g., stationary combustion
units in the ARP) or are familiar with
the methods, and have all of the
necessary equipment or processes in
place to monitor emissions consistent
with the methods in 40 CFR part 98.
Therefore, delaying implementation by
a year not only deprives EPA of valuable
data to support future policy
development, but at the same time, does
not provide any real advantage to these
facilities.
Proposed 40 CFR part 98, subpart A,
specifies numerical reporting thresholds
for different direct emitters or supply
E:\FR\FM\10APP2.SGM
10APP2
16472
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
operations. A facility or supply
operation that exceeds any of these
reporting thresholds in 2010 would
submit a full emissions report in
reporting year 2011, which contains
calendar year 2010 data. The facilities
and supply operations that contain
many of the source categories that are
listed in 40 CFR part 98, subpart A are
larger facilities that have been
participating in a variety of mandatory
and voluntary GHG emissions programs.
Therefore, those facilities and supply
operations should be familiar with the
methods and able to comply with the
requirements and submit a full report
without significant burden.
As discussed earlier, if a facility does
not have any of the source categories
listed in proposed 40 CFR 98.2 (a)(1) or
(2), but has stationary combustion onsite
that exceeds the GHG reporting
threshold in 2010, they would still be
required to estimate GHG emissions in
2010 and report in 2011. However,
because those facilities would not
contain any of the source categories
specifically identified in proposed 40
CFR 98.2 (a)(1) or (2) and tend to be
smaller facilities in diverse industrial
sectors, they may require some extra
time to implement the requirements of
this rule. As such, they would be
allowed to use an abbreviated facility
report using simplified emission
estimation methods for the first year
(i.e., for calendar year 2010) and would
not be required to complete a full report
until the second reporting year (i.e.,
2012).
The abbreviated report would allow
the facility to use default fuel-specific
CO2 emission factors. They would not
be required to determine actual fuel
carbon content or to use a CEMS to
determine CO2 emissions, as they may
otherwise be required to do with a full
report. This provision for abbreviated
reporting requirements has been
proposed because there are potentially
many facilities that are not in the listed
industries, but are required to report
solely due to stationary combustion
sources at their facility. These include
numerous and diverse sources in a wide
variety of industries, some of which
may not be as familiar with GHG
monitoring and reporting. Such sources
may often need more time to determine
if they are above the threshold and
subject to the rule and, if they are, to
implement the full monitoring and
reporting systems required. Therefore,
the abbreviated report with simpler
estimating methodologies is being
proposed for these sources for the first
year of monitoring and reporting.
EPA proposes that the annual GHG
emissions reports would be submitted
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
no later than March 31 for the previous
calendar year’s reporting period. Three
months is a reasonable time to compile
and review the information needed for
the annual GHG emissions report and to
prepare and submit the report. The data
needed to estimate emissions and
compile the report would be collected
by the facility on an ongoing basis
throughout the year, so facilities could
begin data summary during the year as
the data are collected. For example, they
could compile needed GHG calculation
input data (e.g., fuel use or raw material
consumption data) or emission data on
a periodic basis (e.g., monthly or
quarterly) throughout the year and then
total it at the end of the year. Therefore,
only the most recently collected
information would need to be compiled
and a final set of calculations would
need to be performed before the final
report is assembled. Given the nature of
the methodologies contained in the rule,
three months is sufficient time to
calculate emissions, quality-assure,
certify, and submit the data.
F. Rationale for Selecting the Frequency
of Reporting
EPA is proposing that all affected
facilities would have to submit annual
GHG emission reports. Facilities with
ARP units that report CO2 emissions
data to EPA on a quarterly basis would
continue to submit quarterly reports as
required by 40 CFR part 75, in addition
to providing the annual GHG reports.
The annual CO2 mass emissions from
the ARP reports would simply be
converted to metric tons and included
in the GHG report. This approach
should not impose a significant burden
on ARP sources.
We have determined that annual
reporting is sufficient for policy
development. It is consistent with other
existing mandatory and voluntary GHG
reporting programs at the State and
Federal levels (e.g., TCR, several
individual State mandatory GHG
reporting rules, EPA voluntary
partnership programs, the DOE
voluntary GHG registry). However, as
future policies develop it may be
necessary to reconsider the reporting
frequency and require more or less
frequent reporting (e.g., quarterly or
every few years). For example, under
future programs or policy initiatives,
particularly if regulatory in nature (e.g.,
a cap-and-trade program similar to the
ARP) it may be more appropriate require
quarterly reporting.
PO 00000
Frm 00026
Fmt 4701
Sfmt 4702
G. Rationale for the Emissions
Information To Report
1. General Content of Reports
Generally, we propose that facilities
report emissions for all source
categories at the facility for which
methods have been defined in any
subpart of proposed 40 CFR part 98.
Facilities would report (1) total annual
GHG emissions in metric tons CO2e and
(2) separately present annual mass
emissions of each individual GHG for
each source category at the facility .59
Reporting of CO2e allows a comparison
of total GHG emissions across facilities
in varying categories which emit
different GHGs. Knowledge of both
individual gases emitted and total CO2e
emissions would be valuable for future
policy development and help EPA
quantify the relative contribution of
each gas to a source category’s
emissions, while maintaining the
transparency of reporting total mass of
individual gases released by facility,
unit, or process.
Emissions would be reported at the
level (facility, process, unit) at which
the emission calculation methods are
specified in each applicable subpart. For
example, if a pulp and paper mill has
three boilers and a wastewater treatment
operation, the facility would report
emissions for each boiler (according to
the methodologies presented in
proposed 40 CFR part 98, subpart C), the
wastewater treatment operation
(according to proposed 40 CFR part 98,
subpart II), and from chemical recovery
units, lime kilns, and makeup chemicals
(according to proposed 40 CFR part 98,
subpart AA). In addition, the report
would include summary information on
certain process operating data that
influence the level of emissions and that
are necessary to calculate GHG
emissions and verify those calculations
using the methodologies in the rule.
Examples of these data include fuel type
and amount, raw material inputs, or
production output. The specific process
information to report varies for each
source category and is specified in each
subpart.
Furthermore, in addition to any
specific requirements for reporting
emissions from electricity generation in
Sections V.C and V.D of this preamble,
EPA is proposing that all facilities and
supply operations affected by this rule
would also report the quantity of
electricity generated onsite. The
generation of onsite electricity can
59 Consistent with the IPCC, the CARB reporting
rule and the EU Emission Trading System, the
proposed rule requires units to separately report the
biogenic portion of their total annual CO2
emissions.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
represent a relatively significant fraction
of onsite fuel use. We seek comment on
whether this information would be
useful to support future climate policy
development, given the other data
related to GHG emissions from
electricity generation already collected
under other sections of this proposed
rule. At this point, we do not propose
separate reporting of the onsite
electricity generation by generation
source (e.g., combined heat and power
or renewable or fossil-based) due to the
burden on reporters, but we recognize
the potential value of being able to
discern the quantity of electricity being
generated from renewable and nonrenewable sources. We are seeking
comment on the value of collecting this
data; and if it is collected, whether there
is a need to separately report the
kilowatt-hours by type of generation
source.
We are also taking comment on, but
not proposing at this time, requiring
facilities and supply operations affected
by the proposed rule to also report the
quantity of electricity purchased. For
many industrial facilities, purchased
electricity represents a large part of
onsite energy consumption, and their
overall GHG emissions footprint when
taking into account the indirect
emissions from fossil fuel combusted for
the electricity generated. Together, the
reporting of electricity purchase data
and onsite generation could provide a
better understanding of how electricity
is used in the economy and the major
industry sectors.
Many existing reporting programs
require reporting of indirect emissions
(e.g., Climate Leaders, CARB, TCR, DOE
1605(b) program). In general, the
protocols for these programs follow the
methods developed by WRI/WBCSD for
the quantification and reporting of
indirect emissions from the purchase of
electricity. The WRI/WBCSD protocol
outlines three scopes to help delineate
direct and indirect emission sources,
with the stated goal to improve
transparency, and provide utility for
different types of organizations and
different types of climate policies and
business goals. Scope 1 includes direct
GHG emissions occurring from sources
that are owned or controlled by the
business. Scope 2 includes indirect
GHG emissions resulting from the
generation of purchased electricity,
heat, and/or steam. Scope 3 is optional
and includes other types of indirect
emissions (e.g., from production of
purchased materials, waste disposal or
employee transportation).
We are taking comment on, but not
proposing at this time, an approach that
would require the reporting of
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
electricity purchase data, and not
indirect emissions, because these data
are more readily available to all
facilities. Through the review of existing
reporting programs that require the
reporting of indirect emissions data it
was determined that there are multiple
ways proposed to calculate indirect
emissions from electricity purchases.
This reflects the challenge associated
with determining the specific fossil fuel
mix used to generate the electricity
consumed by a facility, and thus the
indirect emissions that should be
attributed to the facility. Although
indirect emissions data would not be
directly reported under this approach, it
would enable indirect emissions for
facilities to be calculated. This option
also would be the least burdensome to
reporting facilities since the data would
be easily available.
The information that is proposed to be
reported reflects the data that could
support analyses of GHG emissions for
future policy development and ensure
the data are accurate and comparable
across source categories. Besides total
facility emissions, it benefits
policymakers to understand: (1) The
specific sources of the emissions and
the amounts emitted by each unit/
process to effectively interpret the data,
and (2) the effect of different processes,
fuels, and feedstocks on emissions. This
level of reporting should not be overly
burdensome because many of these data
already are routinely monitored and
recorded by facilities for business
reasons. The remainder of the reported
data would need to be collected to
determine GHG emissions.
The report would contain a signed
certification from a representative
designated by the owner or operator of
a facility affected by this rule. This
‘‘Designated Representative’’ would act
as a legal representative between the
source and the Agency. The use of the
Designated Representative would
simplify the administration of the
program while ensuring the
accountability of an owner or operator
for emission reports and other
requirements of the mandatory GHG
reporting rule. The Designated
Representative would certify that data
submitted are complete, true, and
accurate. The Designated Representative
could appoint an alternate to act on
their behalf, but the Designated
Representative would maintain legal
responsibility for the submission of
complete, true, and accurate emissions
data and supplemental data.
Besides these general reporting
requirements, the specific reporting
requirements for each source category
are described in the methodological
PO 00000
Frm 00027
Fmt 4701
Sfmt 4702
16473
discussions in Section V of this
preamble.
2. De minimis Reporting for Minor
Emission Points
A number of existing GHG reporting
programs contain ‘‘de minimis’’
provisions. The goal of a de minimis
provision is to avoid imposing excessive
reporting costs on minor emission
points that can be burdensome or
infeasible to monitor. Existing GHG
reporting programs recognize that it may
not be possible or efficient to specify the
reporting methods for every source that
must be reported and, therefore, have
some type of provision to reduce the
burden for smaller emissions sources.
Depending on the program, the reporter
is allowed to either not report a subset
of emissions (e.g., 2 to 5 percent of
facility-level emissions) or use
simplified calculation methods for de
minimis sources.
We analyzed the de minimis
provisions of existing reporting rules
and concluded that there is no need to
exclude a percentage of emissions from
reporting under this proposal. EPA
recognizes the potential burden of
reporting emissions for smaller sources.
The proposal addresses this concern in
several ways. First, only those facilities
over the established thresholds would
be required to report. Smaller facilities
would not be subject to the program.
Second, for those facilities subject to the
rule, only emissions from those source
categories for which methods are
provided would be reported. Methods
are not proposed for what are typically
smaller sources of emissions (e.g., coal
piles on industrial sites). Third, because
some facilities subject to the rule could
still have some relatively small sources,
the proposal includes simplified
emissions estimation methods for
smaller sources, where appropriate. For
example, small stationary combustion
units could use a default emission factor
and heat rate to estimate emissions, and
no fuel measurements would be
required. Where simplified methods are
proposed, they are described in the
relevant discussions in Section V of this
preamble.
Our analysis showed that the GHG
reporting programs with de minimis
exclusions are structured differently
than our proposed rule. For example,
most rules with de minimis exclusions
require corporate level reporting of all
emission sources. Under these
programs, some corporations must
report emissions from numerous remote
facilities and must report emissions
from small onsite equipment (e.g., lawn
mowers). For these programs, a de
minimis exclusion avoids potentially
E:\FR\FM\10APP2.SGM
10APP2
16474
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
unreasonable reporting burdens. The
recent trend in these programs,
however, is to require full reporting of
all required GHG emissions, but allow
simplified calculation procedures for
small sources. In contrast to these other
reporting programs, today’s proposed
rule would affect only larger facilities,
would require reporting of significant
emission points only, and would
contain simplified reporting where
practicable. Accordingly, a de minimis
exclusion is not necessary. EPA requests
comment on whether this approach to
smaller sources of emissions is
appropriate or if we should include
some type of de minimis provision.
For additional information on the
treatment of de minimis in existing GHG
reporting programs, please refer to the
‘‘Reporting Methods for Small Emission
Points (De Minimis Reporting)’’ (EPA–
HQ–OAR–2008–0508–048).
3. Recalculation and Missing Data
Most voluntary and mandatory GHG
reporting programs include provisions
for operators to revise previously
submitted data. For example, some
voluntary programs require reporters to
revise their base year emissions
calculations if there is a significant
change in the boundary of a reporter, a
change in methodologies or input data,
a calculation error, or a combination of
the above that leads to a significant
change in emissions. Recalculation
procedures particularly appear to be
central in voluntary GHG reporting
programs that are also tracking
emissions reductions.
Moreover, some programs (e.g., ARP)
have detailed provisions for filling in
data gaps that are missing in the
required report. For example, in ARP,
these procedures apply when CEMS are
not functioning and as a result several
hours of the required hourly data are
missing. Note, however, that merely
filling in data gaps that are missing or
correcting calculation errors does not
relieve an operator from liability for
failure to properly calculate, monitor
and test as required.
For this mandatory GHG reporting
program, EPA concluded it was
important to have missing data
procedures in order to ensure there is a
complete report of emissions from a
particular facility. However, because
this program requires annual reporting
rather than quarterly reporting of hourly
data as in ARP, the missing data
provision often require the facility to
redo the test or calculation of emissions.
Section V of the preamble details the
missing data procedures for facilities
reporting to this program. EPA is
seeking comment on whether to include
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
a provision to require a minimum
standard for reported data (e.g., only 10
percent of the data reported can be
generated using missing data
procedures).
In addition to establishing procedures
for missing data, there may be benefit in
requiring previously submitted data to
be recalculated in order to ensure that
the GHG emissions reported by a facility
are as accurate as possible. The
proposed California mandatory GHG
reporting program, for example, allows
reporters to revise submitted emissions
data if errors are identified, subject to
approval by the program.
EPA is considering whether or not to
include provisions to require facilities
to correct previously submitted data
under certain circumstances. However,
these benefits must also be weighed
against the additional costs associated
with requiring reporters to recalculate
and resubmit previous data, and the
magnitude of the emissions changes
expected from such recalculations.
Moreover, even if EPA were to allow
recalculation of submitted data or
accept data submitted using missing
data procedures, that would not relieve
the reporter of their obligation to report
data that are complete, accurate and in
accordance with the requirements of
this rule. Although submitting
recalculated data or data using missing
data procedures would correct the data
that are wrong, that resubmission or
missing data procedures does not
necessarily reverse the potential rule
violation and would not relieve the
reporter of any penalties associated with
that violation. EPA is seeking comment
on whether the mandatory GHG
reporting program should include
provisions to require reporters to submit
recalculated data and under what
circumstances such recalculations
should be required.
H. Rationale for Monitoring
Requirements
In selecting the monitoring
requirements for the proposed rule,
EPA’s goal is to collect data of sufficient
accuracy and quality to be used to
inform future climate policy
development and support a range of
possible policies and regulations. Future
policies and regulations could range
from research and development
initiatives to regulatory programs (e.g. ,
cap-and-trade programs). Accurate and
timely information is critical to making
policy decisions and developing
programs. However, EPA recognizes that
methods that provide the most accurate
data may also entail higher data
collection costs. In selecting a general
monitoring approach, EPA considered
PO 00000
Frm 00028
Fmt 4701
Sfmt 4702
the relative accuracy and costs of
different approaches, the monitoring
methods already in use within the
regulated industries, and consistency
with the monitoring approaches
required by various Federal and State
mandatory and voluntary GHG reporting
programs. Measurement methods can
range from continuous direct emissions
measurements to simple calculation
methods that rely on default factors and
assumptions. EPA considered four
broad monitoring approaches for the
mandatory GHG rule. These general
approaches (options 1 through 4) and
the rationale for the selected approach
are described in this section. After a
general approach was selected, EPA
developed the specific proposed
monitoring methods for each source
category as described in Section V of
this preamble.
Option 1. Direct Emission
Measurement. Option 1 would require
direct measurement of GHGs for all
source categories where direct
measurement is feasible. It would
require installation of CEMS for CO2 in
the stacks from stationary combustion
units and industrial processes. The
approach would be similar to 40 CFR
part 75 that require coal-fired EGUs to
install, operate, and maintain CEMs for
SO2 and NOX emissions and report
hourly emissions data (although some
lower-emitting units have the option to
use fuel sampling and fuel flow rate
metering to determine emissions). Like
40 CFR part 75, the direct measurement
approach would have detailed
requirements for the CEMS including
stringent QA/QC requirements to
monitor accuracy and precision.
Direct measurement is not technically
feasible in all cases. For example, CEMS
are not available for many of the GHGs
that must be reported. Direct
measurement is also infeasible for
emissions that are not captured and
emitted through a stack, such as CH4
emissions from the surface of landfills
or fugitive emissions from selected oil
and natural gas operations. For sources
where direct measurement is not
technically feasible, this option would
require the use of rigorous methods with
a comparable level of accuracy to CEMS.
The direct measurement option has
the highest degree of certainty of the
data reported. It is also the most costly
because all facilities where direct
measurement is feasible would need to
install, operate, and maintain emission
monitors. Most facilities currently do
not have CEMS to measure GHG
emissions.
Option 2. Combination of Direct
Emission Measurement and FacilitySpecific Calculations. This option
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
would require direct measurement of
emissions from units at facilities that
already are required to collect and
report data using CEMS under other
Federally enforceable programs (e.g.,
ARP, NSPS, NESHAP, SIPs). In some
cases, this may require upgrading
existing CEMS that currently monitor
criteria pollutants to also monitor CO2.
Facilities that do not have units that
have CEMS installed would have the
choice to either directly measure
emissions or to use facility-specific GHG
calculation methods. The measurement
and calculation methods for each source
category would be specified in each
subpart. Depending on the source
category, methods could include mass
balance; measurement of the facility’s
use of fuels, raw materials, or additives
combined with site-specific measured
carbon content of these materials; or
other procedures that rely on facilityspecific data. For the supplier source
categories (e.g., those that supply fuels
or industrial GHGs), this option would
require reporting of production, import,
and export data. The supplier
companies already closely track these
data for financial and other reasons.
This option provides a relatively high
degree of certainty and takes advantage
of existing practices at facilities. This
option is less costly than option 1
because most facilities are not required
to install CEMS and can, in many cases,
make use of data they are already
collecting for other reasons.
Option 3. Simplified Calculation
Methods. Under option 3, facilities
would calculate emissions using simple
inputs (e.g., total annual production)
that are usually already measured for
other reasons, and EPA-supplied default
emission factors (many of which have
been developed by industry
consortiums, such as the World
Resources Institute/World Business
Council for Sustainable Development
(WRI/WBCSD) (Cement Sustainability
Initiative) Protocol). The default
emission factors would represent
national average factors. These methods
and emission factors would not take
into account facility-specific differences
in processes or in the composition of
raw materials, fuels, or products.
Under this option, the only facilities
that would have to use more rigorous
monitoring or site-specific calculations
methods are facilities that are already
required to report emissions under 40
CFR part 75. These facilities would
continue to follow the CO2 monitoring
and reporting requirements of 40 CFR
part 75.
Data collected under this option
would have a lower degree of certainty
than options 1 or 2. Furthermore, many
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
facilities are already calculating GHG
emissions to a higher degree of certainty
for business reasons or for other
mandatory or voluntary reporting
programs, and option 3 would not make
use of such available data. However, the
cost to facilities is lower than under
options 1 and 2.
Option 4. Reporter’s Choice of
Methods. Under this approach, reporters
would have flexibility to select any
measurement or calculation method and
any emission factors for determining
emissions. The rule would not prescribe
any methods or present any specific
options for determining emissions.
Data collected under this option
would not be comparable across a given
industry and across reporters subject to
the program, thereby minimizing the
usefulness of the data to support future
policymaking. Although some facilities
might choose to use direct measurement
because CEMS are already installed at
the facility, other facilities would select
default calculations. This option would
be the lowest cost to reporters.
Proposed Option. For the proposed
rule, EPA selected option 2
(combination of direct measurement and
facility-specific calculations) as the
general monitoring approach. This
option results in relatively high quality
data for use in developing climate
policies and supporting a wide range of
potential future policy options. Because
we do not yet know which specific
policy options the data may ultimately
be used to support, the reported GHG
emission estimates should have a
sufficient degree of certainty such that
they could be used to help develop a
potential variety of programs.
Option 2 strikes a balance between
data accuracy and cost. It makes use of
existing data and methodologies to the
extent feasible, and avoids the cost of
installing and operating CEMS at
numerous facilities. It is consistent with
the types of methods contained in other
GHG reporting programs (e.g., TCR,
California programs, Climate Leaders).
Because this option specifies methods
for each source category, it should result
in data that are comparable across
facilities.
Option 1 (direct emission
measurement) was not chosen because
the cost to the reporters if all facilities
had to install continuous emission
monitoring systems would be
unreasonably high in the absence of a
defined policy that would require this
type of monitoring. However, under the
selected option, facilities that already
use CEMS would still be required to use
them for purposes of the GHG reporting
rule.
PO 00000
Frm 00029
Fmt 4701
Sfmt 4702
16475
Option 3 (simplified calculation
methods) was not chosen because the
data would be less accurate than option
2 and would not make use of sitespecific data that many facilities already
have available and refined calculation
approaches that many facilities are
already using. Option 3 would also be
inconsistent with several other GHG
reporting programs such as TCR and
California programs that contain more
site-specific calculation methods for
several of the source categories.
Option 4 (reporter’s choice of
methods) was not proposed because the
accuracy and reliability of the reported
data would be unknown and would vary
from one reporter to the next. Because
consistent methods would not be used
under this option, the reported data
would not be comparable across similar
facilities. The lack of comparability
would undermine the use of the data to
support policy decisions.
EPA requests comments on the
selected monitoring approach and on
other potential options and their
advantages and disadvantages.
I. Rationale for Selecting the
Recordkeeping Requirements
EPA is proposing that each facility
that would be required to submit an
annual GHG report would also keep the
following records, in addition to any
records prescribed in each applicable
subpart:
• A list of all units, operations,
processes and activities for which GHG
emissions are calculated;
• The data used to calculate the GHG
emissions for each unit, operation,
process, and activity, categorized by fuel
or material type;
• Documentation of the process used
to collect the necessary data for the GHG
emissions calculations;
• The GHG emissions calculations
and methods used;
• All emission factors used for the
GHG emissions calculations;
• Any facility operating data or
process information used for the GHG
emissions calculations;
• Names and documentation of key
facility personnel involved in
calculating and reporting the GHG
emissions;
• The annual GHG emissions reports;
• A log book documenting any
procedural changes to the GHG
emissions accounting methods and any
changes to the instrumentation critical
to GHG emissions calculations;
• Missing data computations;
• A written QAPP;
• Any other data specified in any
applicable subpart of proposed 40 CFR
part 98. Examples of such data could
E:\FR\FM\10APP2.SGM
10APP2
16476
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
include the results of sampling and
analysis procedures required by the
subparts (e.g., fuel heat content, carbon
content of raw materials, and flow rate)
and other data used to calculate
emissions.
These data are needed to verify the
accuracy of reported GHG emission
calculations and, if needed, to
reproduce GHG emission estimates
using the methods prescribed in the
proposed rule. Since the above
information must be collected in order
to calculate GHG emissions, the added
burden of maintaining records of that
information should be minimal.
Each facility would be required to
retain all required records for at least 5
years. Records would be maintained for
this period so that a history of
compliance could be demonstrated and
questions about past emission estimates
could be resolved, if needed.
The records would be required to be
kept in an electronic or hard-copy
format (as appropriate) that is readily
accessible within a reasonable time for
onsite inspection and auditing. They
would be recorded in a form that can be
easily inspected and reviewed. The
allowance of a variety of electronic and
hard copy formats for records allows
flexibility for facilities to use a system
that meets their needs and is consistent
with other facility records maintenance
practices, thereby minimizing the
recordkeeping burden.
J. Rationale for Verification
Requirements
1. General Approach to Verification
Proposed in This Rule
GHG emissions reported under this
rule would be verified to ensure
accuracy and completeness so that EPA
and the public could be confident in
using the data for developing climate
policies and potential future
regulations. To ensure the completeness
and quality of data reported to the
program, the Agency proposes selfcertification with EPA verification.
Under this approach, all reporters
subject to this rule would certify that
the information they submit to EPA is
truthful, accurate and complete. EPA
would then review the emissions data
and supporting data submitted by
reporters to verify that the GHG
emission reports are complete, accurate,
and meet the reporting requirements of
this rule.
Given the scope of this rulemaking,
this approach is consistent with many
EPA regulatory programs. That said, this
proposal does not preclude that in the
future, as climate policies evolve, EPA
may consider third party verification for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
other programs (e.g., offsets).
Furthermore, many programs in the
States and Regions may be broader in
scope and the use of third party verifiers
may be appropriate to meet the needs of
those programs.
In addition, under the authorities of
CAA sections 114 and 208, EPA has the
authority to independently conduct site
visits to observe monitoring procedures,
review records, and verify compliance
with this rule (see Section VII of this
preamble for further information on
compliance and enforcement). For
vehicle and engine manufacturers, EPA
is not proposing additional verification
requirements beyond the current
emissions testing and certification
procedures. These procedures include
well-established methods for assuring
the completeness and quality of
reported emission test data and EPA is
proposing to include the new GHG
reporting requirements as part of these
methods.
2. Options Considered
In selecting this proposed approach to
verification, the Agency reviewed
verification requirements and
procedures under a number of existing
EPA regulatory programs, as well as
existing domestic and international
GHG reporting programs. Additional
information on this review and the
verification approaches can be found in
a technical memorandum (‘‘Review of
Verification Systems in Environmental
Reporting Programs,’’ EPA–HQ–OAR–
2008–0508–047). Based on this review,
EPA considered three alternative
approaches to verification: (1) Selfcertification without independent
verification, (2) self-certification with
third-party verification, and (3) selfcertification with EPA verification.
Option 1. Self-certification without
independent verification. Under this
option, the Designated Representative of
the reporting facility would be required
to sign and submit a certification
statement as part of each annual
emissions report. The certification
would affirm that the report has been
prepared in accordance with the
requirements of the GHG reporting rule,
and that the emissions data and other
information reported is true and
accurate to the best knowledge and
belief of the certifying official. The
reasons for requiring self-certification
are contained in Section IV.G of this
preamble. Under option 1, EPA would
not independently verify the accuracy
and consistency of the reported data.
Furthermore, because this approach
does not include independent
verification by EPA or a third party, the
facility would not have to submit the
PO 00000
Frm 00030
Fmt 4701
Sfmt 4702
detailed data needed to verify emissions
estimates. Such information would be
retained at the facility. For example,
facilities would not be required to
submit detailed monitoring data,
activity data (e.g., fuel use, raw material
consumption, production rates), carbon
content measurements, or emission
factor data used to calculate emissions.
Option 1 is a low burden option for
reporters submitting data for this rule.
Reporters under this option would not
have to pay for third-party verifiers and
would not necessarily have to submit
the additional data required under the
other options. In addition, EPA would
not incur the expense of conducting
verification of the reported data or
certifying independent verifiers to
conduct verification activities. The
major disadvantages of this approach
are the greater potential for inconsistent
and inaccurate data in the absence of
independent verification and the lower
level of confidence that the public,
stakeholders and EPA may have in the
data.
Option 2. Self-certification with thirdparty verification. Under this approach,
reporters would submit the same selfcertification statements as under option
1. In addition, reporters would be
required to hire independent third-party
verifiers. The third-party verifiers would
review the emissions report and the
underlying monitoring system records,
activity data collection, calculation
procedures, and documentation, and
submit a verification statement that the
reported emissions are accurate and free
of material misstatement. Under this
approach, records supporting the GHG
emissions calculations would be
retained at the facility for compliance
purposes and provided to the verifiers,
but not submitted to EPA. In addition,
as discussed below, EPA would have to
establish a system to certify the
independent verifiers.
Self-certification with third-party
verification provides greater assurance
of accuracy and impartiality than selfcertification without verification. While
this option is consistent with some
existing domestic and international
GHG reporting programs such as TCR,
the California mandatory reporting rule,
CCAR, and the EU Emission Trading
System, the majority of industry
stakeholders that met with EPA are
opposed to this approach for this
rulemaking, primarily due to the
additional cost. Compared to option 1,
the third-party verification approach
places two additional costs on reporters:
(1) Reporters would need to hire and
pay verifiers, at a cost of thousands of
dollars per reporting facility, and (2)
reporters would incur costs to assemble
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
and provide to verifiers detailed
supporting data for the emission
estimates.
To ensure consistency and quality of
the third-party verifications, EPA would
need to develop verification protocols,
establish a system to qualify and
accredit the third-party verifiers, and
conduct ongoing oversight and auditing
of verifications to be sure that thirdparty verifications continue to be
conducted in a consistent and high
quality manner.
As mentioned above, as climate
policy evolves, it may be appropriate for
EPA to consider the use of third party
verification in other circumstances (e.g.,
offsets).
Option 3. Self-certification with EPA
verification. Under this option, reporters
would submit the same self-certification
as under option 1. Reporters also would
assemble data to support their emissions
estimates, similar to option 2 but submit
it to EPA in their annual emission
reports, rather than to a third party
verifier. EPA would review the
emissions estimates and the supporting
data contained in the reports, and
perform other activities (e.g.,
comparison of data across similar
facilities, site visits) to verify that the
reported emissions data are accurate
and complete.
EPA verification provides greater
assurance of accuracy and impartiality
than self-reporting without verification.
Compared to a third-party verification
system, there would be a consistent
approach to verification from one
centralized verifier rather than a variety
of separate verifiers although this option
would require EPA to ensure
consistency if it chose to use its own
contractors to support its verification
activities. In addition, a centralized
verification system would provide
greater ability to the government to
identify trends and outliers in data and
thus assist with targeted enforcement
planning. Finally, an EPA verification
approach is consistent with other EPA
emissions reporting programs including
EPA’s ARP.60 The cost to the reporter is
intermediate between options 1 and 2.
Although this approach would not
subject reporters to the cost of paying
for third-party verifiers, reporters would
have to assemble and submit detailed
supporting data to ensure proper
verification by EPA. An EPA
60 For a description of how verification is
conducted in ARP please see, ‘‘Fundamentals of
Successful Monitoring, Reporting, and Verification
under a Cap-and-Trade Program.’’ John
Schakenbach, Robert Vollaro, and Reynaldo Forte,
U.S. EPA/OAP. Journal of the Air and Waste
Management Association 56:1576–1583. November
2006. (EPA–HQ–OAR–2008–0508–051.)
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
verification program would result in
greater costs to the Agency than options
1 and 2, but due to economies of scale
may result in lower overall costs.
3. Selection of Self-Certification With
EPA Verification as the Proposed
Approach
EPA is proposing self-certification
with EPA verification (option 3) because
it ensures that data reported under this
rule are consistent, accurate, and
complete. In addition, we are seeking
comment on requiring third-party
verification for suppliers of petroleum
products, many of whom currently
report to EPA under the Office of
Transportation and Air Quality’s fuels
programs. Third-party verification could
be reasonable in these instances because
this rule, to some extent, would build
on existing transportation fuels
programs that already require audits of
records maintained by these suppliers
by independent certified public
accountants or certified internal
auditors. For more information about
the approach to fuel suppliers please
refer to Section V of this preamble.
EPA is successfully using self
certification with EPA verification in a
number of other emissions reporting
programs. EPA verification option
provides greater assurance of the
accuracy, completeness, and
consistency of the reported data than
option 1 (no independent verification)
and consistent with feedback from
industry stakeholders, does not require
reporters to hire third-party verifiers
(option 2). In addition, EPA verification
option does not require the
establishment of an accreditation and
approval program for third-party
verifiers although it would require EPA
to ensure consistency if it chose to use
its own contractors to support its
verification activities.
EPA judged that option 1 (no
independent verification) does not
ensure sufficient quality data for the
possible future uses of the data. The
potential inconsistency, inaccuracy, and
increased uncertainty of the data
collected under option 1 would make
the data less useful for informing
decisions on climate policy and
supporting the development of a wide
range of potential future policies and
regulations.
We selected EPA verification (option
3) instead of third-party verification
(option 2) because EPA verification is
consistent with other EPA programs, has
lower costs to reporters than option 2,
and would result in a consistent
verification approach applied to all
submitted data. Even with a verifier
accreditation and approval process, the
PO 00000
Frm 00031
Fmt 4701
Sfmt 4702
16477
third-party verification approach could
entail a risk of inconsistent verifications
because verification responsibilities are
spread amongst numerous verifiers.
Given the potential diversity of verifiers,
the quality and thoroughness of
verifications may be inconsistent and
EPA audit and enforcement oversight
would become the predominant factor
in ensuring uniformity. Under option 2,
EPA would also need to develop and
administer a process to ensure that
verifiers hired by the reporting facilities
do not have conflicts of interest. Such
a program could require EPA to review
numerous individual conflict of interest
screening determinations made each
time a reporter hires a third-party
verifier. Finally, EPA verification would
likely avoid any delays that may be
introduced by third-party verification
and better ensure the timely reporting
and use of the reported data. Some
reporting programs provide four to six
months after the annual emissions
report is submitted for third-party
verification. That said, as mentioned
above, depending on the scope or type
of program (e.g., offsets), EPA may
consider the use of third party
verification in the future as policy
options evolve.
The Agency recognizes that, in some
instances, data submitted by reporters
under this rule may have been
independently verified as the result of
other mandatory or voluntary GHG
reporting programs or by other Federal,
State or local regulations. Whether or
not data have been independently
verified outside of the requirements of
this proposed GHG reporting rule, EPA
has concluded for the purposes of this
proposal it is important to apply the
same verification requirements to all
affected facilities in order to ensure
equity across all reporters and
consistent data collection for policy
analysis and public information.
K. Rationale for Selection of Duration of
the Program
EPA is proposing that the rule require
the reporting of GHG emissions data on
an ongoing, annual basis. Other
approaches that EPA considered include
a one-time collection of information and
collection of a limited duration (e.g., a
three-year data collection effort).
EPA does not believe that a one-time
data collection effort is consistent with
the legislative history of the FY 2008
Consolidated Appropriations Act,
which instructed EPA to develop a rule
to require the reporting of GHG
emissions. Typically, a rule is not
required to undertake a one-time
information collection request.
Moreover, the President’s FY 2010
E:\FR\FM\10APP2.SGM
10APP2
16478
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Budget, as well as initial Congressional
budgets for the remainder of FY 2009
indicate that policy makers anticipate
that the information will be collected for
multiple years.
For example, on February 6, 2009,
Senators Feinstein, Boxer, Snowe and
Klobuchar sent a letter to EPA’s
Administrator Lisa Jackson and OMB’s
Director Peter Orszag stating that this
program allowed EPA to ‘‘gather critical
baseline data on greenhouse gas
emissions, which is essential
information that policymakers need to
craft an effective climate change
approach.’’ In addition, in recent
testimony from John Stephenson,
Director of Natural Resources and
Environment at the Government
Accountability Office,61 stated that
when setting baselines for past
regulatory policies, averaging data
‘‘across several years also helped to
ensure that the baseline reflected
changes in emissions that can result in
a given year due to economic and other
conditions.’’ The testimony further
noted the because EPA’s ARP was able
to average several years worth of data
when setting the baseline for SO2
reductions, the program ‘‘achieved
greater assurances that it reduced
emissions from historical levels’’ as
opposed to the EU who did not have
enough data to set accurate baselines for
the first phase of the EU Emissions
Trading System. Furthermore, EPA’s
experience with certain CAA programs
show that a one-time snapshot of
information is not always representative
of normal operations, and hence
emissions, of a facility. See, e.g., Final
New Source Review (NSR) Reform
Rules, 68 FR 80186, 80199 (2002).
Finally, as discussed earlier, a multiyear reporting program allows EPA to
track trends in emissions and
understand factors that influence
emissions levels.
EPA also considered a multi-year
program that would sunset at a date
certain in the future (e.g., three years)
absent subsequent regulatory action by
EPA to extend it. EPA decided against
this approach because it would
unnecessarily limit the debate about
potential policy options to address
climate change. At this time, it would be
premature to guess at what point in the
future this information may be less
relevant to decision-making. Rather, a
more prudent approach is to maintain
the program until such time in the
future when it is determined that the
61 High Quality Greenhouse Gas Emissions Data
are a Cornerstone of Programs to Address Climate
Change, Statement of John Stephenson, Director,
Natural Resources and Environment, Government
Accountability Office, February 24, 2009.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
information for one or more source
categories is no longer relevant to
decision-making, or is adequately
provided in the context of regulatory
program (e.g., CAA NSPS). Notably,
EPA crafted the requirements in this
rule with the potential monitoring,
recordkeeping and reporting
requirements for any future regulations
addressing GHG emissions in mind.
EPA solicits comment on all of these
possible approaches, including whether
EPA should commit to revisit the
continued necessity of the reporting
program at a future date.
V. Rationale for the Reporting,
Recordkeeping and Verification
Requirements for Specific Source
Categories
Section V of this preamble discusses
the source categories covered by the
proposed rule. Each section presents a
description of a source category and the
proposed threshold, monitoring
methods, missing data procedures, and
reporting and recordkeeping
requirements.
A. Overview of Reporting for Specific
Source Categories
Once you have determined that your
facility exceeds any reporting threshold
specified in 40 CFR 98.2(a), you would
have to calculate and report GHG
emissions, or alternate information as
required (e.g., production and imports
for industrial GHG suppliers) for all
source categories at your facility for
which there are measurement methods
provided. The threshold determination
is separately assessed for suppliers
(fossil fuel suppliers and industrial GHG
suppliers) and downstream source
categories.
Facilities, or corporations, where
relevant, that trigger only the threshold
for upstream fossil fuel or industrial
GHG supply (proposed 40 CFR part 98,
subparts KK through PP) need only
follow the methods in those respective
sections. Facilities (or corporations) that
contain source categories that also have
downstream sources of emissions (e.g.,
proposed 40 CFR part 98, subparts B
through JJ), or facilities that are
exclusively downstream sources of
emissions may have to monitor and
report GHG emissions using methods
presented in multiple sections. For
example, a food processing facility
should review Section V.C (General
Stationary Fuel Combustion), Section
V.HH (Landfills) and Section V.II
(Wastewater Treatment) in addition to
Section V.M (Food Processing) of this
preamble. Table 2 of this preamble (in
the SUPPLEMENTARY INFORMATION section
of this preamble) provides a cross walk
PO 00000
Frm 00032
Fmt 4701
Sfmt 4702
to aid facilities in identifying potentially
relevant source categories. The crosswalk table should only be seen as a
guide as to the types of source categories
that may be present in any given facility
and therefore the methodological
guidance in Section V of this preamble
that should be reviewed. Additional
source categories (beyond those listed in
Table 2 of this preamble) may be
relevant to a given reporter. Similarly,
not all listed source categories would be
relevant to all reporters. The remainder
of this overview summarizes the general
approach to calculating and reporting
these downstream sources of emissions.
Consistent with the requirements in
the proposed 40 CFR part 98, subpart A,
facilities would have to report GHG
emissions from all source categories
located at their facility—stationary
combustion, process (e.g., iron and
steel), fugitive (e.g., oil and gas) or
biologic (e.g., landfills) sources of GHG
emissions. The methods presented
typically account for normal operating
conditions, as well as SSM, where
significant (e.g., HCFC–22 production
and oil and gas systems). Although SSM
is not specifically addressed for many
source categories, emissions estimation
methodologies relying on CEMS or mass
balance approaches would capture these
different operating conditions.
For many facilities, calculating
facility-wide emissions would simply
involve adding GHG emissions
calculated under Section V.C of this
preamble (General Stationary Fuel
Combustion Sources) and emissions
calculated under the source-specific
subpart. For other facilities, particularly
selected sources in Sections V.E through
V.JJ of this preamble that rely on mass
balance approaches or the use of CEMS,
the proposed methods would
(depending on the operating conditions
and configuration of the plant) capture
both combustion and process-related
emissions and there is no need to
separately quantify combustion-related
emissions using the methods presented
in Section V.C of this preamble.
Generally, the proposed method
depends on the equipment you
currently have installed at the facility.
Sources with CEMS. If you have
CEMS that meet the requirements in
proposed 40 CFR part 98, subpart C you
would be required to quantify and
report the CO2 emissions that can be
monitored using the existing CEMS.
Non-CO2 combustion-related emissions
would be estimated consistent with
proposed 40 CFR part 98, subpart C, and
other non-CO2 emissions would be
estimated using the source-specific
methods provided.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(1) Where the CEMS capture both
combustion- and process-related
emissions you would be required to
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of proposed 40 CFR part
98, subpart C to estimate emissions from
the industrial source. In this case, use of
the additional methods provided in the
source-specific discussions would not
be required.
(2) Where the CEMS do not capture
both combustion and process-related
emissions, you should refer to the
source-specific sections that provide
methods for calculating process
emissions. You would also be required
to follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of proposed 40 CFR part
98, subpart C to estimate any stationary
fuel combustion emissions from the
industrial source.
Sources without CEMS. If you do not
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, you would be required to
carry out facility-specific calculations to
estimate process emissions. You would
also be required to follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
any stationary fuel combustion
emissions from the industrial source.
B. Electricity Purchases
At this time, we are not proposing
that facilities report information to us
regarding their electricity purchases or
indirect emissions from electricity
consumption. However, we carefully
considered proposing that all facilities
that report to us also report their total
purchases of electricity. This section
describes our deliberations and outlines
potential methods for monitoring and
reporting electricity purchases. We
generally seek comment on the value of
collecting information on electricity
purchases. Further, we are specifically
interested in receiving feedback on the
approach outlined below.
1. Definition of the Source Category
The electric utility sector is the largest
emitter of GHG emissions in the U.S.
The level of GHG emissions associated
with electricity use is determined not
just by the fuel and combustion
technology onsite at the power plant,
but also by customer demand for
electricity. Accordingly, electricity use
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
and the efficiency of this use indirectly
affect the emissions of CO2, CH4 and
N2O from the combustion of fossil fuel
at electric generating stations.
For many facilities, purchased
electricity represents a large part of
onsite energy consumption, and their
overall GHG emissions footprint when
taking into account the indirect
emissions from fossil fuel combusted for
the electricity generated. Therefore, the
reporting of electricity purchase data
from facilities could provide a better
understanding of how electricity is used
in the economy and the major sectors.
We would propose not to provide for
adjustments to take into account the
purchases of renewable energy credits
or other mechanisms.
If included, this source category
would include electricity purchases, but
not include electricity generated onsite
(i.e., facility-operated power plants,
emergency back-up generators, or any
portable, temporary, or other process
internal combustion engines). General
requirements for all reporters subject to
the proposed rule to report on total
kilowatt hours of electricity generated
onsite is discussed in Section IV.G of
the preamble. Calculating emissions
from onsite electricity generation is
addressed in Sections V.C and V.D of
this preamble.
For additional background
information on indirect emissions from
electricity purchases, please refer to the
Electricity Purchases TSD (EPA–HQ–
OAR–2008–0508–003).
2. Selection of Reporting Threshold
Three options for reporting thresholds
could be considered for the reporting of
indirect emissions from purchased
electricity (i.e., GHG emissions from the
production of purchased electricity).
These options would be as follows:
Option 1: Do not require any reporting
on electricity purchases or associated
indirect emissions from electricity
purchases as part of this rule.
Option 2: Require reporting on
purchased electricity from all facilities
that are already required to report their
GHG emissions under this rule.
Option 3: Require reporting of
indirect emissions from purchased
electricity for facilities that exceed a
prescribed total facility emissions
threshold (including indirect emissions
from the purchased electricity).
Reporting for this option could be
proposed either in terms of electricity
purchases or calculated indirect CO2e
emissions based on purchased
electricity. This option would require an
additional number of reporters, based
on their annual electricity purchases, to
report indirect emissions.
PO 00000
Frm 00033
Fmt 4701
Sfmt 4702
16479
No additional facilities to those
already reporting their emissions data
under this rule would be affected by the
first or second options. The number of
additional facilities affected by the third
proposed threshold is estimated to be
approximately: 250 facilities at a
100,000 metric tons CO2e threshold;
5,000 total facilities at a 25,000 metric
tons CO2e threshold; 15,000 total
facilities at a 10,000 metric tons CO2e
threshold; and 185,000 total facilities at
a 1,000 metric tons CO2e threshold.
Under all threshold options, reporting
of information related to electricity
purchases would apply to entities
reporting at the facility level. This
provision would not apply to source
categories that we propose report at the
corporate level (e.g., importers and
exporters of industrial GHGs, local
distribution companies, etc.). These
companies in many cases may own large
facilities such as refineries which
already have a reporting obligation for
direct emissions and electricity
purchases.
Given the above considerations, our
preferred option would be option 2.
Purchased electricity is considered to be
a significant portion of the GHG
emissions of most industrial facilities,
therefore the collection of indirect
emissions from purchased electricity
could be seen as an important
component of the GHG mandatory
reporting rule. Although such a
reporting requirement would not
provide EPA with emissions
information, it could provide the
necessary underlying data to develop
emissions estimates in the future if this
were necessary.
The reporting of electricity purchase
data directly instead of calculated
indirect emissions would be preferred
due to the difficulties in identifying the
appropriate electrical grid or electrical
plant emission factor for converting a
facility’s electricity purchases to GHG
emissions. EPA does not have data to
evaluate the uncertainty of applying
national, regional or State emission
factors to electricity consumption at a
given facility, versus undertaking
detailed studies to determine the actual
emissions from electricity purchases.
Under Option 2, all facilities that are
already required to report their GHG
emissions under this rule would also
have to quantify and report their annual
electricity purchases. The total
purchased electricity would include
electricity purchased from all sources
(i.e., fossil fuel power plants, green
power generating facilities, etc.). It
should be noted that under this
approach, data from large sources of
indirect emissions due to electricity
E:\FR\FM\10APP2.SGM
10APP2
16480
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
usage (e.g., non-industrial commercial
buildings) would be not be collected.
3. Selection of Proposed Monitoring
Methods
Purchased electricity could be
quantified through the use of purchase
receipts or similar records provided by
the electricity provider. The facility
could choose to use data from facility
maintained electric meters in addition
to or in lieu of data from an electricity
provider (e.g., electricity purchase
receipts, etc.), provided that this data
could be demonstrated to accurately
reflect facility electricity purchases.
However, purchase receipts or
electricity provider data would be the
preferred method of quantifying a
facility’s electricity purchases. Because
facilities would be expected to retain
these data as part of routine financial
records, the only additional burden of
collecting this information would be to
retain the records in a readily available
manner.
In identifying the options outlined
above, we reviewed five reporting
programs and guidelines: (1) EPA
Climate Leaders Program, (2) the CARB
Mandatory Greenhouse Gas Emissions
Program, (3) TRI, (4) the DOE 1605(b)
program, and (5) the GHG Protocol
developed jointly by WRI and WBCSD.
In general, these protocols follow the
methods presented in WRI/WBCSD for
the quantification and reporting of
indirect emissions from the purchase of
electricity.
See the Electricity Purchases TSD
(EPA–HQ–OAR–2008–0508–003) for
more information.
4. Selection of Procedures for Estimating
Missing Data
If we were to collect information on
electricity purchases, we would propose
that a facility be required to make all
attempts to collect electricity records
from their electricity provider. In the
event that there were missing electricity
purchase records, the facility would
estimate its electricity purchases for the
missing data period based on historical
data (i.e., previous electricity purchase
records). Any historical data used to
estimate missing data should represent
similar circumstances to the period over
which data are missing (e.g., seasonal).
If a facility were using electric meter
data and had a missing data period, the
facility could use a substitute data value
developed by averaging the qualityassured values metered values for
kilowatt-hours of electricity use
immediately before and immediately
after the missing data period.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
5. Selection of Data Reporting
Requirements
If we were to collect information on
electricity purchases, we would propose
that a facility report total annual
purchased electricity in kilowatt-hours
for the entire facility.
6. Selection of Records That Must Be
Retained
If we were to collect information on
electricity purchases, we would propose
that the owner or operator maintain
monthly electricity purchase records for
all operations and buildings. If electric
meter data were used, then monthly logs
of the electric meter readings would also
be proposed to be maintained.
C. General Stationary Fuel Combustion
Sources
1. Definition of the Source Category
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,
combustion turbines, engines,
incinerators, and process heaters. The
combustion process may be used to: (a)
Generate steam or produce useful heat
or energy for industrial, commercial, or
institutional use; (b) produce electricity;
or (c) reduce the volume of waste by
removing combustible matter. As
discussed in Section III of this preamble
and proposed 40 CFR part 98, subpart
A, this section applies to facilities with
stationary fuel combustion sources that
(a) have emissions greater than or equal
to 25,000 metric tons CO2e/yr; or (b) are
referred to this section by other source
categories listed in proposed 40 CFR
98.2(a)(1) or (2).
Combustion of fossil fuels in the U.S.
is the largest source of GHG emissions
in the nation, producing three principal
greenhouse gases: CO2, CH4 and N2O.
For the purposes of this rule, CO2, CH4,
and N2O would be reported by
stationary fuel combustion sources. The
emission rate of CO2 is directly
proportional to the carbon content of the
fuel, and virtually all of the carbon is
oxidized to CO2. The emission rates of
CH4 and N2O are much less predictable,
as these gases are by-products of
incomplete or inefficient combustion,
and depend on many factors such as
combustion technology and other
considerations. The CO2 emissions
generated by fuel combustion far exceed
PO 00000
Frm 00034
Fmt 4701
Sfmt 4702
the CH4 and N2O emissions (CH4 and
N2O contribute less than 1 percent of
combined U.S. GHG emissions from
stationary combustion, on a CO2e basis),
however, under this proposed rule, CO2,
CH4, and N2O would all be reported by
stationary fuel combustion sources. EPA
is proposing to not require reporting of
emissions from portable equipment or
generating units designated as
emergency generators in a permit issued
by a state or local air pollution control
agency. We request comment on
whether or not a permit should be
required for these emergency generators.
A wide and diverse segment of the
U.S. economy engages in stationary
combustion, principally the combustion
of fossil fuels. According to the
‘‘Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990–2006’’, the
nationwide GHG emissions from
stationary fossil fuel combustion are
approximately 3.75 billion metric tons
CO2e per year. This estimate includes
both large and small stationary sources
and represents more than 50 percent of
total GHG emissions in the U.S.
EPA’s proposed rule presents
methods for calculating GHG emissions
from stationary combustion, both at
unspecified facilities as well as facilities
in source categories listed in proposed
40 CFR 98.2(a)(1) and (2), which are
based on the fuel combusted and the
size of the stationary equipment (e.g.,
the maximum heat input capacity in
mmBtu/hr). EPA already collects CO2
emissions data from electricity
generating units in the ARP,62 which
combust the vast majority of coal
consumed in the U.S. annually. So,
while detailed requirements are
provided for facilities that combust
solid fuels, these methods are likely to
affect only a small percentage of
facilities reporting under proposed 40
CFR part 98 (as separate methods, in
proposed 40 CFR 98.40, would be used
by electricity generating units already
reporting under the requirements of
ARP). In presenting methodologies in
the following sections, EPA further
notes that the majority of reporters
under proposed 40 CFR part 98, subpart
C would use the methods prescribed for
stationary combustion equipment
combusting natural gas.
Table C–1 of this preamble illustrates
the methods for calculating CO2
emissions for different types of reporters
based on the fuel being combusted at
the facility and the size of the stationary
combustion equipment. The
62 It should be noted, as discussed in section V.D,
EPA already collects over 90% of total CO2
emissions from U.S. coal combustion through the
40 CFR part 75 requirements of ARP.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
calculations for CH4 and N2O that are
presented in subsequent subsections are
to be applied to all fuel types and are
16481
not contingent upon the stationary
cobustion equipment size.
TABLE C–1. FOUR-TIERED APPROACH FOR CALCULATING CO2 EMISSIONS FROM STATIONARY COMBUSTION SOURCES
Combustion unit size
Methodological
tier
required a
Additional requirement(s)
Solid Fossil Fuel (e.g., Coal)
> 250 mmBtu/hour ...................................
≤ 250 mmBtu/hr .......................................
—Unit has operated more than 1,000 hours a year b ...............................................
—Unit has existing, certified gas monitors or stack gas volumetric flow rate monitor (or both); and
—Facility has an established monitoring infrastructure and meets specific QA/QC
requirements.
—Unit does not meet conditions above ....................................................................
—Unit operates more than 1,000 hours a year b ......................................................
—Unit has existing, certified CO2 or O2 concentration monitor and stack gas volumetric flow rate monitor; and
—Facility has an established monitoring infrastructure and meets specific QA/QC
requirements.
—Unit does not meet conditions above ....................................................................
—Monthly measured HHV is available.
—Unit does not meet conditions above ....................................................................
—Monthly measured HHV is not available.
4
3
4
2
1
Gaseous Fossil Fuel (e.g., Natural Gas)
> 250 mmBtu/hr .......................................
≤ 250 mmBtu/hr .......................................
None ..........................................................................................................................
—Monthly measured HHV is available .....................................................................
—Monthly measured HHV is not available ...............................................................
3
2
1
Fossil Liquid Fuel (e.g., Diesel)
> 250 mmBtu/hr .......................................
≤ 250 mmBtu/hr .......................................
None ..........................................................................................................................
—Monthly measured HHV is available .....................................................................
—Monthly measured HHV is not available ...............................................................
3
2
1
Biomass or Biomass-Derived Fuels (e.g., wood)
All Sizes ...................................................
All Sizes ...................................................
All Sizes ...................................................
—EPA has provided a default CO2 emission factor and a default heating value for
the fuel.
—EPA has provided a default CO2 emission factor for specific fuel to be used
with that fuel’s measured heating value.
—EPA has not provided a default CO2 emission factor for specific fuel to be used
with that fuel’s measured heating value.
1
2
3
MSW
> 250 tons MSW/day ...............................
≤ 250 tons MSW/day ...............................
—Unit has operated more than 1,000 hours a year b ...............................................
—Unit has existing, certified gas monitors or stack gas volumetric flow rate monitor (or both); and
—Facility has an established monitoring infrastructure and meets specific QA/QC
requirements.
—Unit does not meet conditions above ....................................................................
—Unit operates more than 1,000 hours a year b ......................................................
—Unit has existing, certified CO2 concentration monitor and stack gas volumetric
flow rate monitor; and
—Facility has an established monitoring infrastructure and meets specific QA/QC
requirements.
—Unit does not meet conditions above ....................................................................
4
2
4
2
a Minimum
tier level to be used by reporters. Reporters required to use Tier 1, 2, or 3 have the option to use a higher tier methodology.
of operation in any year since 2005.
Note: Facilities with units reporting CO2 data to ARP should refer to Section V.D of this preamble (Electricity Generation).
b Hours
2. Selection of Reporting Threshold
In developing the threshold for
facilities with stationary combustion
equipment, EPA considered an
emissions-based threshold of 1,000,
10,000, 25,000, and 100,000 metric tons
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
CO2e. Table C–2 of this preamble
illustrates the emissions covered and
the number of facilities that would be
covered under these various thresholds.
It should be noted that Table C–2 of this
preamble only includes facilities with
stationary combustion equipment that
PO 00000
Frm 00035
Fmt 4701
Sfmt 4702
are not covered in other subparts of the
proposed rule. For this reason, the total
emissions presented in Table C–2 of this
preamble appear as a lower total than
presented previously (the general
discussion in Section C.1 of this
preamble), where emissions from all
E:\FR\FM\10APP2.SGM
10APP2
16482
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
stationary combustion equipment are
being discussed.
TABLE C–2. THRESHOLD ANALYSIS FOR UNSPECIFIED INDUSTRIAL STATIONARY FUEL COMBUSTION
Total national
emissions
(million
metric tons
CO2e)
Million
metric tons
CO2e/yr
410
410
410
410
Threshold level metric tons CO2e/yr
Total number
of facilities
350,000
350,000
350,000
350,000
250
230
220
170
1,000
10,000
25,000
100,000
In calculating emissions for this
analysis, and for the proposed
threshold, only CO2 from the
combustion of fossil fuels, in
combination with all CH4 and N2O
emissions, are considered. CO2
emissions from biomass are not
considered as part of the determination
of the threshold level. This treatment of
biomass fuels is consistent with the
IPCC Guidelines and the annual
Inventory of U.S. Greenhouse Gas
Emissions and Sinks, which account for
the release of these CO2 emissions in
accounting for carbon stock changes
from agriculture, forestry, and other
land-use. CH4 and N2O emissions from
combustion of biomass are counted as
part of stationary combustion within the
IPCC and national U.S. GHG inventory
frameworks.
The purpose of the general stationary
combustion source category is to
capture significant emitters of stationary
combustion GHG emissions that are not
covered by the specific source categories
described elsewhere in this preamble.
Therefore, EPA is proposing a threshold
for reporting emissions from stationary
combustion at 25,000 metric tons
CO2e.63 EPA selected the proposed
25,000 metric tons CO2e threshold as it
appears to strike the best balance
between covering a high percentage of
nationwide GHG emissions and keeping
the number of affected facilities
manageable. As illustrated in Table C–
2 of this preamble, selecting a 25,000
metric tons CO2e threshold achieves the
greatest incremental gain in coverage
with the lowest increase in the number
of covered sources.
The 100,000 metric tons CO2e
threshold was not proposed because
EPA believes it would exclude too many
significant emitters of GHG emissions
that are not required to report pursuant
63 As described previously, the threshold only
includes CO2 from the combustion of fossil fuels
and CH4 and N2O emissions from all fuel
combustion. CO2 emissions from biomass are not
considered as part of the determination of the
threshold level.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
to the other provisions of this rule. EPA
believes that most of the population of
facilities over a 100,000 metric tons
CO2e threshold is known either through
source category studies or existing EPA
reporting programs.
The 10,000 metric tons CO2e
threshold showed a smaller incremental
gain in emissions coverage from a
higher threshold than the 25,000 metric
tons CO2e threshold, while greatly
increasing the incremental number of
reporters (as illustrated in Table C–2 of
this preamble). The 1,000 metric tons
CO2e threshold greatly increases the
total number of reporters for this rule
and places an unnecessary
administrative burden on EPA, while
not greatly increasing nationwide
emissions coverage of stationary
combustion sources.
In addition, although there is
considerable uncertainty as to the
number of facilities under a 25,000
metric tons CO2e threshold, there is
evidence to indicate that moving the
threshold from 25,000 to 10,000 metric
tons CO2e would have a
disproportionate impact on the
commercial sector. It should also be
noted that this concern is even more
applicable to the 1,000 metric tons CO2e
threshold.
EPA concluded that a 25,000 metric
tons CO2e threshold would better
achieve a comprehensive economy wide
coverage of emissions while focusing
reporting efforts on large industrial
emitters. In particular, it would address
the considerable uncertainties in the
25,000 to 100,000 metric tons CO2e
emissions range, both as to the number
of reporters and the magnitude of
emissions. EPA believes that a 25,000
metric tons CO2e threshold would help
in gathering data from a reasonable
number of reporters for which little
information is currently known without
imposing undue administrative burden.
EPA also considered including GHG
emissions from the combustion of
biomass fuels in the emission threshold
calculations. Therefore, the proposed
PO 00000
Frm 00036
Fmt 4701
Sfmt 4702
Facilities covered
Percent
61
56
54
41
Number
32,000
8,000
3,000
1,000
Percent
9.1
2.3
0.9
0.3
rule states that GHG emissions from
biomass fuel combustion are to be
excluded when evaluating a facility’s
status with respect to the 25,000 metric
tons CO2e reporting threshold. This is
similar to the approach taken by the
IPCC and various other GHG emission
inventories.
Finally, EPA considered a heat input
capacity-based threshold (such as all
facilities with stationary combustion
equipment rated over 100 mmBtu/hr
maximum heat input capacity). A
complete, reliable set of heat input
capacity data was unavailable for all
facilities that might be subject to this
rule, thus this type of threshold could
not be thoroughly evaluated.
For a full discussion of the threshold
analysis and for background information
on this threshold determination, please
refer to the Thresholds TSD (EPA–HQ–
OAR–2008–0508–046). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
EPA’s proposed methods for
calculating GHG emissions from
stationary fuel combustion sources is
consistent with existing domestic and
international protocols, as well as
monitoring programs currently
implemented by EPA. Those protocols
and programs generally utilize either a
direct measurement approach based on
concentrations of combustion exhaust
gases through a stack, or a direct
measurement approach based on the
quantity of fuel combusted and the
characteristics of the fuel (e.g., heat
content, carbon content, etc.). As the
magnitude of CO2 emissions released by
stationary combustion sources relative
to CH4 and N2O is greater (even on a
CO2e basis), more guidance is provided
on the application of specific
monitoring and calculation methods for
CO2. EPA is proposing simpler
calculation methods for CH4 and N2O.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
For facilities which have EGUs
subject to the ARP reporting
requirements under 40 CFR part 75,
refer to Section V.D of this preamble
regarding those units. For other units
located at that facility (i.e., units that are
not reporting to the ARP), the facility
would use the calculation methods
presented below.
The discussions which follow in this
subsection will focus on methods for: (a)
The calculation of CO2 emissions from
fuel combustion; (b) the calculation for
the separate reporting of biogenic CO2
emissions; (c) reporting biogenic CO2
emissions from MSW; (d) the
calculation of CH4 and N2O emissions;
and (e) the calculation of additional CO2
emissions from the sorbent in
combustion control technology systems.
a. CO2 Emissions From Fuel
Combustion
To monitor and calculate CO2
emissions from stationary combustion
sources, EPA is proposing a four-tiered
approach, which would be applied
either at the unit or facility level. The
most stringent emissions calculation
methods would apply to large stationary
combustion units that are fired with
solid fuels and that have existing CEMS
equipment. This is due to the
complexity of monitoring solid fuel
consumption and the heterogeneous
nature of solid fuels. Furthermore,
because of the significant mass of CO2
emissions that are released by these
large units, combining stringent
methods and existing monitoring
equipment is justified.
The next level of methodological
stringency applies to large stationary
combustion units that are fired with
liquid or gaseous fuels. The stringency
of the methods reflects the homogenous
nature of these fuels and the ability to
monitor fuel consumption more
precisely. However, in cases where
there is greater heterogeneity in the
fuels (e.g., refinery fuel gas) more
frequent analyses of liquid and gaseous
fuels is required.
For smaller combustion units, EPA is
proposing to allow the use of more
simplified emissions calculation
methods that rely on relationships
between the heat content of the fuel (a
generally known parameter) and the
CO2 emission factor associated with the
fuel’s characteristics.
The following subsections present
EPA’s proposed four-tiered approach in
order from the most rigorous to the least
stringent, and describe how it must be
used by affected facilities. The
applicability of the four measurement
tiers, based on unit size and fuel type,
is summarized in Table C–1 of this
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
preamble. These CO2 emission
calculation methods would, in some
cases, be applied at the unit level, and
in other cases at the facility level (for
further discussion, see ‘‘Selection of
Data Reporting Requirements’’ below).
Affected facilities would have the
flexibility to use higher-tier methods
(i.e., more stringent methods) than the
ones required by this rule.
Tier 4. The Tier 4 methodology would
require the use of certified CEMS to
quantify CO2 mass emissions, where
existing CEMS equipment is installed.
The existing installed CEMS must
include a gas monitor of any kind or a
flow monitor (or both). Generally, a CO2
monitor and a stack gas volumetric flow
rate monitor would be required to
calculate CO2 emissions, although in
some cases, in lieu of a CO2
concentration monitor, data from a
certified oxygen (O2) concentration
monitor and fuel-specific F-factors
could be used to calculate hourly CO2
concentrations. An appropriate upgrade
of the existing CEMS would be required:
(1) If the gas monitor is neither a CO2
concentration monitor nor an O2
concentration monitor and (2) if a flow
monitor is not already installed.
Any CEMS that would be used to
quantify CO2 emissions would also have
to be certified and undergo on-going
quality-assurance testing according to
the procedures specified in either: (1) 40
CFR part 75; or (2) 40 CFR part 60,
Appendix B; or (3) a State monitoring
program.
The Tier 4 method, and the use of
CEMS (with any required monitor
upgrades), is required for solid fossil
fuel-fired units with a maximum heat
input capacity greater than 250 mmBtu/
hr (and for units with a capacity to
combust greater than 250 tons per day
of MSW). The use of an O2 monitor to
determine CO2 concentrations would
not be allowed for units combusting
MSW. EPA is unaware of carbon-based
F-factors for MSW that would be
appropriate for converting O2 readings
to CO2 concentrations for this rule.
Therefore, units combusting MSW
would need to use a CO2 monitor to
calculate CO2 emissions.
For smaller solid fossil fuel-fired units
(i.e., less than or equal to 250 mmBtu/
hr or 250 tons per day of MSW), EPA
would require the use of Tier 4 if all the
monitors needed to calculate CO2 mass
emissions (i.e., CO2 gas monitor and
flow monitor) are already installed, and
certified and quality assured as
described above.
In addition, in order to be subject to
the Tier 4 requirements, the unit must
have been operated for 1,000 hours or
more in any calendar year since 2005.
PO 00000
Frm 00037
Fmt 4701
Sfmt 4702
16483
The incremental cost of adding a
diluent gas (CO2 or O2) monitor or a
flow monitor, or both, to meet Tier 4
monitoring requirements would likely
not be unduly burdensome for a large
unit that combusts solid fossil fuels or
MSW, operates frequently, and is
already required to install, certify,
maintain, and operate CEMS and to
perform on-going QA testing of the
existing monitors. The cost of
compliance with the proposed rule
would be even less for units that already
have all of the necessary monitors in
place. Cost estimates are provided in the
RIA (EPA–HQ–OAR–2008–0508–002).
In addition, EPA is allowing provisions
to monitor common stack
configurations. Please refer to Section
V.C.5 of this preamble, on data reporting
requirements, for further information on
reporting where there are common stack
configurations.
Reporters would follow the reporting
requirements stated in proposed 40 CFR
part 98, subpart A. However, EPA is
allowing a January 1, 2011 compliance
date to install CEMS to meet the Tier 4
requirements, if either a diluent gas
monitor, flow monitor, or both, must be
added. The January 1, 2011 deadline
would allow sufficient time to purchase,
install, and certify any additional
monitor(s) needed to quantify CO2 mass
emissions. Until that time, affected units
subject to that deadline would be
allowed to use the Tier 3 methodology
in 2010.
Tier 3. The Tier 3 calculation
methodology would require periodic
determination of the carbon content of
the fuel, using consensus standards
listed in the proposed 40 CFR part 98
(e.g., ASTM methods) and direct
measurement of the amount of fuel
combusted. This methodology is
required for liquid and gaseous fossil
fuel-fired units with a maximum heat
input capacity greater than 250 mmBtu/
hr, and is required for solid fossil fuelfired units that are not subject to the
Tier 4 provisions. In addition, EPA is
proposing that a facility may use the
Tier 3 calculation methodology to
calculate facility-wide CO2 emissions
(rather than unit-by-unit emissions)
when the same liquid or gaseous fuel is
used across the facility and a common
direct measurement of fuel consumed is
available (e.g., a natural gas meter at the
facility gate). This flexibility is
consistent with existing protocols and
methodologies allowed by EPA in
existing programs. Please refer to the
subsequent subsection on data reporting
requirements for further information on
the use of fuel data from common
supply lines.
E:\FR\FM\10APP2.SGM
10APP2
16484
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
The required frequency for carbon
content determinations for the Tier 3
calculation methodology would be
monthly for natural gas, liquid fuels,
and solid fuels (monthly molecular
weight determinations are also required
for gaseous fuels). Daily determinations
for other gaseous fuels (e.g., refinery gas,
process gas, etc.) would be required.
The daily fuel sampling requirement for
units that combust ‘‘other’’ gaseous fuels
would likely not be overly burdensome,
because the types of facilities that burn
these fuels are likely to have equipment
in place (e.g., on-line gas
chromatographs) to continuously
monitor the fuels’ characteristics in
order to optimize process operation.
Solid fuel samples would be taken
weekly and composited, but would only
be analyzed once a month. Also, fuel
sampling and analysis would be
required only for those days or months
when fuel is combusted in the unit.
For liquid and gaseous fuels, Tier 3
would require direct measurement of
the amount of fuel combusted, using
calibrated fuel flow meters.
Alternatively, for fuel oil, tank drop
measurements could be used. Solid fuel
consumption would be quantified using
company records. For quality-assurance
purposes, EPA proposes that all oil and
gas flow meters would have to be
calibrated prior to the first reporting
year. EPA recommends the use of the
fuel flow meter calibration methods in
40 CFR part 75, but, alternatively, the
manufacturer’s recommended procedure
could be used. Tank drop measurements
and carbon content determinations
would be made using the appropriate
methods incorporated by reference.
Tier 2. The Tier 2 calculation
methodology would require that the
HHVs of each fuel combusted would be
measured monthly. EPA is proposing
that the Tier 2 method be used by units
with heat input capacities of 250
mmBtu/hr or less, combusting fuels for
which EPA has provided default CO2
emission factors in the proposed rule.
Fuel consumption would be based on
company records. Please refer to the
subsequent subsection on data reporting
requirements for further information on
the aggregation of units.
Tier 1. Under Tier 1, the annual CO2
mass emissions would be calculated
using the quantity of each type of fuel
combusted during the year, in
conjunction with fuel-specific default
CO2 emission factors and default HHVs.
The amount of fuel combusted would be
determined from company records. The
default CO2 emission factors and HHVs
are national-level default factors. The
Tier 1 method may be used by any small
unit if EPA has provided the fuel-
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
specific HHV and emission factors in
proposed 40 CFR part 98, subpart C.
However, if the owner or operator
routinely performs fuel sampling and
analysis on a monthly (or more
frequent) basis to determine the HHV
and other properties of the fuel, or if
monthly HHV data are provided by the
fuel supplier, Tier 1 could not be used
but instead Tier 2 (or a higher tier)
would have to be used.
EPA considered several alternative
CO2 emission calculation methods of
varying stringency for stationary
combustion units. The most stringent
method would have required all
combustion units at the affected
facilities to use 40 CFR part 75
monitoring methodologies. However,
this option was not pursued because it
would have likely imposed an undue
cost burden, particularly on smaller
entities. For homogenous fuels, this
additional cost burden would probably
not lead to significant increases in
accuracy compared with Tiers 1–3.
For coal combustion, EPA evaluated a
number of calculation methods used in
other mandatory and voluntary GHG
emissions reporting programs. In
general, these methods require relatively
infrequent fuel sampling, do not take
into account the heat input capacity of
stationary combustion equipment, and
use company records to estimate fuel
consumption. Given the heterogeneous
characteristics of coal, EPA determined
that the procedures used in these other
programs are not rigorous enough for
this proposed rule and would introduce
significant uncertainty into the CO2
emissions estimates, especially for
larger combustion units.
EPA considered allowing the use of
default emission factors, default HHVs,
and company records to quantify annual
fuel consumption for all stationary
combustion units, regardless of size or
the type of fuel combusted. The Agency
decided to limit the use of this type of
calculation methodology to smaller
combustion units. The proposed rule
reflects this, by allowing use of the Tier
1 and Tier 2 calculation methodologies
at units with a maximum heat input
capacity of 250 mmBtu/hr or less.
For gaseous fuel combustion, EPA
considered calculation methodologies
based on an assumption that all gaseous
fuels are homogeneous. However, the
Agency decided against this approach
because the characteristics of certain
gaseous fuels can be quite variable, and
mixtures of gaseous fuels are often
heterogeneous in composition.
Therefore, the proposed rule requires
daily sampling for all gaseous fuels
except for natural gas.
PO 00000
Frm 00038
Fmt 4701
Sfmt 4702
Finally, EPA considered allowing
affected facilities to rely exclusively on
the results of fuel sampling and analysis
provided by fuel suppliers, rather than
performing periodic on-site sampling for
all variables. The Agency decided not to
propose this because in most instances,
only the fuel heating value, not the
carbon content, is routinely provided by
fuel suppliers. Therefore, EPA proposes
to allow fuel suppliers to provide fuel
HHVs for the Tier 2 calculation method.
However, EPA is requesting comment
on integrating the fuel supplier
requirements of this proposed rule with
both the Tier 1 and Tier 2 calculation
methodologies.
b. CO2 Emissions From Biomass Fuel
Combustion
Today’s proposed rule requires
affected facilities with units that
combust biomass fuels to report the
annual biogenic CO2 mass emissions
separately. As previously described, this
is consistent with the approach taken in
the IPCC and national U.S. GHG
inventory frameworks. EPA is proposing
distinct methods to determine the
biogenic CO2 emissions from a
stationary combustion source
combusting a biomass or biomassderived fuel depending upon which tier
is used for reporting other fuel
combustion CO2 emissions.
Where Tier 4 is not required, EPA is
allowing the Tier 1 method to be used
to calculate biogenic CO2 emissions for
fuels in which EPA has provided default
CO2 emission factors and a default HHV
in the proposed rule. If default values
are not provided by EPA, the facility
would use the Tier 2 or Tier 3 method,
as appropriate, to calculate the biogenic
CO2 emissions.
For units required to use Tier 4, total
CO2 emissions are directly measured
using CEMS. Except when MSW is
combusted, EPA proposes that facilities
perform a supplemental calculation to
determine the biogenic CO2 and nonbiogenic CO2 portions of the measured
CO2 emissions. The facility would use
company records on annual fossil fuel
combusted to calculate the annual
volume of CO2 emitted from that fossil
fuel combustion. This value would then
be subtracted from the total volume of
CO2 emissions measured to obtain the
volume of biogenic CO2 emissions. The
volume ratio of biogenic CO2 emissions
to total CO2 emissions would then be
applied to the measured total CO2
emissions to determine the biogenic CO2
emissions.
c. CO2 Emissions From MSW
EPA is proposing a separate
calculation method for a unit that
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
combusts MSW, which can include
biomass components. For units subject
to Tier 4, as described above, an
additional analysis would be required to
separately report any biogenic CO2
emissions. The reporter would be
required to use ASTM methods listed in
the rule to sample and analyze the CO2
in the flue gas once each quarter, in
order to determine the relative
percentages of fossil fuel-based carbon
(e.g., petroleum-based plastics) and
biomass carbon (e.g., newsprint) in the
effluent when MSW is combusted in the
unit. The measured ratio of biogenic to
fossil CO2 concentrations is then
applied to the measured or calculated
total CO2 emissions to determine
biogenic CO2 emissions.
The GHG emission calculation
methods for units combusting MSW
would be used in conjunction with
EPA’s proposed calculation method for
the annual unit heat input, based on
steam production and the design
characteristics of the combustion unit.
For units that combust MSW, EPA
considered allowing a manual sorting
approach to be used to determine the
biomass and non-biomass fractions of
the fuel, based on defined and traceable
input streams. However, this approach
is not considered practical, given the
highly variable composition of MSW. To
eliminate this uncertainty, EPA believes
that more rigorous and standardized
ASTM methods should be used to
determine the biogenic percentage of the
CO2 emissions when MSW is
combusted.
d. CH4 and N2O Emissions From All
Fuel Combustion
As described previously, EPA is
allowing simplified emissions
calculation methods for CH4 and N2O.
The annual CH4 and N2O emissions
would be estimated using EPA-provided
default emission factors and annual heat
input values. The calculation would
either be done at the unit level or the
facility level, depending upon the tier
required for estimating CO2 emissions
(and using the same heat input value
reported from the CO2 calculation
method).
A CEMS methodology was not
selected for measuring N2O primarily
because the cost impacts of requiring
the installation of CEMS is high in
comparison to the relatively low amount
of N2O emissions (even on a CO2e basis)
that would be emitted from stationary
combustion equipment.
EPA considered requiring periodic
stack testing to derive site-specific
emission factors for CH4 and N2O. This
approach has the advantage of ensuring
a higher level of accuracy and
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
consistency among reporters. However,
it was decided that this option was too
costly for the small improvement in data
quality that it might achieve. The CH4
and N2O emissions from stationary
combustion are relatively low compared
to the CO2 emissions. The proposed
approach, i.e., using fuel-specific
default emission factors to calculate CH4
and N2O emissions, is in accordance
with methods used in other programs
and provides data of sufficient accuracy.
However, given the unit-level approach
for calculating CO2 emissions, EPA is
requesting comments on the use of more
technology-specific CH4 and N2O
emission factors that could be applied
in unit-level calculations.
e. CO2 Emissions From Sorbent
For fluidized bed boilers and for units
equipped with flue gas desulfurization
systems or other acid gas emission
controls with sorbent injection, CO2
emissions would be accounted for and
reported using simplified methods.
These methods are based on the
quantity of limestone or other sorbent
material used during the year, if not
accounted for using the Tier 4
calculation methodology.
In summary, EPA is proposing to
allow facilities flexibility in measuring
and monitoring stationary fuel
combustion sources by: (1) Allowing
most smaller combustion units
(depending upon facility-level
considerations described above) to use
the Tier 1 and Tier 2 calculation
methods; (2) allowing Tier 3 to be
widely used, with few restrictions; (3)
limiting the requirement to use Tier 4 to
certain solid fuel-fired combustion units
located at facilities where there is an
established monitoring infrastructure;
and (4) allowing simplified
methodologies to calculate CH4 and N2O
emissions. In addition, EPA is using a
maximum heat input capacity
determination of 250 mmBtu/hr to
distinguish between large and small
units. This approach is common to
many existing EPA programs.
EPA believes that the proposed
default CO2 emission factors and high
heat values used in Tiers 1 and 2 and
the ASTM methods incorporated by
reference for the carbon content
determinations required by Tier 3 are
well-established and minimize
uncertainty.
In proposing this tiered approach,
EPA acknowledges that, in the case of
solid fuels, a simple, standardized way
of measuring the amount of solid fuel
combusted in a unit is not proposed. In
view of this, the proposed rule would
require the owner or operator to keep
detailed records explaining how
PO 00000
Frm 00039
Fmt 4701
Sfmt 4702
16485
company records are used to quantify
solid fuel usage. These records would
describe the procedures used to
calibrate weighing equipment and other
measurement devices, and would
include scientifically-based estimates of
the accuracy of these devices. EPA
therefore solicits comment on ways to
ensure that the feed rate of solid fuel to
a combustion device is accurately
measured.
4. Selection of Procedures for Estimating
Missing Data
The proposed rule requires the use of
substitute data whenever a qualityassured value of a parameter that is used
to calculate GHG emissions is
unavailable, commonly referred to as
‘‘missing data.’’ For units using the CO2
calculation methodologies in Tiers 2
and 3, when HHV, fuel carbon content,
or fuel molecular weight data are
missing, the substitute data value would
be the average of the quality-assured
values of the parameter immediately
before and immediately after the
missing data period. When Tier 3 or
Tier 4 is used and fuel flow rate or stack
gas flow rate data is missing, the
substitute data values would be the best
available estimates of these parameters,
based on process and operating data
(e.g., production rate, load, unit
operating time, etc.). This same
substitute data approach would be used
when fuel usage data and sorbent usage
data are missing. The proposed rule
provides that the reporter would be
required to document and keep record
of the procedures used to determine the
appropriate substitute data values.
EPA considered more conservative
missing data procedures for the
proposed rule, such as requiring higher
substitute data values for longer missing
data periods, but decided against
proposing these procedures out of
concern that GHG emissions might be
significantly overestimated.
5. Selection of Data Reporting
Requirements
In addition to the facility-level
information that would be reported
under proposed 40 CFR part 98, subpart
A, the proposed rule would require the
reporter to submit certain unit-level data
for the stationary combustion units at
each affected facility. This additional
information would require reporting of
the unit type, its maximum rated heat
input, the type of fuel combusted in the
unit during the report year, the
methodology used to calculate CO2
emissions for each type of fuel
combusted, and the total annual GHG
emissions from the unit.
E:\FR\FM\10APP2.SGM
10APP2
16486
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
To reduce the reporting burden, the
proposed rule would allow reporting of
the combined GHG emissions from
multiple units at the facility instead of
requiring emissions reporting for each
individual unit, in certain instances.
Three types of emissions aggregation
would be allowed. First, the combined
GHG emissions from a group (or groups)
of small units at a facility could be
reported, provided that the combined
maximum rated heat input of the units
in the group does not exceed 250
mmBtu/hr. Second, the combined GHG
emissions from units in a common stack
configuration could be reported, if
CEMS are used to continuously monitor
the CO2 emissions at the common stack.
Third, if a facility combusts the same
type of homogeneous oil or gaseous fuel
through a common supply line, and the
total amount of fuel consumed through
that supply line is accurately measured
using a calibrated fuel flow meter, the
combined GHG emissions from the
facility could be reported.
Different levels of verification data are
required depending upon which tier is
used for reporting. For Tier 1, only the
total quantity of each type of fuel
combusted during the report year would
be reported. For Tier 2, the quantity of
each type of fuel combusted during each
measurement period would be reported,
along with all high heat values used in
the emissions calculations, the methods
used to determine the HHVs, and
information indicating which HHVs (if
any) are substitute data values.
For Tier 3, the quantity of each type
of fuel combusted during each
measurement period (day or month)
would be reported, along with all
carbon content values and, if applicable,
molecular weight measurements used in
the emissions calculations, with
information indicating which ones (if
any) are substitute data values. In
addition, the results of all fuel flow
meter calibrations would be reported
along with information indicating
which analytical methods were used for
the carbon content determinations, flow
meter calibrations and (if applicable) oil
tank drop measurements.
For Tier 4, the number of unit
operating days and hours would be
reported, along with daily CO2 mass
emission totals, the number of hours of
substitute data used in the annual
emissions calculations, the results of the
initial CEMS certification tests and the
major ongoing QA tests.
If MSW is combusted in the unit, the
owner or operator would be required to
report the results of the quarterly
sample analyses used to determine the
biogenic percentage of CO2 emissions in
the effluent. If combinations of fossil
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
and biomass fuels are combusted and
CEMS are used to measure CO2
emissions, the annual volumes of
biogenic and fossil CO2 would be
reported, along with the F-factors and
fuel gross calorific values used in the
calculations, and the biogenic
percentage of the annual CO2 emissions.
Finally, for units that use acid gas
scrubbing with sorbent injection but are
not equipped with CEMS, the owner or
operator would be required to report
information on the type and amount of
sorbent used.
6. Selection of Records That Must Be
Retained
In addition to meeting the general
recordkeeping requirements in proposed
40 CFR part 98, subpart A, whenever
company records are used to estimate
fuel consumption (e.g., when the Tier 1
or 2 emissions calculation methodology
is used) and sorbent consumption, EPA
proposes to require the owner or
operator to keep on file a detailed
explanation of how fuel usage is
quantified, including a description of
the QA procedures that are used to
ensure measurement accuracy (e.g.,
calibration of weighing devices and
other instrumentation).
As discussed in Section IV of this
preamble and proposed 40 CFR part 98,
subpart A, there are a number of
facilities that are not part of a source
category listed in 40 CFR 98.2(1)(a) or
(2) but have stationary combustion
equipment emitting GHG emissions. In
2010, those facilities would have to
determine whether or not they are
subject to the requirements of this rule
(i.e., if their emissions are 25,000 metric
tons CO2e/yr or higher). In order to
reduce the burden on those facilities, we
are proposing that facilities with an
aggregate maximum heat input capacity
of less than 30 mmBtu/hr from
stationary combustion units are
automatically exempt from the proposed
40 CFR part 98. Based on our
assessment of the maximum amount of
GHG emissions likely from units of that
size that burn fossil fuels (e.g, coal, oil
or gas) and operate continuously
through the year, such a facility would
still be below the 25,000 metric tons
CO2e threshold. The purpose for having
this provision is to exempt small
facilities from having to estimate
emissions to determine if they are
subject to the rule, and re-estimate
whenever there are process changes.
D. Electricity Generation
1. Definition of the Source Category
This section of the preamble
addresses GHG emissions reporting for
PO 00000
Frm 00040
Fmt 4701
Sfmt 4702
facilities with EGUs that are in the ARP,
and are subject to the CO2 emissions
reporting requirements of Section 821 of
the CAA Amendments of 1990. All
other facilities using stationary fuel
combustion equipment to generate
electricity should refer to Section V.C of
this preamble (General Stationary Fuel
Combustion Sources) to understand
EPA’s proposed approach for GHG
emissions reporting.
Electricity generating units in the ARP
reported CO2 emissions of 2,262 million
metric tons CO2e in 2006. This
represents almost one third of total U.S.
GHG emissions and over 90 percent of
CO2 emissions from electricity
generation. EPA has been receiving
these CO2 data since 1995.64
2. Selection of Reporting Threshold
If a facility includes within its
boundaries at least one EGU that is
subject to the ARP, the facility would be
subject to the mandatory GHG emissions
reporting of proposed 40 CFR part 98,
subpart D. Facilities with EGUs in the
ARP would not be expected to report
any new CO2 data. Therefore, EPA
expects that the GHG emissions
reporting requirements of this rule
would not be overly burdensome for
facilities already reporting to the ARP.
For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
For ARP units, the CO2 mass
emissions data already reported to EPA
under 40 CFR part 75 would be used in
the annual GHG emissions reports
required under this proposed rule. The
annual CO2 mass emissions (i.e., English
short tons) reported for an ARP unit
would simply be converted to metric
tons and then included in the GHG
emissions report for the facility.
As CH4 and N2O emissions are not
required to be reported under 40 CFR
part 75, the facility would consult the
proposed methods in proposed 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources) for
calculating CH4 and N2O from the ARP
units.
The additional units at an affected
facility that are not in the ARP would
use the GHG calculation methods
specified and required in proposed 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
64 This data can be accessed at: https://epa.gov/
camdataandmaps.
E:\FR\FM\10APP2.SGM
10APP2
16487
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
4. Selection of Procedures for Estimating
Missing Data
The proposed missing data
substitution procedures for CH4 and
N2O emissions from ARP units and all
GHG emissions from units at the facility
not in ARP are discussed in Section
V.C.4 of this preamble, under General
Stationary Fuel Combustion Sources.
5. Selection of Data Reporting
Requirements
The proposed data reporting
requirements are discussed in Section
V.C.5 of this preamble, under General
Stationary Fuel Combustion Sources.
6. Selection of Records That Must Be
Retained
The records that must be retained
regarding CH4 and N2O emissions from
ARP units and all GHG emissions from
units at the facility not in the ARP are
discussed in Section V.C.6 of this
preamble, under General Stationary
Fuel Combustion Sources.
E. Adipic Acid Production
1. Definition of the Source Category
Adipic acid is a white crystalline
solid used in the manufacture of
synthetic fibers, plastics, coatings,
urethane foams, elastomers, and
synthetic lubricants. Commercially, it is
the most important of the aliphatic
dicarboxylic acids, which are used to
manufacture polyesters. Adipic acid is
also used in food applications.
Adipic acid is produced through a
two-stage process. The first stage
usually involves the oxidation of
cyclohexane to form a cyclohexanone/
cyclohexanol mixture. The second stage
involves oxidizing this mixture with
nitric acid to produce adipic acid.
National emissions from adipic acid
production were estimated to be 9.3
million metric tons CO2e (less than 0.1
percent of U.S. GHG emissions) in 2006.
These emissions include both processrelated emissions (N2O) and on-site
stationary combustion emissions (CO2,
CH4, and N2O). The main GHG emitted
from adipic acid production is N2O,
which is generated as a by-product of
the nitric acid oxidation stage of the
manufacturing process, and it is emitted
in the waste gas stream. Process N2O
emissions alone were estimated at 5.9
million metric tons CO2e, or 64 percent
of the total GHG emissions in 2006,
while on-site stationary combustion
emissions account for the remaining 3.4
million metric tons CO2e, or 36 percent
of the total.
Process emissions from the
production of adipic acid vary with the
types of technologies and level of
emission controls employed by a
facility. DE for N2O emissions can vary
from 90 to 98 percent using abatement
technologies such as nonselective
catalytic reduction. In 1998, the three
major adipic acid production facilities
in the U.S. had control systems in place.
Only one small facility, representing
approximately two percent of adipic
acid production, does not control for
N2O.
As part of this proposed rule,
stationary combustion emissions would
be estimated and reported according to
the applicable procedures in proposed
40 CFR part 98, subpart C. For
additional background information on
adipic acid production, please refer to
the Adipic Acid Production TSD (EPA–
HQ–OAR–2008–0508–005).
2. Selection of Reporting Threshold
In developing the threshold for adipic
acid production, we considered
emissions-based thresholds of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Table E–1 of
this preamble illustrates that the various
thresholds do not affect the amount of
emissions or number of facilities that
would be covered.
TABLE E–1. THRESHOLD ANALYSIS FOR ADIPIC ACID PRODUCTION
Emissions covered
Total national
emissions
Threshold level
metric tons CO2e/yr
Total number
of facilities
9,300,000
9,300,000
9,300,000
9,300,000
4
4
4
4
1,000 ....................................................................
10,000 ..................................................................
25,000 ..................................................................
100,000 ................................................................
Facility-level emissions estimates
based on known facility capacities for
the four known adipic acid facilities
suggests that each of the facilities would
be at least five times over the 100,000
metric tons CO2e threshold based on
just process-related emissions. Because
all adipic acid production facilities
would have to report under any of the
emission thresholds that were
examined, we propose that all adipic
acid production facilities be required to
report. This would simplify rule
applicability and avoid any burden for
the source to perform unnecessary
calculations.
For a full discussion of the threshold
analysis, please refer to the Adipic Acid
Production TSD (EPA–HQ–OAR–2008–
0508–005). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Metric tons
CO2e/yr
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating adipic acid production
process emissions (e.g., 2006 IPCC
Guidelines, U.S. Inventory, DOE
1605(b), and TRI). These methodologies
coalesce around the four options
discussed below.
Option 1. Default emission factors
would be applied to total facility
production of adipic acid. The
emissions would be calculated using the
total production of adipic acid and the
highest international default emission
factor available in the 2006 IPCC
Guidelines. This option assumes no
PO 00000
Frm 00041
Fmt 4701
Sfmt 4702
Percent
9,300,000
9,300,000
9,300,000
9,300,000
section 4 of the RIA and the RIA cost
appendix.
Facilities covered
100
100
100
100
Number
Percent
4
4
4
4
100
100
100
100
abatement of N2O emissions. This
approach is consistent with IPCC Tier 1
and the DOE 1605(b) ‘‘C’’ rated
estimation method.
Option 2. Default emission factors
would be applied on a site-specific basis
using the specific type of abatement
technology used and the adipic acid
production activity. The amount of N2O
emissions would be determined by
multiplying the technology-specific
emission factor by the production level
of adipic acid. This approach is
consistent with 1605(b) ‘‘B’’ rated
estimation method, IPCC Tier 2, and
TCR’s ‘‘B’’ rated estimation method.
Option 3. Periodic direct emission
measurement of N2O emissions would
be used to determine the relationship
between adipic acid production and the
amount of N2O emissions; i.e., to
develop a facility-specific emissions
E:\FR\FM\10APP2.SGM
10APP2
16488
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
factor. The facility-specific emissions
factor and production rate (activity
level) would be used to calculate the
emissions. The facility-specific emission
factor would be developed from a single
annual test. Production rate is most
likely already measured at facilities.
Existing procedures would be followed
to measure the production rate during
the performance test and on a quarterly
basis thereafter. After the initial test,
annual testing of N2O emissions would
be required each year to estimate the
emission factor and applied to
production to estimate emissions. The
yearly testing would assist in verifying
the emission factor. Testing would also
be required whenever the production
rate is changed by more than 10 percent
from the production rate measured
during the most recent performance test.
Option 3 and the following Option 4 are
approaches consistent with IPCC Tier 3,
DOE 1605(b) ‘‘A’’ and TCR’s ‘‘A2’’ rated
estimation methods.
Option 4. CEMS would be used to
directly measure the N2O process
emissions. CEMS would be used to
directly measure N2O concentration and
flow rate to directly determine N2O
emissions. Measuring N2O emissions
directly with CEMS is feasible, but
adipic acid production facilities are
currently only using NOX CEMS to
comply with State programs (e.g. Texas).
Half of the adipic acid production
facilities are located in Texas where
NOX CEMS are required in O3
nonattainment areas under Control of
Air Pollution from Nitrogen Compounds
(TX Chap 117 (Reg 7)).
Proposed option: We propose Option
3 to quantify process emissions from all
adipic acid facilities. In addition, you
would be required to follow the
requirements of proposed 40 CFR part
98, subpart C to estimate emissions of
CO2, CH4 and N2O from stationary
combustion.
We identified Options 3 and 4 as the
approaches providing the lowest
uncertainty and the best site-specific
estimates based on differences in
process operation and abatement
technologies. Option 3 requires annual
monitoring of N2O emissions and the
establishment of a facility-specific
emissions factor that relates N2O
emissions with adipic acid production
rate.
Option 4 was not chosen as the
required method because, while N2O
CEMS are available, there is no existing
EPA method for certifying N2O CEMS,
and the cost impact of requiring the
installation of CEMS is high in
comparison to the relatively low amount
of emissions that would be quantified
from the adipic acid production sector.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
NOX CEMS only capture emissions of
NO and NO2 and not N2O. Although the
amount of NOX and N2O emissions from
adipic acid production may be directly
related, direct measurement of NOX
does not automatically correlate to the
amount of N2O in the same exhaust
stream. Periodic testing of N2O
emissions (Option 3) would not indicate
changes in emissions over short periods
of time, but it does offer direct
measurement of GHGs.
We request comment on the
advantages and disadvantages of using
Options 3 and 4. After consideration of
public comments, we may promulgate
one or more of these options or a
combination based on the additional
information that is provided.
We decided against Options 1 and 2
because facility-specific emission
factors are more appropriate for
reflecting differences in process design
and operation. According to IPCC, the
default emission factors for adipic acid
are relatively certain because they are
derived from the stoichiometry of the
chemical reaction employed to oxidize
nitric acid. However, there is still
uncertainty in the amount of N2O that
is generated. This variability is a result
of differences in the composition of
cyclohexanone and cyclohexanol
feedstock. Variability also arises if
adipic acid is produced from use of
other feedstocks, such as phenol or
hydrogen peroxide. Facility-specific
emission factors would be based on
actual feedstock composition rather
than an assumed composition.
The various approaches to monitoring
GHG emissions are elaborated in the
Adipic Acid Production TSD (EPA–HQ–
OAR–2008–0508–005).
4. Selection of Procedures for Estimating
Missing Data
For process sources that use Option 3
(facility-specific emission factor), no
missing data procedures would apply
because the facility-specific emission
factor is derived from an annual
performance test and used in each
calculation. The emission factor would
be multiplied by the production rate,
which is readily available. If the test
data are missing or lost, the test would
have to be repeated. Therefore, 100
percent data availability would be
required.
5. Selection of Data Reporting
Requirements
We propose that facilities submit their
total annual N2O emissions from adipic
acid production, as well as any
stationary fuel combustion emissions. In
addition we propose that facilities
submit the following data, which are the
PO 00000
Frm 00042
Fmt 4701
Sfmt 4702
basis of the calculations and are needed
to understand the emissions data and
verify the reasonableness of the reported
emissions. The data submitted on an
annual basis should include annual
adipic acid production capacity, total
adipic acid production, facility-specific
emission rate factor used, abatement
technology used, abatement technology
efficiency, abatement utilization factor,
and number of facility operating hours
in calendar year.
Capacity, actual production, and
operating hours support verification of
the emissions data provided by the
facility. The production rate can be
determined through sales records or by
direct measurement using flow meters
or weigh scales. This industry generally
measures the production rate as part of
normal operating procedures.
A list of abatement technologies
would be helpful in assessing the
widespread use of abatement in the
adipic acid source category, cataloging
any new technologies that are being
used, and documenting the amount of
time that the abatement technologies are
being used.
A full list of data to be reported is
included in the proposed 40 CFR part
98, subparts A and E.
6. Selection of Records That Must Be
Retained
We propose that facilities maintain
records of annual testing of N2O
emissions, calculation of the facilityspecific emission rate factor, hours of
operation, annual adipic acid
production, adipic acid production
capacity, and N2O emissions. These
records hold values directly used to
calculate the emissions that are reported
and are necessary to allow
determination of whether the GHG
emissions monitoring calculations were
done correctly. A full list of records that
must be retained on site is included in
the proposed 40 CFR part 98, subparts
A and E.
F. Aluminum Production
1. Definition of the Source Category
This source category includes primary
aluminum production facilities.
Secondary aluminum production
facilities would not be required to report
emissions under Subpart F. Aluminum
is a light-weight, malleable, and
corrosion-resistant metal that is used in
manufactured products in many sectors
including transportation, packaging,
building and construction. As of 2005,
the U.S. was the fourth largest producer
of primary aluminum, with
approximately eight percent of the
world total (Aluminum Production TSD
E:\FR\FM\10APP2.SGM
10APP2
16489
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(EPA–HQ–OAR–2008–0508–006)). The
production of primary aluminum—in
addition to consuming large quantities
of electricity—results in process-related
emissions of CO2 and two PFCs:
perfluoromethane (CF4) and
perfluoroethane (C2F6). Only these
process-related emissions are discussed
here. Stationary fuel combustion source
emissions must be monitored and
reported according to proposed 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources), which is
discussed in Section V.C of this
preamble.
CO2 is emitted during the primary
aluminum smelting process when
alumina (aluminum oxide, Al2O3) is
reduced to aluminum using the Hall´
Heroult reduction process. The
reduction of the alumina occurs through
electrolysis in a molten bath of natural
or synthetic cryolite (Na3AlF6). The
reduction cells contain a carbon lining
that serves as the cathode. Carbon is
also contained in the anode, which can
be a carbon mass of paste, coke
briquettes, or prebaked carbon blocks
from petroleum coke. During reduction,
most of the carbon in the anode is
oxidized and released to the atmosphere
as CO2. In addition, a smaller amount of
CO2 is released during the baking of
anodes for use in smelters using prebake
technologies.
In addition to CO2 emissions, the
primary aluminum production industry
is also a source of PFC emissions.
During the smelting process, if the
alumina ore content of the electrolytic
bath falls below critical levels required
for electrolysis, rapid voltage increases
occur, which are termed ‘‘anode
effects.’’ These anode effects cause
carbon from the anode and fluorine
from the dissociated molten cryolite
bath to combine, thereby producing
emissions of CF4 and C2F6. For any
particular individual smelter, the
magnitude of emissions for a given level
of production depends on the frequency
and duration of these anode effects. As
the frequency and duration of the anode
effects increase, emissions increase. In
addition, even at constant levels of
production and anode effect minutes,
emissions vary among smelter
technologies (e.g., Center-Work Prebake
vs. Side-Work Prebake) and among
individual smelters using the same
smelter technology due to differing
operational practices.
Total U.S. Emissions. According to
the U.S. GHG Inventory total processrelated GHG emissions from primary
aluminum production in the U.S. are
estimated to be 6.4 million metric tons
CO2e in 2006. Process emissions of CO2
from the 14 aluminum smelters in the
U.S. were estimated to be 3.9 million
metric tons CO2e in 2006. Process
emissions of CF4 and C2F6 from
aluminum smelters were estimated to be
2.5 million metric tons CO2e in 2006. In
2006, 13 of the 14 primary aluminum
smelters in the U.S. accounted for the
vast majority of primary aluminum
emissions. The remaining smelter was
idle through most of 2006, restarting at
the end of the year.
Emissions to be reported. We propose
to require reporting of the following
types of emissions from primary
aluminum production: Process
emissions of PFCs, process emissions of
CO2 from consumption of the anode
during electrolysis (for both Prebake and
S<derberg cells), and process emissions
of CO2 from the anode baking process
(for Prebake cells only).
Another potential source of process
CO2 emissions is coke calcining. We
request comment on whether any U.S.
smelters operate calcining furnaces and
the extent of these process emissions.
2. Selection of Reporting Threshold
We propose to require all owners or
operators of primary aluminum facilities
to report the total quantities of PFC and
CO2 process emissions. In 2006, 5
companies operated 14 primary
aluminum for at least part of the year.
(One of these smelters operated only
briefly at the end of the year.) All
primary aluminum smelters that
operated throughout 2006 would be
covered at all capacity and emissionsbased thresholds considered in this
analysis.
In developing the threshold for
primary aluminum, we considered the
emissions thresholds 1,000, 10,000,
25,000, and 100,000 metric tons CO2e
per year (metric tons CO2e/yr). These
emissions thresholds translate to 64,
640, 1,594, and 6,378 metric tons
primary aluminum produced,
respectively, based on use of the 2006
IPCC default emission factors and
assuming side-worked prebake cells and
100 percent capacity utilization as
shown in Table F–1 of this preamble.
TABLE F–1. THRESHOLD ANALYSIS FOR ALUMINUM PRODUCTION BASED ON 2006 EMISSIONS AND FACILITY PRODUCTION
CAPACITY
Emissions covered
Emission threshold level metric tons
CO2e/yr
Total national
emissions
1,000 ......................................................
10,000 ....................................................
25,000 ....................................................
100,000 ..................................................
Total number
of facilities
6,402,000
6,402,000
6,402,000
6,402,000
Metric tons
CO2e/yr
14
14
14
14
Facilities covered
Percent
6,402,000
6,397,000
6,397,000
6,397,000
Number
Percent
100
99.9
99.9
99.9
14
13
13
13
100
93
93
93
100
100
100
100
14
14
14
14
100
100
100
100
Production Capacity Threshold metric tons Al/year
64 ...........................................................
640 .........................................................
1,594 ......................................................
6,378 ......................................................
6,402,000
6,402,000
6,402,000
6,402,000
We propose that all primary
aluminum facilities be subject to
reporting. All smelters that operated in
2006 would be required to report if a
10,000, 25,000, or 100,000 metric tons
CO2e per year threshold were used.
Requiring all facilities to report would
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
14
14
14
14
6,402,000
6,402,000
6,402,000
6,402,000
simplify the rule, avoid the need for
facilities to estimate emissions to
determine applicability, and ensure
complete coverage of emissions from
this source category. It results in little
extra burden for the industry since few
if any additional facilities would be
PO 00000
Frm 00043
Fmt 4701
Sfmt 4702
required to report (compared to the
thresholds considered). Significant
fluctuations in capacity utilization do
occur; aluminum smelters sometimes
shut down for long periods. Under the
proposed rule, facilities that did not
operate at all during the previous year
E:\FR\FM\10APP2.SGM
10APP2
16490
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
would still have to submit a report;
however, reporting would be minimal.
(Zero production implies zero
emissions.)
For a full discussion of the threshold
analysis, please refer to the Aluminum
Production TSD (EPA–HQ–OAR–2008–
0508–006). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
This section of this preamble provides
monitoring methods for calculating and
reporting process CO2 and PFC
emissions only. If a facility has
stationary fuel combustion it would
need to also refer to proposed 40 CFR
part 98, subpart C for methods for CO2,
CH4 and N2O and would be required to
follow the calculation procedures,
monitoring and QA/QC methods,
recordkeeping requirements as
described.
Protocols and guidance reviewed for
this analysis include the 2006 IPCC
Guidelines, EPA’s Voluntary Aluminum
Industrial Partnership, the Inventory of
U.S. Greenhouse Gas Emissions and
Sinks, the International Aluminum
Institute’s Aluminum Sector
Greenhouse Gas Protocol, the Technical
Guidelines for the Voluntary Reporting
of Greenhouse Gases (1605(b)) Program,
EPA’s Climate Leaders Program, and
TRI.
The methods described in these
protocols and guidance coalesce around
the methods described by the
International Aluminum Institute’s
Aluminum Sector Greenhouse Gas
Protocol and the 2006 IPCC Guidelines.
These methods range from Tier 1
approaches based on aluminum
production to Tier 3 approaches based
primarily on smelter-specific data. The
IPCC Tier 3 and International
Aluminum Institute methods are
essentially the same.
Proposed Method for Monitoring PFC
Emissions. The proposed method for
monitoring PFC emissions from
aluminum processing is similar to the
Tier 3 approach in the 2006 IPCC
Guidelines for primary aluminum
production. The proposed method
requires smelter-specific data on
aluminum production, anode effect
minutes per cell day (anode effect-mins/
cell-day), and recently measured slope
coefficients. The slope coefficient
represents kg of CF4/metric ton of
aluminum produced divided by anode
effect minutes per cell-day. The cell-day
is the number of cells operating
multiplied by the number of days of
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
operation, per the 2006 IPCC
Guidelines. The following describes
how to calculate CF4 and C2F6 emissions
based on the slope method. CF4
emissions equal the slope coefficient for
CF4 (kg CF4/metric ton Al)/anode effectMins/cell-day) times metal production
(metric tons Al). Annual anode effect
calculations and records should be the
sum of anode effect minutes per cell day
and production by month. C2F6
emissions equal emissions of CF4 times
the weight fraction of C2F6/CF4 (kg C2F6/
kg CF4).
Both the IPCC Tier 3 method and the
less accurate IPCC Tier 2 method are
based on these equations and
parameters. The critical distinction
between the two methods is that the
Tier 3 method requires smelter-specific
slope coefficients while the Tier 2
method relies on default, technologyspecific slope coefficients. Of the
currently operating U.S. smelters, all but
one has measured a smelter-specific
coefficient at least once. However, as
discussed below, some smelters may
need to update these measurements if
they occurred more than 3 years ago.
Use of the Tier 3 approach
significantly improves the precision of a
smelter’s PFC emissions estimate. For
individual facilities using the most
common smelter technology in the U.S.,
the uncertainty (95 percent confidence
interval) of estimates developed using
the Tier 2 approach is ±50 percent,65
while the uncertainty of estimates
developed using the Tier 3 approach is
approximately ±15 percent (Aluminum
Production TSD (EPA–HQ–OAR–2008–
0508–006)). For a typical U.S. smelter
emitting 175,000 metric tons CO2e in
PFCs, these errors result in absolute
uncertainties of ±88,000 metric tons
CO2e and ±26,000 metric tons CO2e,
respectively. The reduction in
uncertainty associated with moving
from the Tier 2 to the Tier 3 approach,
62,000 metric tons CO2e, is as large as
the emissions from many of the sources
that would be subject to the rule. We
concluded the extra burden to facilities
of measuring the smelter-specific slope
coefficients is justified by the
65 The most common smelter technology in the
U.S. is the center-worked prebake technology. The
2006 IPCC Guidelines provide a 95 percent
confidence interval of ±6 percent for the centerworked prebake technology default slope
coefficient. However, this range is not the range
within which the slope coefficient from a single
center-worked prebake technology has a 95 percent
chance of falling. Instead, it is the range within
which the true mean of all center-worked prebake
technology slope factors has a 95 percent chance of
falling. This appears to depart from the usual
convention for expressing the uncertainties related
to the use of default coefficients in the Guidelines.
PO 00000
Frm 00044
Fmt 4701
Sfmt 4702
considerable improvement in the
precision of the reported emissions.
Measurement of Slope Coefficients.
We propose that slope coefficients be
measured using a method similar to the
USEPA/International Aluminum
Institute Protocol for Measurement of
Tetrafluoromethane and
Hexafluoroethane from Primary
Aluminum Production. The protocol
establishes guidelines to ensure that
measurements of smelter-specific slopecoefficients are consistent and accurate
(e.g., representative of typical smelter
operating conditions and emission
rates). These guidelines include
recommendations for documenting the
frequency and duration of anode effects,
measuring aluminum production,
sampling design, measurement
instruments and methods, calculations,
QA/QC, and measurement frequency.
During the past few years, multiple
U.S. smelters have adopted changes to
their production process which are
likely to have changed their slope
coefficients.66 These include the
adoption of slotted anodes and
improvements to process control
algorithms. Although some U.S.
smelters have recently updated their
measurements of smelter-specific
coefficients, others may not have.
We understand that two smelting
companies in the U.S., Rio Tinto Alcan
and Alcoa, have the necessary
equipment and teams in-house to
measure smelter-specific slope factors.
These two companies account for 11 out
of 15 of the operating smelters in the
U.S. The remaining facilities would
need to hire a consultant to conduct a
measurement study once every three
years to accurately determine their slope
coefficients. The cost of hiring a
consultant to conduct the measurement
study is probably significantly lower
than the capital, labor and O&M costs of
the equipment, training, and
maintenance required to conduct the
measurements in-house. While the cost
to implement a Tier 3 approach is
significantly greater than the cost to
implement a Tier 2 approach, the
benefit of reduced uncertainty is
considerable (approximately 40
percent), as noted above.
We request comment on the proposal
that all smelters be required to measure
their smelter-specific slope coefficients
at least once every three years. We
considered, but are not proposing, to
exempt ‘‘high performing’’ smelters, as
defined by the 2006 IPCC Guidelines,
from the requirement to measure their
smelter-specific slope coefficients more
66 Aluminum Production TSD (EPA–HQ–OAR–
2008–0508–006).
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
than once. The Guidelines define ‘‘highperforming’’ smelters as those that
operate with less than 0.2 anode effect
minutes per cell day or less than 1.4
millivolt overvoltage. The Guidelines
state, ‘‘no significant improvement can
be expected in the overall facility GHG
inventory by using the Tier 3 method
rather than the Tier 2 method.’’ (IPCC,
page 4.53, footnote 1). However, EPA
believes there is benefit to EPA and to
industry of periodic evaluation of the
correlation of the smelter-specific slope
coefficient and actual emissions, even in
situations of low anode effect minutes
per cell day or overvoltage.
The Overvoltage Method. Another
Tier 3 method included in the IPCC
Guidelines is the Overvoltage Method.
This method relates PFC emissions to an
overvoltage coefficient, anode effect
overvoltage, current efficiency, and
aluminum production. The overvoltage
method was developed for smelters
using the Pechiney technology. We
request comment on whether any U.S.
smelters are using the Pechiney
technology and, if so, on whether these
smelters should be permitted to use the
Overvoltage Method.
Proposed Method for Monitoring
Process CO2 Emissions. If you are
required to use an existing CEMS to
meet the requirements outlined in
proposed 40 CFR part 98, subpart C, you
would be required to use CEMS to
estimate stationary fuel combustion CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
emissions you would be required to
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of proposed 40 CFR part
98, subpart C to estimate process and
stationary fuel combustion CO2
emissions from the industrial source.
Also, refer to proposed 40 CR part 98,
subpart C to estimate combustionrelated CH4 and N2O.
If your facility does not have
stationary combustion, or if you do not
currently have CEMS that meet the
requirements outlined in proposed 40
CR part 98, subpart C, or where the
CEMS would not adequately account for
process CO2 emissions, the proposed
monitoring method for process CO2
emissions is similar to the IPCC Tier 2
approach, which relies on industry
defaults rather than smelter-specific
values for concentrations of minor
anode components.
CO2 emitted during electrolysis. We
propose to require that CO2 emitted
during electrolysis be calculated based
on metal production and net anode
consumption using a mass balance
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
approach that assumes all carbon from
net anode consumption is ultimately
emitted as CO2. Since the
concentrations of the non-carbon
components are small (typically less
than one percent to five percent),
facility-specific data on them is not as
critical to the precision of emission
estimates as is facility-specific data on
net anode consumption. Tier 3 improves
the accuracy of the results but the
improvement in accuracy is not
expected to exceed 5 percent per the
2006 IPCC Guidelines. Although we do
not propose to require the use of the
Tier 3 approach, we would allow and
encourage smelter operators to use
facility-specific data on anode noncarbon components when that data were
available.
For prebake cells, CO2 emissions are
equal to net prebaked anode
consumption per metric ton aluminum
times total metal production times the
percent weight of sulfur and ash content
in the baked anode times the molecular
mass of CO2.
CO2 emissions from S<derberg cells
are a function of total metal production,
paste consumption, emissions of
cyclohexane soluble matter, percent
binder and sulfur content in paste,
percent ash and hydrogen content in
pitch, percent weight of sulfur and ash
content in calcined coke, carbon in
skimmed dust from S<derberg cells, and
the carbon atomic mass ratio.
The data reported by companies
participating in EPA’s Voluntary
Aluminum Industrial Partnership has
generally not included smelter-specific
values for each of these variables.
However, most participants in the
Voluntary Aluminum Industrial
Partnership have used either data on
paste consumption (for S<derberg cells)
or on net anode consumption (for
Prebake cells), along with some smelterspecific data on impurities, to develop
a hybrid IPCC Tier 2/3 estimate (i.e.,
combination of smelter-specific and
default factors).
CO2 emitted during anode baking. We
propose that CO2 emitted during anode
baking be calculated based on a mass
balance approach involving chemical
contents of the anodes and packing
materials. No anode baking emissions
occur when using S<derberg cells, since
these cells are not baked before
aluminum smelting, but rather, bake in
the electrolysis cell during smelting.
CO2 emissions from pitch volatiles
combustion equal the initial weight
from green anode minus hydrogen
content minus baked anode production
minus waste tar collected times the
molecular weight of CO2. CO2 emissions
from bake furnace packing material are
PO 00000
Frm 00045
Fmt 4701
Sfmt 4702
16491
a function of packing coke consumption
times baked anode production times the
percent weight sulfur and ash content in
packing coke.
As is the case for CO2 emitted during
electrolysis, the IPCC Tier 2 approach
for anode baking relies on industry-wide
defaults for minor anode components,
requiring smelter-specific data only for
the initial weight of green anodes and
for baked anode production. The IPCC
Tier 3 approach requires smelterspecific values for all parameters. Again,
the concentrations of minor components
are small, limiting their impact on the
estimate of CO2 emissions from anode
baking. In addition, anode baking
emissions account for approximately 10
percent of total CO2 process emissions,
so reducing the uncertainty in this
estimate would have only a minor
impact on the overall CO2 process
estimate. For EPA’s Voluntary
Aluminum Industrial Partnership
program, many smelters report only
some smelter-specific values for the
concentrations of minor anode
components. In light of these
considerations, we propose to require
the Tier 2 method for estimating CO2
emissions from anode baking, with the
option to use facility-specific data on
impurity concentrations when that data
is available.
Other Options Considered. We are not
proposing IPCC’s Tier 1 methodology
for calculating PFC emissions. Although
this methodology is simple, the default
emission factors for PFCs have large
uncertainties due to the variability in
anode effect frequency and duration.
Since 1990, all U.S. smelters have
sharply reduced their anode effect
frequency and duration; through 2006,
average anode minutes per cell day have
declined by approximately 85 percent,
lowering U.S. smelter emission rates
well below those of the IPCC Tier 1
defaults. Consequently, as discussed
above, the Tier 3 methodology has been
proposed.
For CO2, we are not proposing IPCC’s
Tier 1 methodology for calculating
emissions. The difference in uncertainty
between emission estimates developed
using IPCC Tier 1 and Tier 2/3
approaches for U.S. smelters is notably
lower than the difference for the PFC
estimates. However, as part of typical
operations, facilities regularly monitor
inputs to higher Tier methods (e.g.,
consumption of anodes); consequently,
the incremental cost to use the IPCC
Tier 2 or a Tier 2/3 hybrid estimate are
small.
E:\FR\FM\10APP2.SGM
10APP2
16492
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
4. Selection of Procedures for Estimating
Missing Data
Where anode effect minutes per cell
day data points are missing, the average
anode effect minutes per cell day of the
remaining measurements within the
same reporting period may be applied.
These parameters are typically logged
by the process control system as part of
the operations of nearly all aluminium
production facilities and the
uncertainties in these data are low.
It is likely that aluminum production
levels would be well known, since
businesses rely on accurate monitoring
and reporting of production levels. The
2006 IPCC Guidelines specify an
uncertainty of less than 1 percent in the
data for the annual production of
aluminum. The likelihood for missing
data is low.
For CO2 emissions, the uncertainty in
recording anode consumption as baked
anode consumption or coke
consumption is estimated to be only
slightly higher than for aluminium
production, less than 2 percent per the
2006 IPCC Guidelines. This is also an
important parameter in smelter
operations and is routinely/
continuously monitored. Again, the
likelihood for missing data is low.
5. Selection of Data Reporting
Requirements
In addition to annual GHG emissions
data, facilities would be required to
submit annual aluminum production
and smelter technology used. The
following PFC-specific information
would also be required to be reported on
an annual basis: Anode effect minutes
per cell-day, and anode effect frequency
and duration. Smelters would also be
required to submit smelter-specific
slope coefficient; the last date when
smelter-specific slope coefficient was
measured; certification that
measurements of slope coefficients were
conducted in accordance with the
method identified in proposed 40 CFR
part 98, subpart F; and the parameters
used by the smelter to measure the
frequency and duration of anode effects.
The following CO2-specific
information would be reported on an
annual basis: Anode consumption for
pre-bake cells, paste consumption for
S<derberg cells, and smelter-specific
inputs to the CO2 process equations
(e.g., levels of impurities) that were used
in the calculation. Exact data elements
required would vary depending on
smelter technology.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
These records consist of values that
are used to calculate the emissions and
are necessary to enable verification that
the GHG emissions monitoring and
calculations were done correctly.
6. Selection of Records That Must Be
Retained
In addition to the data reported, we
propose that facilities maintain records
on monthly production by smelter,
anode effect minutes per cell-day or
anode effect overvoltage by month,
facility specific emission coefficient
linked to anode effect performance, and
net anode consumption for Prebake cells
or paste consumption for S<derberg
cells.
These records consist of data that
would be used to calculate the GHG
emissions and are necessary to verify
that the emissions monitoring and
calculations are done correctly.
G. Ammonia Manufacturing
1. Definition of the Source Category
Ammonia is a major industrial
chemical that is mainly used as
fertilizer, directly applied as anhydrous
ammonia, or further processed into
urea, ammonium nitrates, ammonium
phosphates, and other nitrogen
compounds. Ammonia also is used to
produce plastics, synthetic fibers and
resins, and explosives.
Ammonia can be produced through
three processes: Steam reforming, solid
fuel gasification, and brine electrolysis.
The production of ammonia typically
uses conventional steam reforming or
solid fuel gasification and generates
both combustion and process-related
greenhouse gas emissions. The
production of ammonia through the
brine electrolysis process does not
produce process GHG emissions,
although it releases GHGs from
combustion of fuels to support the
electrolysis process. We have not
identified any facilities in the U.S.
producing ammonia through the brine
electrolysis process.
Catalytic steam reforming of ammonia
generates process-related CO2, primarily
through the use of natural gas as a
feedstock. One plant located in Kansas
is manufacturing ammonia from
petroleum coke feedstock. This and
other natural gas-based and petroleum
coke-based feedstock processes produce
CO2 and hydrogen, the latter of which
is used in the manufacture of ammonia.
Not all of the CO2 produced in the
manufacture of ammonia is emitted
directly to the atmosphere. Both
PO 00000
Frm 00046
Fmt 4701
Sfmt 4702
ammonia and CO2 are used as raw
materials in the production of urea
(CO(NH2)2), which is another type of
nitrogenous fertilizer that contains
carbon (C) and nitrogen (N). The carbon
from ammonia production that is used
to manufacture urea is assumed to be
released into the environment as CO2
during urea use. Therefore, the majority
of CO2 emissions associated with urea
consumption are those that result from
its use as a fertilizer. For CO2 collected
and used onsite or transferred offsite,
you must follow the methodology
provided in proposed 40 CFR part 98,
subpart PP (Suppliers of CO2).
Some facilities produce for sale a
combination of ammonia, methanol, and
hydrogen. We propose that facilities
report their process-related GHG
emissions in the source category
corresponding to the primary NAICS
code for the facility. For example, a
facility that primarily produces
ammonia but also produces methanol
would report in the ammonia
manufacturing source category. Since
CO2 is used to produce methanol, it
does not get emitted directly into the
atmosphere. These facilities would
account for the CO2 used to produce
methanol through the methodology
provided in proposed 40 CFR part 98,
subpart G (Ammonia Manufacturing).
National emissions from ammonia
manufacturing were estimated to be 14.6
million metric tons CO2 equivalent
(<0.25 percent of U.S. GHG emissions in
2006). These emissions include both
process related CO2 emissions and onsite stationary combustion emissions
(CO2, CH4, and N2O) from 24
manufacturing facilities across the U.S.
Process-related emissions account for
7.6 million metric tons CO2, or 52
percent of the total, while on-site
stationary combustion emissions
account for the remaining 7.0 million
metric tons CO2 equivalent emissions.
For additional background
information on ammonia
manufacturing, please refer to the
Ammonia Manufacturing TSD (EPA–
HQ–OAR–2008–0508–007).
2. Selection of Reporting Threshold
In developing the reporting threshold
for ammonia manufacturing, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Table G–1 of
this preamble illustrates the emissions
and facilities that would be covered
under these various thresholds.
E:\FR\FM\10APP2.SGM
10APP2
16493
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE G–1. THRESHOLD ANALYSIS FOR AMMONIA MANUFACTURING
Emissions covered
Total national
emissions
Threshold level metric tons CO2e/yr
Total number
of facilities
14,543,007
14,543,007
14,543,007
14,543,007
24
24
24
24
1,000 ....................................................................................
10,000 ..................................................................................
5,000 ....................................................................................
100,000 ................................................................................
Facility-level emissions estimates
based on known plant capacities suggest
that all known facilities, except two,
exceed the 100,000 metric tons CO2e
threshold. Where information was
available, emission estimates were
adjusted to account for CO2
consumption during urea production,
and this was taken into account in the
threshold analysis. In order to simplify
the proposed rule and avoid the need
for the source to calculate and report
whether the facility exceeds the
threshold value, we propose that all
ammonia manufacturing facilities are
required to report.
For a full discussion of the threshold
analysis, please refer to the Ammonia
Manufacturing TSD (EPA–HQ–OAR–
2008–0508–007). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
monitoring guidelines and protocols
include methodologies for estimating
both combustion and process-related
emissions from ammonia manufacturing
(e.g., 2006 IPCC Guidelines, U.S.
Inventory, DOE 1605(b), and TCR).
These methodologies coalesce around
the following four options which we
considered for quantifying emissions
from ammonia manufacture:
Option 1. The first method found in
existing protocols estimates emissions
by applying a default emission factor to
total ammonia produced. This approach
estimates only process-related
emissions. This approach is consistent
with IPCC Tier 1 and DOE 1605(b) ‘‘C’’
rated estimation methods.
Option 2. A second method consists
of performing a mass balance
calculation using default carbon content
values for feedstock (from the U.S.
DOE). Using default carbon content for
fuel would not provide the same level
of accuracy as using facility-specific
carbon contents. This approach is
consistent with IPCC Tier 2, DOE
1605(b) and TCR’s ‘‘B’’ rated estimation
methods.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Metric tons
CO2e/yr
14,543,007
14,543,007
14,543,007
14,449,519
Option 3. The third option is based on
the IPCC Tier 3 method for determining
CO2 emissions from ammonia
manufacture. This method calculates
emissions based on the monthly
measurements of the total feedstock
consumed (quantity of natural gas or
other feedstock) and the monthly carbon
content of the feedstock. All carbon in
the feedstock is assumed to be oxidized
to CO2. The accuracy and certainty of
this approach is directly related to the
accuracy of the feedstock usage and the
carbon content of the feedstock. If the
measurements or readings are made and
verified according to established QA/QC
methods, the resulting emission
calculations are as accurate as possible.
For CO2 collected and used onsite or
transferred offsite, you must follow the
methodology provided in proposed 40
CFR part 98, subpart PP of this part
(Suppliers of CO2). This approach is
also consistent with DOE’s 1605(b) ‘‘A’’
rated method and TCR’s ‘‘A2’’ rated
estimation methods.
Option 4. The fourth option is using
CEMS to directly measure CO2
emissions. While this method does tend
to provide the most accurate emissions
measurements, it is likely the costliest
of all the monitoring methods.
Proposed Option. Under the proposed
rule, if you are required to use an
existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98,
subpart C and the CEMS capture all
combustion- and process-related CO2
emissions you would be required to
follow requirements of proposed 40 CFR
part 98, subpart C to estimate CO2
emissions from the industrial source.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS does not
measure CO2 process emissions, the
proposed monitoring method is Option
3. You would be required to follow the
requirements of proposed 40 CFR part
98, subpart C to estimate CO2, CH4 and
N2O emissions from stationary
combustion.
The proposed monitoring method is
Option 3. Options 3 and 4 provide the
most accurate estimates from site-
PO 00000
Frm 00047
Fmt 4701
Sfmt 4702
Percent
100
100
100
99
Facilities covered
Number
24
24
24
22
Percent
100
100
100
92
specific conditions. Option 3 is
consistent with current feedstock
monitoring practices at facilities within
this industry, thereby minimizing costs.
For CO2 collected and used onsite or
transferred offsite, you must follow the
methodology provided in proposed 40
CFR part 98, subpart PP (Suppliers of
CO2).
In general, we decided against
existing methodologies that relied on
default emission factors or default
values for carbon content of materials
because the differences among facilities
could not be discerned, and such
default approaches are inherently
inaccurate for site-specific
determinations. The use of default
values is more appropriate for sectorwide or national total estimates from
aggregated activity data than for
determining emissions from a specific
facility.
The various approaches to monitoring
GHG emissions are elaborated in the
Ammonia Manufacturing TSD (EPA–
HQ–OAR–2008–0508–007).
4. Selection of Procedures for Estimating
Missing Data
The proposed rule requires the use of
substitute data whenever a qualityassured value of a parameter that is used
to calculate GHG emissions is
unavailable, or ‘‘missing.’’ For missing
feedstock supply rates, use the lesser of
the maximum supply rate that the unit
is capable of processing or the
maximum supply rate that the meter can
measure. There are no missing data
procedures for carbon content. A re-test
must be performed if the data from any
monthly measurements are determined
to be invalid.
5. Selection of Data Reporting
Requirements
We propose that facilities that
estimate their process CO2 emissions
under proposed 40 CFR part 98, subpart
G, submit their process CO2 emissions
data and the following additional data
on an annual basis. These data are the
basis for calculations and are needed for
us to understand the emissions data and
verify the reasonableness of the reported
emissions. We propose facilities submit
E:\FR\FM\10APP2.SGM
10APP2
16494
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the following data on an annual basis
for each process unit: The total quantity
of feedstock consumed for ammonia
manufacturing, the monthly analyses of
carbon content for each feedstock used
in ammonia manufacturing. A full list of
data to be reported is included in
proposed 40 CFR part 98, subparts A
and G.
6. Selection of Records That Must Be
Retained
We propose that each ammonia
manufacturing facility maintain records
of monthly carbon content analyses, and
the method used to determine the
quantity of feedstock used. These
records consist of values that are
directly used to calculate the emissions
that are reported and are necessary to
enable verification that the GHG
emissions monitoring and calculations
were done correctly.
H. Cement Production
1. Definition of the Source Category
Hydraulic Portland cement, the
primary product of the cement industry,
is a fine gray or white powder produced
by heating a mixture of limestone, clay,
and other ingredients at high
temperature. Limestone is the single
largest ingredient required in the
cement-making process, and most
cement plants are located near large
collection equipment and can either be
limestone deposits. CO2 from the
recycled back to the kiln or be sent
chemical process of cement production
offsite for disposal, depending on its
is the second largest source of industrial quality. Organic carbon in raw materials
CO2 emissions in the U.S.
is also emitted as CO2 as raw material
During the cement production
is heated.
process, calcium carbonate (CaCO3)
National GHG emissions from cement
(usually from limestone and chalk) is
production were estimated to be 86.83
combined with silica-containing
million metric tons CO2e in 2006. These
materials (such as sand and shale) and
emissions include both process-related
is heated in a cement kiln at a
emissions (CO2) and on-site stationary
temperature of about 1,450 °C (2,400 °F). combustion emissions (CO , CH , and
2
4
The CaCO3 forms calcium oxide (or
N2O) from 107 cement production
CaO) and CO2 in a process known as
facilities. Process-related emissions
calcination or calcining. Very small
account for over half of emissions (45.7
amounts of carbonates other than
million metric tons CO2), while on-site
CaCO3, such as magnesium carbonates
stationary combustion emissions
and non-carbonate organic carbon may
account for the remaining 41.1 million
also be present in the raw materials,
metric tons CO2e emissions.
both of which contribute to generation
For additional background
of additional CO2. The product from the
information on cement production,
cement kiln is clinker, an intermediate
please refer to the Cement Production
product, and the CO2 generated as a byTSD (EPA–HQ–OAR–2008–0508–008).
product. The CO2 is released to the
atmosphere.
2. Selection of Reporting Threshold
Additional CO2 emissions are
In developing the threshold for
generated with the formation of partially
cement manufacturing, we considered
calcinated cement kiln dust. During
emissions-based thresholds of 1,000
clinker production, some of the clinker
metric tons CO2e, 10,000 metric tons
precursor materials (instead of forming
CO2e, 25,000 metric tons CO2e, and
clinker) are entrained in the flue gases
100,000 metric tons CO2e. Table H–1 of
exiting the kiln as non-calcinated,
this preamble illustrates the emissions
partially calcinated, or fully calcinated
cement kiln dust 67. Cement Kiln Dust is and facilities that would be covered
under these thresholds.
collected from the flue gas in dust
TABLE H–1. THRESHOLD ANALYSIS FOR CEMENT MANUFACTURING
Total
national
emissions
(MMTCO2e)
Threshold level metric tons CO2e/yr
1,000 ............................................................................
10,000 ..........................................................................
25,000 ..........................................................................
100,000 ........................................................................
All emissions thresholds examined
covered over 99.9 percent of CO2e
emissions from cement facilities. Only
one plant out of 107 in the dataset
would be excluded by a 100,000 metric
tons CO2e threshold. All facilities would
be included under a 25,000 metric tons
CO2e threshold. Therefore, EPA is
proposing that all cement production
facilities are required to report. Having
no threshold covers all of the cement
production process emissions without
Emissions Covered
Total number
of facilities
86.83
86.83
86.83
86.83
Million
metric tons
CO2e/yr
107
107
107
107
increasing the number of facilities that
must report and simplifies the rule.
For a full discussion of the threshold
analysis, please refer to the Cement
Production TSD (EPA–HQ–OAR–2008–
0508–008). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
86.83
86.83
86.83
86.74
Percent
100
100
100
99.9
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00048
Fmt 4701
Sfmt 4702
Number
Percent
107
107
107
106
100
100
100
99.9
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from cement manufacturing (e.g., the
2006 IPCC Guidelines, U.S. Inventory,
DOE 1605(b), CARB mandatory GHG
emissions reporting program, EPA’s
Climate Leaders, the EU Emissions
Trading System, and the Cement
Sustainability Initiative Protocol). These
67 Cement Production TSD (EPA–HQ–OAR–
2008–0508–008).
VerDate Nov<24>2008
Facilities Covered
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
methodologies coalesce around four
different options.
Option 1. Apply a default emission
factor to the total quantity of clinker
produced at the facility. The quantity of
clinker produced could be directly
measured, or a clinker fraction could be
applied to the total quantity of cement
produced.
Option 2. Apply site-specific emission
factors to the quantity of clinker
produced.
Option 3. Measure the carbonate
inputs to the furnace. Under this ‘‘kiln
input’’ approach, emissions are
calculated by weighing the mass of
individual carbonate species sent to the
kiln, multiplying by the emissions factor
(relating CO2 emissions to carbonate
content in the kiln feed), and
subtracting for uncalcined cement kiln
dust.
Option 4. Direct measurement of
emissions using CEMS.
Proposed Option. Based on the
agency’s review of the above
approaches, we propose two different
methods for quantifying GHG emissions
from cement manufacturing, depending
on current emissions monitoring at the
facility.
CEMS Method. Under the proposed
rule, if you are required to use an
existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, you would be required to use
CEMS to estimate CO2 emissions. Where
the CEMS capture all combustion- and
process-related CO2 emissions you
would be required to follow the
requirements of proposed 40 CFR part
98, subpart C to estimate all CO2
emissions from the industrial source.
Also, refer to proposed 40 CFR part 98,
subpart C (discussed in Section V.C of
this preamble) to estimate combustionrelated CH4 and N2O.
Calculation Method (Option 2). For
facilities that do not currently have
CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS would
not adequately account for process
emissions, we propose that these
facilities calculate emissions following
Option 2 outlined below. You would be
required to follow the requirements of
proposed 40 CFR part 98, subpart C to
estimate emissions of CO2, CH4 and N2O
from stationary combustion. The cement
production section provides only those
procedures for calculating and reporting
process-related emissions.
Under Option 2, we propose that
facilities develop facility-specific
emission factors relating CO2 emissions
to clinker production for each
individual kiln. The emission factor
relating CO2 emissions to clinker
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
production would be based on the
percent of measured carbonate content
in the clinker (measured on a monthly
basis) and the fraction of calcination
achieved. The clinker emission factor is
then multiplied by the monthly clinker
production to estimate monthly processrelated CO2 emissions from cement
production. Annual emissions are
calculated by summing CO2 emissions
over 12 months across all kilns at the
facility.
Most current protocols propose this
method, but allow facilities to apply a
national default emission factor. We
propose the development of a facilityspecific emission factor based on the
understanding that facilities analyze the
carbonate contents of their raw
materials to the kiln on a frequent basis,
either on a daily basis or every time
there is a change in the raw material
mix.
Cement Kiln Dust. The CO2 emissions
attributable to calcined material in the
cement kiln dust not recycled back to
the kiln must be added to the estimate
of CO2 emissions from clinker
production. To establish a cement kiln
dust adjustment factor, we propose that
facilities conduct a chemical analysis on
a quarterly basis to estimate the plantspecific fraction of uncalcined carbonate
in the cement kiln dust from each kiln,
that is not recycled to the kiln each
quarter. Again, this method provides
reasonable accuracy and is highly
consistent with the prevailing methods
presented in existing protocols.
TOC Content in Raw Materials. The
CO2 emissions attributable to the TOC
content in raw material must be added
to the estimate of CO2 emissions from
clinker production and cement kiln
dust. We propose that facilities conduct
an annual chemical analysis to
determine the organic content of the raw
material on an annual basis. The
emissions are calculated from the TOC
content by multiplying the organic
content by the amount of raw material
consumed annually.
Other Options Considered. We
considered three alternative options to
estimate process-related emissions from
cement production. The first method
considered was to apply default
emission factors to clinker production
(either based on measurement of
clinker, or by applying a clinker fraction
to cement production). Applying default
emission factors to clinker production is
one of the most common approaches in
existing protocols. However, we have
determined that applying default
emission factors to clinker production is
more appropriate for national-level
emissions estimates than facilityspecific estimates, where data are
PO 00000
Frm 00049
Fmt 4701
Sfmt 4702
16495
readily available to develop site-specific
emission factors.
In some protocols, this method
requires correcting for purchases and
sales of clinker, such that a facility is
only accounting for emissions from the
clinker that is manufactured on site.
This approach provides better emissions
data than protocols where the method
does not correct for clinker purchases
and sales. In some protocols, the
method requires reporters to start with
cement production, estimate the clinker
fraction, and then estimate the
carbonate input used to produce the
clinker. Conceptually, this might not be
any different than the kiln input
approach as the facility would
ultimately have to identify and quantify
the carbonate inputs to the kiln.
The kiln input approach was
considered, but not proposed, because it
would not lead to significantly reduced
uncertainty in the emissions estimate
over the clinker based approach, where
a site-specific emission factor is
developed using periodic sampling of
the carbonate mix into the kiln. The
primary difference is the proposed
clinker-based approach requires a
monthly analysis of the degree of
calcination achieved in the clinker in
order to develop the facility-specific
emissions factor, whereas the kiln input
approach would require monthly
monitoring of the inputs and outputs of
the kiln. We concluded that although
the kiln input does not improve
certainty estimates significantly, it
could potentially be more costly
depending on the carbonate input
sampling frequency.
Early domestic and international
guidance documents for estimating
process CO2 emissions from cement
production offered the option of
applying a default emission factor to
cement production (e.g. IPCC Tier 1,
DOE 1605(b) ‘‘C’’ rated approach). This
is no longer considered an acceptable
method in national inventories therefore
we did not consider it further for
developing a mandatory GHG reporting
rule.
The various approaches to monitoring
GHG emissions are elaborated in the
Cement Production TSD (EPA–HQ–
OAR–2008–0508–008).
4. Selection of Procedures for Estimating
Missing Data
For facilities with CEMs, we propose
that facilities follow the missing data
procedures in proposed 40 CFR part 98,
subpart C, which are also discussed in
Section V.C of this preamble.
For facilities without CEMs, we
propose that no missing data procedures
would apply because the emission
E:\FR\FM\10APP2.SGM
10APP2
16496
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
factors used to estimate CO2 emissions
from clinker and cement kiln dust
production are derived from routine
tests of carbonate contents. In the event
data on carbonate content analysis is
missing we propose that the facility
undertake a new analysis of carbonate
contents. We are not proposing any
missing data allowance for clinker and
cement kiln dust production data. The
likelihood for missing input, clinker and
cement kiln dust production data is low,
as businesses closely track their
purchase of production inputs, quantity
of clinker produced, and quantity of
cement kiln dust discarded.
5. Selection of Data Reporting
Requirements
We propose that facilities submit
annual CO2 emissions from cement
production, as well as any stationary
fuel combustion emissions. In addition,
facilities using CEMS would be required
to follow the data reporting
requirements in proposed 40 CFR part
98, subpart C. Facilities using the
clinker-based approach would be
required to report annual clinker
production, annual cement kiln dust
production, number of kilns, sitespecific clinker emission factor, the total
annual fraction of cement kiln dust
recycled to the kiln, and the quantity of
CO2 captured for use and the end use,
if known. In addition, we propose that
facilities submit their annual analysis of
carbonate composition, the total annual
fraction of calcination achieved (for
each carbonate), organic carbon content
of the raw material, and the amount of
raw material consumed annually. These
data, used as the basis of the
calculations, are needed for EPA to
understand the emissions data and
verify reasonableness of the reported
emissions. A full list of data to be
reported is included in proposed 40
CFR part 98, subparts A and H.
6. Selection of Records That Must Be
Retained
In addition to the data reported, we
propose that facilities using the clinkerbased approach to calculate emissions
keep records of monthly carbonate
consumption, monthly cement
production, monthly clinker
production, results from monthly
chemical analysis of carbonates,
documentation of calculated site
specific clinker emission factor,
quarterly cement kiln dust production,
total annual fraction calcination
achieved, organic carbon content of the
raw material, and the amount of raw
material consumed annually. These
records include values directly used to
calculate the reported emissions; and
these records are necessary to verify the
estimated GHG emissions. A full list of
records that must be retained onsite is
included in proposed 40 CFR part 98,
subparts A and H.
I. Electronics Manufacturing
1. Definition of the Source Category
such as PFCs, HFCs, SF6, and NF3
during manufacturing of
semiconductors, liquid crystal displays
(LCDs), microelectrical mechanical
systems (MEMs), and photovoltaic cells
(PV). We are also seeking comment
below on the inclusion of light-emitting
diodes (LEDs), disk readers and other
products as part of the electronics
manufacturing source category.
The fluorinated gases (at room
temperature) are used for plasma
etching of silicon materials and cleaning
deposition tool chambers. Additionally,
semiconductor manufacturing employs
fluorinated GHGs (typically liquids at
room temperature) as heat transfer
fluids. The most common fluorinated
GHGs in use are HFC–23, CF4, C2F6, NF3
and SF6, although other compounds
such as perfluoropropane (C3F8) and
perfluorocyclobutane (c-C4F8) are also
used (EPA, 2008a).
Electronics manufacturers may also
use N2O as the oxygen source for
chemical vapor deposition of silicon
oxynitride or silicon dioxide. Besides
dielectric film etching and chamber
cleaning, much smaller quantities of
fluorinated gases are used to etch
polysilicon films and refractory metal
films like tungsten. Table I–1 of this
preamble presents the fluorinated GHGs
typically used during manufacture of
each of these electronics devices.
The electronics industry uses
multiple long-lived fluorinated GHGs
TABLE I–1. FLUORINATED GHGS USED BY THE ELECTRONICS INDUSTRY
Product type
Fluorinated GHGs used during manufacture
Electronics (e.g., Semiconductor, MEMS, LCD, PV) ..
CF4, C2F6, C3F8, c–C4F8, c–C4F8O, C4F6, C5F8, CHF3, CH2F2, NF3, SF6, and Heat Transfer Fluids (CF3–(O–CF(CF3)–CF2)n–(O–CF2)m–O–CF3, CnF2n+2, CnF2n+1(O)
CmF2m+1, CnF2nO, (CnF2n+1)3N)a.
a IPCC Guidelines do not specify the fluorinated GHGs used by the MEMs industry. Literature reviews revealed that CF , SF , and the Bosch
4
6
process (consisting of alternating steps of SF6 and c–C4F8) are used to manufacture MEMs. For further information, see the Electronics Manufacturing TSD (EPA–HQ–OAR–2008–0508–009).
The etching process uses plasmagenerated fluorine atoms, which
chemically react with exposed dielectric
film to selectively remove the desired
portions of the film. The material
removed as well as undissociated
fluorinated gases flow into waste
streams and, unless emission control
systems are employed, into the
atmosphere.
Chambers used for depositing
dielectric films are cleaned periodically
using fluorinated and other gases.
During the cleaning cycle the gas is
converted to fluorine atoms in plasma,
which etches away residual material
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
from chamber walls, electrodes, and
chamber hardware. Undissociated
fluorinated gases and other products
pass from the chamber to waste streams
and, unless emission control systems
are employed, into the atmosphere.
In addition to emissions of unreacted
gases, some fluorinated compounds can
also be transformed in the plasma
processes into different fluorinated
GHGs which are then exhausted, unless
abated, into the atmosphere. For
example, when C2F6 is used in cleaning
or etching, CF4 is generated and emitted
as a process by-product.
PO 00000
Frm 00050
Fmt 4701
Sfmt 4702
Fluorinated GHG liquids (at room
temperature) such as fully fluorinated
linear, branched or cyclic alkanes,
ethers, tertiary amines and aminoethers,
and mixtures thereof are used as heat
transfer fluids at several semiconductor
facilities to cool process equipment,
control temperature during device
testing, and solder semiconductor
devices to circuit boards. The
fluorinated heat transfer fluid’s high
vapor pressures can lead to evaporative
losses during use.68 We are seeking
comment on the extent of use and
68 Electronics Manufacturing TSD (EPA–HQ–
OAR–2008–0508–009); 2006 IPCC Guidelines.
E:\FR\FM\10APP2.SGM
10APP2
16497
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
annual replacement quantities of
fluorinated liquids as heat transfer
fluids in other electronics sectors, such
as their use for cooling or cleaning
during LCD manufacture.
Total U.S. Emissions. Emissions of
fluorinated GHGs from an estimated 216
electronics facilities were estimated to
be 6.1 million metric tons CO2e in 2006.
Below is a breakdown of emissions by
electronics product type.
Semiconductors. Emissions of
fluorinated GHGs, including heat
transfer fluids, from 175 semiconductor
facilities were estimated to be 5.9
million metric tons CO2e in 2006. Of the
total estimated semiconductor
emissions, 5.4 million metric tons CO2e
are from etching/chamber cleaning and
0.5 million metric tons CO2e are from
heat transfer fluid usage. Partners of the
PFC Reduction/Climate Partnership for
Semiconductors comprise
approximately 80 percent of U.S.
semiconductor production capacity.
These partners have committed to
reduce their emissions (exclusive of
heat transfer fluid emissions) to 10
percent below their 1995 levels by 2010,
and their emissions have been on a
general decline toward attainment of
this goal since 1999.
MEMs. Emissions of fluorinated GHGs
from 12 facilities were estimated to be
0.03 million metric tons CO2e in 2006.
LCDs. Emissions of fluorinated GHGs
from 9 facilities were estimated to be
0.02 million metric tons CO2e in 2006.
PVs. Emissions of fluorinated GHGs
from 20 PV facilities were estimated to
be 0.07 million metric tons CO2e in
2006. We request comment on the
number and capacity of thin film (i.e.,
amorphous silicon) and other PV
manufacturing facilities in the U.S.
using fluorinated GHGs.
Emissions To Be Reported. This
section details our proposed
requirements for reporting fluorinated
GHG and N2O emissions from the
following processes and activities:
(1) Plasma etching;
(2) Chamber cleaning;
(3) Chemical vapor deposition using
N2O as the oxygen source; and
(4) Heat transfer fluid use.
Our understanding is that only
semiconductor facilities use heat
transfer fluids; we request comment on
this assumption.
For additional background
information on the electronics industry,
refer to the Electronics Manufacturing
TSD (EPA–HQ–OAR–2008–0508–009).
2. Selection of Reporting Threshold
For manufacture of semiconductors,
LCDs, and MEMs, we are proposing
capacity-based thresholds equivalent to
an annual emissions threshold of 25,000
metric tons CO2e. For manufacture of
PVs for which we have less information
on use and emissions of fluorinated
GHGs, we are proposing an emissions
threshold of 25,000 metric tons of CO2e.
We are seeking comment on the
inclusion of LEDs, disk readers and
other products in the electronics
manufacturing source category. Given
that the manufacturing process for these
devices is similar to other electronics,
we are specifically interested in seeking
feedback on the level of emissions from
their manufacturer and whether
subjecting these products to an
emissions threshold of 25,000 metric
ton CO2e would be appropriate.
In our analysis, we considered
emission thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000
metric tons CO2e, and 100,000 metric
tons CO2e per year. Table I–2 of this
preamble shows emissions and facilities
that would be captured by the
respective emissions thresholds.
TABLE I–2. THRESHOLD ANALYSIS FOR ELECTRONICS INDUSTRY
Emissions covered
Emission threshold level metric tons
CO2e/yr
Total national
emissions
1,000 ......................................................
10,000 ....................................................
25,000 ....................................................
100,000 ..................................................
Total number
of facilities
5,984,462
5,984,462
5,984,462
5,984,462
We selected the 25,000 metric tons
CO2e per year threshold because this
threshold maximizes emissions
reporting, while excluding small
facilities that do not contribute
significantly to the overall GHG
emissions.
We propose to use a production-based
threshold based on the rated capacities
of facilities, as opposed to an emissionsbased threshold, where possible,
because it simplifies the applicability
Metric tons
CO2e/yr
216
216
216
216
Percent
5,972,909
5,840,411
5,708,283
4,708,283
determination. Therefore, we derived
production capacity thresholds that are
approximately equivalent to metric tons
CO2e using IPCC Tier 1 default
emissions factors and assuming 100
percent capacity utilization. Where
IPCC Tier 1 default factors were
unavailable (i.e., MEMs), the emissions
factor was estimated based on those of
semiconductors for the relevant
fluorinated GHGs. The proposed
Facilities covered
Facilities
99.8
98
95
79
Percent
173
118
96
54
80
55
44
25
capacity-based thresholds are 1,000 m2
silicon for semiconductors; 4,000 m2
silicon for MEMs; and 236,000 m2 LCD
for LCDs. Table I–3 of this preamble
shows the estimated emissions and
number of facilities that would report
for each source under the proposed
capacity-based thresholds. PV is not
shown in the table because we are
proposing an emissions threshold due to
lack of information.
TABLE I–3. SUMMARY OF RULE APPLICABILITY UNDER THE PROPOSED CAPACITY-BASED THRESHOLDS
Emissions source
Semi-conductors ...
MEMs ....................
LCD .......................
VerDate Nov<24>2008
Capacity-based
threshold
Total national
facilities
1,080 silicon m2 ....
1,020 silicon m2 ....
235,700 LCD m2 ...
15:41 Apr 09, 2009
Jkt 217001
175
12
9
PO 00000
Frm 00051
Total
emissions
of source
(metric tons
CO2e)
Emissions covered
Metric tons
CO2e/yr
5,741,676
146,115
23,632
Fmt 4701
Sfmt 4702
Facilities covered
Percent
5,492,066
96,164
0
E:\FR\FM\10APP2.SGM
Facilities
96
66
0
10APP2
Percent
91
2
0
52
17
0
16498
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
The proposed capacity-based
thresholds are estimated to cover about
50 percent of semiconductor facilities
and between 0 percent and 20 percent
of the facilities manufacturing MEMs
and LCDs. At the same time, the
thresholds are expected to cover nearly
96 percent of fluorinated GHG
emissions from semiconductor facilities,
and 0 percent and 66 percent of
fluorinated GHG emissions from
facilities manufacturing LCDs and
MEMs, respectively. Combined these
emissions are estimated to account for
close to 94 percent of fluorinated GHG
emissions from electronics as a whole.
We are proposing capacity-based
thresholds for the electronics industry,
where possible, because electronics
manufacturers may employ emissions
control equipment (e.g., thermal
oxidizers, fluorinated GHG capture
recycle systems) to lower their
fluorinated GHG emissions. In addition,
capacity-based thresholds would permit
facilities to quickly determine whether
or not they must report under this rule.
When abatement equipment is used,
electronics manufacturers often estimate
their emissions using the manufacturerpublished DRE for the equipment.
However, abatement equipment may fail
to achieve its rated DRE either because
it is not being properly operated and
maintained or because the DRE itself
was incorrectly measured due to a
failure to account for the effects of
dilution. (For example, CF4 can be off by
as much as a factor of 20 to 50 and C2F6
can be off by a factor of up to 10 because
of failure to properly account for
dilution.) In either event, the actual
emissions from facilities employing
abatement equipment may exceed
estimates based on the rated DREs of
this equipment and may therefore
exceed the 25,000 metric tons CO2e
threshold without the knowledge of the
facility operators. Measuring and
reporting emission control device
performance is therefore important for
developing an accurate estimate of
emissions. As discussed below, we
propose an emission estimation method
that would account for destruction by
abatement equipment only if facilities
verified the performance of their
abatement equipment using one of two
methods. If facilities choose not to
verify the performance of their
abatement equipment, the estimation
method would not account for any
destruction by the abatement device.
For additional background
information on the threshold analysis,
refer to the Electronics Manufacturing
TSD (EPA–HQ–OAR–2008–0508–009).
For specific information on costs,
including unamortized first year capital
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
a. Etching and Cleaning Emissions
Fluorinated GHG Emissions. Under
the proposed rule, large semiconductor
facilities (defined as facilities with
annual capacities of greater than 10,500
m2 silicon) would be required to
estimate their fluorinated GHG
emissions from etching and cleaning
using an approach based on the IPCC
Tier 3 method, and all other facilities
would be required to use an approach
based on the IPCC Tier 2b method. We
have determined that large
semiconductor facilities are already
using Tier 3 methods and/or have the
necessary data readily available either
in-house or from suppliers to apply the
highest tier method. The difference
between the proposed approaches and
the IPCC methods is that the proposed
approaches include stricter
requirements for quantifying the gas
destroyed by abatement equipment, as
described below. None of the IPCC
methods require a standard protocol to
estimate DREs of abatement equipment.
Given that the actual DRE of the
abatement equipment can be
significantly smaller (by up to a factor
of 50) compared to the manufacturer
rated DRE, we are proposing verification
of the DREs using a standard reporting
protocol (Burton, 2007).
Under the proposed rule, we estimate
that 17 percent of all semiconductor
manufacturing facilities would be
required to report using an IPCC Tier 3
approach (equivalent to 29 facilities out
of 175 total facilities) and that 56
percent of total semiconductor
emissions (equivalent 3.4 million metric
tons CO2e out of a total 5.9 million
metric tons CO2e emissions) would be
reported using the IPCC Tier 3
approach.
Method for Large Facilities. The IPCC
Tier 3 approach uses company-specific
data on (1) gas consumption, (2) gas
utilization, (3) by-product formation,
and (4) DRE for all emission abatement
processes at the facility.
Information on gas consumption by
process is often gathered as business as
usual,69 and information on gas
utilization, by-product formation, and
DRE for each process is readily available
69 In the RIA for this rulemaking, we have
conservatively included the costs of gathering,
consolidating, and checking process-specific gas
consumption information. However, we believe that
this information is already gathered in many cases
for purposes of internal process control and/or
emissions reporting under EPA’s voluntary PFC
Reduction Program for the Semiconductor Industry.
PO 00000
Frm 00052
Fmt 4701
Sfmt 4702
from tool manufacturers and can also be
experimentally measured on-site at the
facility. We propose that the DRE for
abatement equipment be experimentally
measured using the protocol described
below.
The guidance prepared by
International SEMATECH Technology
Transfer #0612485A–ENG (December
2006) must be followed when preparing
gas utilization and by-product formation
measurements. We have determined
that electronics manufacturers
commonly track fluorinated GHG
consumption using flow metering
systems calibrated to ±1 percent or
better accuracy. Thus the equation for
estimating emissions does not account
for cylinder heels. However, a facility
may choose to estimate consumption by
weighing fluorinated GHG cylinders
when placed into and taken out of
service, as is common practice by the
magnesium industry.
The use of the IPCC Tier 3 method
and standard site-specific DRE
measurement would provide the most
certain and practical emission estimates
for large facilities. The uncertainty
associated with an IPCC Tier 3 approach
is lower than any of the other IPCC
approaches, and is on the order of ±30
percent at the 95 percent confidence
interval. We estimate that the Tier 3
approach would not impose a
significant burden on facilities because
large semiconductor facilities are
already using Tier 3 methods and/or
have the necessary data to do so readily
available, as noted above.
Method for Other Semiconductor,
LCD, MEMS, and PV Facilities. The
IPCC Tier 2b approach is based on gas
consumption by process type (i.e., etch
or chamber clean) multiplied by default
factors for utilization, by-product
formation, and destruction. We are
proposing that site-specific DRE
measurements be used for quantifying
the amount of gas destroyed. The DRE
measurements would be determined
using the protocol described below.
The Tier 2b approach does not
account for variation among individual
processes or tools and, therefore, the
estimated emissions have an uncertainty
about twice as high as that of IPCC Tier
3 estimates. However, we have
concluded that the IPCC Tier 3 method
would be unduly burdensome to the
estimated 146 facilities with annual
production less than 10,500 m2 silicon.
We estimate that the IPCC Tier 2b
approach would not impose a
significant burden on facilities because
it requires only minimal fluorinated gas
usage tracking by major production
process type. These production input
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
data are readily available at all U.S.
manufacturing facilities.
N2O Emissions. We are proposing that
electronics manufacturers use a simple
mass-balance approach to estimate
emissions of N2O during etching and
chamber cleaning. This methodology
assumes N2O is not converted or
destroyed during etching or chamber
cleaning, due to lack of N2O utilization
data. We request comment on utilization
factors for N2O during etching and
chamber cleaning, and any data on N2O
by-product formation.
Verification of DRE. For facilities that
employ abatement devices and wish to
reflect the emission reductions due to
these devices in their emissions
estimates, two methods are proposed for
verifying the DRE of the equipment.
Either method may be followed.
The first method would require
facilities (or their equipment suppliers)
to test the DRE of the equipment using
an industry standard protocol, such as
the one under development by EPA as
part of the PFC Reduction/Climate
Partnership for Semiconductors (not yet
published). This draft protocol requires
facilities to experimentally determine
the effective dilution through the
abatement device and to measure
abatement DRE during actual or
simulated process conditions. The
second method would require facilities
to buy equipment that has been tested
by an independent third party (e.g., UL)
using an industry standard protocol
such as the one under development by
EPA. Under this approach,
manufacturers would pay the third
party to select random samples of each
model and test them. Because testing
would not need to be obtained for every
piece of equipment sold, this approach
would probably be less expensive than
in-house testing by electronics
manufacturers, but it may not capture
the full range of conditions under which
the abatement equipment would
actually be used.
We believe that the proposed DRE
measurement method is generally
robust, but we are requesting comment
on one aspect of that method. We are
concerned that the DREs measured and
calculated for CF4 may vary depending
on the mix of input gases used in the
electronics manufacturing process. The
calculated DRE for CF4 may be
influenced by the formation of CF4 from
other PFCs during the destruction
process itself, and different input gases
have different CF4 byproduct formation
rates. This means that a DRE for CF4
calculated using one set of input gases
might over- or under-estimate CF4
emissions when applied to another set
of input gases (or even the original set
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
in different proportions). We request
comment on the likelihood and
potential severity of such errors and on
how they might be avoided.
Facilities pursuing either DRE
verification method would also be
required to use the equipment within
the manufacturer’s specified equipment
lifetime, operate the equipment within
manufacturer specified limits for the gas
mix and exhaust flow rate intended for
fluorinated GHG destruction, and
maintain the equipment according to
the manufacturer’s guidelines. We
request comment on these proposed
requirements.
b. Emissions of Heat Transfer Fluids
We propose that electronics
manufacturers use the IPCC Tier 2
approach, which is a mass-balance
approach, to estimate the emissions of
each fluorinated heat transfer fluid. The
IPCC Tier 2 approach uses companyspecific data and accounts for
differences among facilities’ heat
transfer fluids (which vary in their
GWPs), leak rates, and service practices.
It has an uncertainty on the order of ±20
percent at the 95 percent confidence
interval according to the 2006 IPCC
Guidelines. The Tier 2 approach is
preferable to the IPCC Tier 1 approach,
which relies on a default emissions
factor to estimate heat transfer fluid
emissions and has relatively high
uncertainty compared to the Tier 2
approach.
c. Review of Existing Reporting
Programs and Methodologies
We reviewed the PFC Reduction/
Climate Partnership for the
Semiconductor Industry, U.S. GHG
Inventory, 1605(b), EPA Climate
Leaders, WRI, TRI, and the World
Semiconductor Council methods for
estimating etching and cleaning
emissions. All of the methods draw
from both the 2000 and 2006 IPCC
Guidelines.
Etching and Cleaning. For etching and
cleaning emissions, we considered the
2006 IPCC Tier 1 and Tier 2a methods,
as well as a Tier 2b/3 hybrid which
would apply Tier 3 to the most heavily
used fluorinated GHGs in all facilities.
The Tier 1 approach is based on the
surface area of substrate (e.g., silicon,
LCD or PV-cell) produced during
manufacture multiplied by a default gasspecific emission factor. The advantages
of the Tier 1 approach lie in its
simplicity. However, this method does
not account for the differences among
process types (i.e., etching versus
cleaning), individual processes, or tools,
leading to uncertainties in the default
emission factors of up to 200 percent at
PO 00000
Frm 00053
Fmt 4701
Sfmt 4702
16499
the 95 percent confidence interval.70
Facilities routinely monitor gas
consumption as part of business as
usual, making it technically feasible to
employ a method of at least IPCC Tier
2a complexity or higher without
additional data collection efforts.
The Tier 2a approach is based on the
gas consumption multiplied by default
factors for utilization, by-product
formation, and destruction. The Tier 2a
approach is relatively simple, given that
gas consumption data is collected as
part of business as usual. However, due
to variation in gas utilization between
etching and cleaning processes, the
estimated emissions using Tier 2a have
greater uncertainty than Tier 2b
estimated emissions.
Tier 2b/3 hybrid approach involves
requiring Tier 3 reporting for all
facilities, but only for the top three gases
emitted at each facility. For all other
gases, the Tier 2b approach would be
required. The top three gases emitted,
based on data in the Inventory of U.S.
GHG Emissions and Sinks, are C2F6,
CF4, and SF6 (EPA, 2008a). These top
three gases accounted for approximately
80 percent of total fluorinated GHG
emissions from semiconductor
manufacturing during etching and
chamber cleaning in 2006. The
uncertainty associated with the Tier
2b/3 hybrid approach has not been
determined, but is estimated to be
between the uncertainty for a Tier 2b
and Tier 3 approach.
We did not select the Tier 1 and Tier
2a methods due to the greater
uncertainty inherent in these
approaches. Although the Tier 2b/3
hybrid approach would provide more
accurate emissions estimates for small
facilities, we concluded that the Tier 2b
method with site-specific DRE
measurements would provide sufficient
accuracy without the additional
monitoring and recordkeeping
requirements of the Tier 3 method.
We propose collecting emissions data
from MEMS manufacturers meeting the
threshold criterion although no IPCC
default emission factors exist for MEMs
and the IPCC emission factors for
semiconductor and LCD manufacturing
may not be reliable for MEMs.
Therefore, we are seeking information
on emissions and emission factors for
both MEMs and LCD manufacturing.
Heat Transfer Fluids. For heat transfer
fluid emissions, we reviewed both the
IPCC Tier 1 and IPCC Tier 2 approaches.
The Tier 1 approach for heat transfer
fluid emissions is based on the
70 This uncertainty refers only to semiconductors
and LCDs. Tier 1 emission factor uncertainty for PV
was not estimated in the 2006 IPCC Guidelines.
E:\FR\FM\10APP2.SGM
10APP2
16500
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
utilization capacity of the
semiconductor facility multiplied by a
default emission factor. Although the
Tier 1 approach has the advantages of
simplicity, it is less accurate than the
Tier 2 approach according to the 2006
IPCC Guidelines.
4. Selection of Procedures for Estimating
Missing Data
Where facility-specific process gas
utilization rates and by-product gas
formation rates are missing, facilities
can estimate etching/cleaning emissions
by applying defaults from the next
lower Tier (e.g., IPCC Tier 2b or Tier 2a)
to estimate missing data. However,
facilities must limit their use of defaults
from the next lower Tier to less than 5
percent of their emissions estimate.
Default values for estimating DRE
would not be permitted. DRE values
must be estimated as zero in the absence
of facility-specific DREs that have been
measured using a standard protocol. Gas
consumption is collected as business as
usual and is not expected to be missing;
therefore, it would not be permitted to
revert to the Tier 1 approach for
estimating emissions. When estimating
heat transfer fluid emissions during
semiconductor manufacture, the use of
the mass-balance approach requires
correct records for all inputs. Should the
facility be missing records for a given
input, it may be possible that the heat
transfer fluid supplier has information
in their records for the facility.
5. Selection of Data Reporting
Requirements
Owners and operators would be
required to report GHG emissions for
the facility, for all plasma etching
processes, all chamber cleaning, all
chemical vapor deposition processes,
and all heat tranfer fluid use. Along
with their emissions, facilities would be
required to report the following: Method
used (i.e., 2b or 3), mass of each gas fed
into each process type, production
capacity in terms of substrate surface
area (e.g., silicon, PV-cell, LCD), factors
used for gas utilization, by-product
formation and their sources/
uncertainties, emission control
technology DREs and their
uncertainties, fraction of gas fed into
each process type with emissions,
control technologies, description of
abatement controls, inputs in the massbalance equation (for heat transfer fluid
emissions), example calculation, and
emissions uncertainty estimate.
These data form the basis of the
calculations and are needed for us to
understand the emissions data and
verify the reasonableness of the reported
emissions.
6. Selection of Records That Must Be
Retained
We propose that facilities keep
records of the following: Data actually
used to estimate emissions, records
supporting values used to estimate
emissions, the initial and any
subsequent tests of the DRE of oxidizers,
the initial and any subsequent tests to
determine emission factors for process,
and abatement device calibration/
maintenance records.
These records consist of values that
are directly used to calculate the
emissions that are reported and are
necessary to enable verification that the
GHG emissions monitoring and
calculations are done correctly.
J. Ethanol Production
1. Definition of the Source Category
Ethanol is produced primarily for use
as a fuel component, but is also used in
industrial applications and in the
manufacture of beverage alcohol.
Ethanol can be produced from the
fermentation of sugar, starch, grain, and
cellulosic biomass feedstocks, or
produced synthetically from ethylene or
hydrogen and carbon monoxide.
The sources of GHG emissions at
ethanol production facilities that must
be reported under the proposed rule are
stationary fuel combustion, onsite
landfills, and onsite wastewater
treatment.
Proposed requirements for stationary
fuel combustion emissions are set forth
in proposed 40 CFR part 98, subpart C.
Proposed requirements for landfill
emissions are set forth in Section V.HH
of this preamble. Data is unavailable on
landfilling at ethanol facilities, but it is
our understanding that some of these
facilities may have landfills with
significant CH4 emissions. For more
information on landfills at industrial
facilities, please refer to the Ethanol
Production TSD (EPA–HQ–OAR–2008–
0508–010). EPA is seeking comment on
available data sources for landfilling
practices at ethanol production
facilities.
The wastewater generated at ethanol
production facilities is handled in a
variety of ways, with dry milling and
wet milling facilities generally treating
wastewaters differently. In 2006, CH4
emissions from wastewater treatment at
ethanol production facilities were
68,200 metric tons CO2e. Proposed
requirements for GHG emissions form
wastewater treatment are set forth in
Section V.II of this preamble. For more
information on wastewater treatment at
ethanol production facilities, please
refer to the Ethanol Production TSD
(EPA–HQ–OAR–2008–0508–010).
As noted in Section IV.B of this
preamble under the heading ‘‘Reporting
by fuel and industrial gas suppliers’’,
ethanol producers and other suppliers
of biomass-based fuel are not required to
report GHG emissions from their
products under this proposal, and we
seek comment on this approach.
2. Selection of Reporting Threshold
The proposed threshold for reporting
emissions from ethanol production
facilities is 25,000 metric tons CO2e
total emissions from stationary fuel
combustion, landfills, and onsite
wastewater treatment. Table J–1 of this
preamble illustrates the emissions and
facilities that would be covered under
various thresholds.
TABLE J–1. THRESHOLD ANALYSIS FOR ETHANOL PRODUCTION
National emissions
mtCO2e
Threshold level
1,000 mtCO2e .....................
10,000 mtCO2e ...................
25,000 mtCO2e ...................
100,000 mtCO2e .................
Not
Not
Not
Not
estimated
estimated
estimated
estimated
Data were unavailable to estimate
emissions from landfills at ethanol
refineries, or to estimate the combined
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
.............
.............
.............
.............
140
140
140
140
mtCO2e/year
Not
Not
Not
Not
estimated
estimated
estimated
estimated
.............
.............
.............
.............
wastewater treatment and stationary
fuel combustion emissions at facilities.
Data on stationary fuel combustion were
PO 00000
Frm 00054
Fmt 4701
Sfmt 4702
Facilities covered
Percent
Not
Not
Not
Not
estimated
estimated
estimated
estimated
.............
.............
.............
.............
Number
>101
>94
>86
>43
Percent
>72
>67
>61
>31
used to estimate the minimum number
of facilities that would meet each of the
facility-level thresholds examined. The
E:\FR\FM\10APP2.SGM
10APP2
16501
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
25,000 metric tons CO2e threshold
results in a reasonable number of
reporters, and is consistent with
thresholds for other source categories.
For more information on this analysis,
please refer to the Ethanol Production
TSD (EPA–HQ–OAR–2008–0508–010).
EPA is seeking comment on the analysis
and on alternative data sources for
stationary combustion at ethanol
production facilities. For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Refer to Sections V.C, V.HH, and V.II
of this preamble for monitoring methods
for general stationary fuel combustion
sources, landfills, and wastewater
treatment occurring on-site at ethanol
production facilities.
4. Selection of Procedures for Estimating
Missing Data
Refer to Sections V.C, V.HH, and V.II
of this preamble for procedures for
estimating missing data for general
stationary fuel combustion sources,
landfills, and industrial wastewater
treatment occurring on-site at ethanol
production facilities.
5. Selection of Data Reporting
Requirements
Refer to Sections V.C, V.HH, and V.II
of this preamble for reporting
requirements for general stationary fuel
combustion sources, landfills, and
industrial wastewater treatment
occurring on-site at ethanol production
facilities. In addition, you would be
required to report the quantity of CO2e
captured for use (if applicable) and the
end use, if known. For more information
on reporting requirements for CO2e
capture, please refer to Section V.PP of
this preamble.
6. Selection of Records That Must Be
Maintained
Refer to Sections V.C, V.HH, and
V.GG of this preamble for recordkeeping
requirements for stationary fuel
combustion, landfills, and industrial
wastewater treatment occurring on-site
at ethanol production facilities.
K. Ferroalloy Production
1. Definition of the Source Category
A ferroalloy is an alloy of iron with
at least one other metal such as
chromium, silicon, molybdenum,
manganese, or titanium. For this
proposed rule, we are defining the
ferroalloy production source category to
consist of any facility that uses
pyrometallurgical techniques to produce
any of the following metals:
ferrochromium, ferromanganese,
ferromolybdenum, ferronickel,
ferrosilicon, ferrotitanium,
ferrotungsten, ferrovanadium,
silicomanganese, or silicon metal.
Ferroalloys are used extensively in the
iron and steel industry to impart
distinctive qualities to stainless and
other specialty steels, and serve
important functions during iron and
steel production cycles. Silicon metal is
included in the ferroalloy metals
category due to the similarities between
its production process and that of
ferrosilicon. Silicon metal is used in
alloys of aluminum and in the chemical
industry as a raw material in siliconbased chemical manufacturing.
The basic process used at U.S.
ferroalloy production facilities is a batch
process in which a measured mixture of
metals, carbonaceous reducing agents,
and slag forming materials are melted
and reduced in an electric arc furnace.
The carbonaceous reducing agents
typically used are coke or coal. Molten
alloy tapped from the electric arc
furnace is casted into solid alloy slabs
which are further mechanically
processed for sale as product or
disposed in landfills.
Ferroalloy production results in both
combustion and process-related GHG
emissions. The major source of GHG
emissions from a ferroalloy production
facility are the process-related emissions
from the electric arc furnace operations.
These emissions, which consist
primarily of CO2e with smaller amounts
of CH4, result from the reduction of the
metallic oxides and the consumption of
the graphite (carbon) electrodes during
the batch process.
Total nationwide GHG emissions from
ferroalloy production facilities operating
in the U.S. were estimated to be
approximately 2.3 million metric tons
CO2e for the year 2006. Process-related
GHG emissions were 2.0 million metric
tons CO2e (86 percent of the total
emissions). The remaining 0.3 million
metric tons CO2e (14 percent of the total
emissions) were combustion GHG
emissions.
Additional background information
about GHG emissions from the
ferroalloy production source category is
available in the Ferroalloy Production
TSD (EPA–HQ–OAR–2008–0508–011).
2. Selection of Reporting Threshold
Ferroalloy production facilities in the
U.S. vary in the specific types of alloy
products produced. In developing the
threshold for ferroalloy production
facilities, we considered using annual
GHG emissions-based threshold levels
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Table K–1 of
this preamble presents the estimated
emissions and number of facilities that
would be subject to GHG emissions
reporting, based upon emission
estimates using production capacity
data for the nine U.S. facilities that
produce either ferrosilicon, silicon
metal, ferrochromium, ferromanganese,
or silicomanganese alloys. We were
unable to obtain production data for an
estimated five additional facilities that
produce ferromolybdenum and
ferrotitanium alloys.
TABLE K–1. THRESHOLD ANALYSIS FOR FERROALLOY PRODUCTION FACILITIES
Total national
emissions
(metric tons
CO2e/yr)
Threshold level (metric tons CO2e/yr)
1,000 ............................................................
10,000 ..........................................................
25,000 ..........................................................
100,000 ........................................................
Table K–1 of this preamble shows that
all nine of the facilities would be
required to report emissions at all
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
2,343,990
2,343,990
2,343,990
2,343,990
9
9
9
9
Metric tons
CO2e/yr
PO 00000
Frm 00055
Fmt 4701
Sfmt 4702
Percent
2,343,990
2,343,990
2,343,990
2,276,639
thresholds except 100,000 metric tons
CO2e, when considering combustion
and process-related emissions. The rule
Facilities covered
100
100
100
97
Number
Percent
9
9
9
8
100
100
100
89
could be simplified for these facilities
by making the rule applicable to all
ferroalloy production facilities.
E:\FR\FM\10APP2.SGM
10APP2
16502
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
However, because the threshold analysis
did not include all of the facilities in the
ferroalloy source category that
potentially could be subject to the rule,
we have decided that it is appropriate
to include a reporting threshold level.
The proposed threshold selected for
reporting emissions from ferroalloy
production facilities is 25,000 metric
tons CO2e per year consistent with the
threshold level being proposed for other
source categories. This threshold level
would avoid placing a reporting burden
on any small specialty ferroalloy
production facility which may operate
as a small business while still requiring
the reporting of GHG emissions from the
ferroalloy production facilities releasing
most of the GHG emissions in the source
category. A full discussion of the
threshold selection analysis is available
in the Ferroalloy Production TSD (EPA–
HQ–OAR–2008–0508–011). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
We reviewed existing methodologies
used by the 2006 IPCC Guidelines for
National Greenhouse Gas Inventories,
Canadian Mandatory Greenhouse Gas
Reporting Program, the Australian
National Greenhouse Gas Reporting
Program, and EU Emissions Trading
System. In general, the methodologies
used for estimating process related GHG
emissions at the facility level coalesce
around the following four options.
Option 1. Apply a default emission
factor to ferroalloy production. This is a
simplified emission calculation method
using only default emission factors to
estimate process-related CO2 and CH4
emissions. The method requires
multiplying the amount of each
ferroalloy product type produced by the
appropriate default emission factors
from the 2006 IPCC Guidelines.
Option 2. Perform a monthly carbon
balance using measurements of the
carbon content of specific process
inputs and process outputs and the
amounts of these materials consumed or
produced during a specified reporting
period. This option is applicable to
estimating only CO2 emissions from an
electric arc furnace, and is the IPCC Tier
3 approach and the higher order
methods in the Canadian and Australian
reporting programs. Implementation of
this method requires you to determine
the carbon contents of carbonaceous
material inputs to and outputs from the
electric arc furnaces. Facilities
determine carbon contents through
analysis of representative samples of the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
material or from information provided
by the material suppliers. In addition,
the quantities of these materials
consumed and produced during
production would be measured and
recorded. To obtain the CO2 emissions
estimate, the average carbon content of
each input and output material is
multiplied by the corresponding mass
consumed and a conversion of carbon to
CO2. The difference between the
calculated total carbon input and the
total carbon output is the estimated CO2
emissions to the atmosphere. This
method assumes that all of the carbon
is converted during the process. For
estimating the CH4 emissions from the
electric arc furnace, selection of this
option for estimating CO2 emissions
would still require using the Option 1
approach of applying default emission
factors to estimate CH4 emissions.
Option 3. Use CO2 emissions data
from a stack test performed using U.S.
EPA test methods to develop a sitespecific process emissions factor which
is then applied to quantity measurement
data of feed material or product for the
specified reporting period. This
monitoring method is applicable to
electric arc furnace configurations for
which the GHG emissions are contained
within a stack or vent. Using sitespecific emissions factors based on
short-term stack testing is appropriate
for those facilities where process inputs
(e.g., feed materials, carbonaceous
reducing agents) and process operating
parameters remain relatively consistent
over time.
Option 4. Use direct emission testing
of CO2 emissions. For electric arc
furnace configurations in which the
process off-gases are contained within a
stack or vent, direct measurement of the
CO2 emissions can be made by
continuously measuring the off-gas
stream CO2 concentration and flow rate
using a CEMS. Using a CEMS, the total
CO2 emissions tabulated from the
recorded emissions measurement data
would be reported annually. If a
ferroalloy production facility uses an
open or semi-open electric arc furnace
for which the CO2 emissions are not
fully captured and contained within a
stack or vent (i.e., a significant portion
of the CO2 emissions escape capture by
the hood and are release directly to the
atmosphere), then another GHG
emission estimation method other than
direct measurement would be more
appropriate.
Proposed Option. Under the proposed
rule, if you are required to use an
existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, you would be required to use
CEMS to estimate CO2 emissions. Where
PO 00000
Frm 00056
Fmt 4701
Sfmt 4702
the CEMS capture all combustion- and
process-related CO2 emissions you
would be required to follow the
requirements of proposed 40 CFR part
98, subpart C, to estimate CO2 emissions
from the industrial source. Also, refer to
proposed 40 CFR part 98, subpart C to
estimate combustion-related CH4 and
N2O.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where CEMS would not
adequately account for process
emissions, the proposed monitoring
method is Option 2. You would be
required to follow the requirements of
proposed 40 CFR part 98, subpart C to
estimate emissions of CO2, CH4 and N2O
from stationary combustion. This
section of the preamble provides
procedures only for calculating and
reporting process-related emissions.
Given the variability of the alloy
products produced and carbonaceous
reducing agents used at U.S. ferroalloy
production facilities, we concluded that
using facility-specific information under
Option 2 is preferred for estimating CO2
emissions from electric arc furnaces.
This method is consistent with IPCC
Tier 3 methods and the preferred
approaches for estimating emissions in
the Canadian and Australian mandatory
reporting programs. We consider the
additional burden of the material
measurements required for the carbon
balance small in relation to the
increased accuracy expected from using
this site-specific information to
calculate CO2 emissions.
Emissions data collected under
Option 3 would have the lowest
uncertainty, expected to be less than 5
percent. For Option 2, the materialspecific emission factors would be
expected to be within 10 percent, which
would provide less uncertainty overall
than for Option 1, which may have
uncertainty of 25 to 50 percent. The use
of the default CO2 emission factors
under Option 1 would be more
appropriate for GHG estimates from
aggregated process information on a
sector-wide or nationwide basis than for
determining GHG emissions from
specific facilities.
In comparison to the CO2 emissions
levels from an electric arc furnace, the
CH4 emissions compose a small fraction
of the total GHG emissions from electric
arc furnace operations at a ferroalloy
production facility. The proposed
Option 2 above doesn’t account for CH4.
Considering the amount that CH4
emissions contribute to the total GHG
emissions and the absence of facilityspecific methods in other reporting
systems, we are proposing that facilities
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
use Option 1 and the IPCC default
emission factors to estimate CH4
emissions from electric arc furnaces at
ferroalloy production facilities. This
method provides reasonable estimates of
the magnitude of the CH4 emissions
from the units without the need for
owners or operator to conduct on-site
CH4 emissions measurements.
We also decided against Option 3
because of the potential for significant
variations at ferroalloy production
facilities in the characteristics and
quantities of the electric arc furnace
inputs (e.g., metal ores, carbonaceous
reducing agents) and process operating
parameters. A method using periodic,
short-term stack testing would not be
practical or appropriate for those
ferroalloy production facilities where
the electric arc furnace inputs and
operating parameters do not remain
relatively consistent over the reporting
period.
The various approaches to monitoring
GHG emissions are elaborated in the
Ferroalloy Production TSD (EPA–HQ–
OAR–2008–0508–011).
4. Selection of Procedures for Estimating
Missing Data
In cases when an owner or operator
calculates CO2 and CH4 emissions using
a carbon balance or an emission factor,
the proposed rule would require the use
of substitute data whenever a qualityassured value of a parameter that is used
to calculate GHG emissions is
unavailable, or ‘‘missing.’’ If the carbon
content analysis of carbon inputs or
outputs is missing or lost, the substitute
data value would be the average of the
quality-assured values of the parameter
immediately before and immediately
after the missing data period. The
likelihood for missing process input and
output data is low, as businesses closely
track their purchase of production
inputs. In those cases when an owner or
operator uses direct measurement by a
CO2 CEMS, the missing data procedures
would be the same as the Tier 4
requirements described for general
stationary combustion sources in
Section V.C of this preamble.
5. Selection of Data Reporting
Requirements
The proposed rule would require
reporting of the total annual CO2 and
CH4 emissions for each electric arc
furnace at a ferroalloy production
facility, as well as any stationary fuel
combustion emissions. In addition we
propose that additional information
which forms the basis of the emissions
estimates also be reported so that we
can understand and verify the reported
emissions. This additional information
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
includes the total number of electric arc
furnaces operated at the facility, the
facility ferroalloy product production
capacity, the annual facility production
quantity for each ferroalloy product, the
number of facility operating hours in
calendar year, and quantities of carbon
inputs and outputs if applicable. A
complete list of data to be reported is
included in the proposed 40 CFR part
98, subparts A and K.
6. Selection of Records That Must Be
Retained
Maintaining records of the
information used to determine the
reported GHG emissions are necessary
to enable us to verify that the GHG
emissions monitoring and calculations
were done correctly. We propose that all
affected facilities maintain records of
product production quantities, and
number of facility operating hours each
month. If you use the carbon balance
procedure, you would record for each
carbon-containing input material
consumed or used and output material
produced the monthly material
quantity, monthly average carbon
content determined for material, and
records of the supplier provided
information or analyses used for the
determination. If you use the CEMS
procedure, you would maintain the
CEMS measurement records.
L. Fluorinated GHG Production
1. Definition of the Source Category
This source category covers emissions
of fluorinated GHGs that occur during
the production of HFCs, PFCs, SF6, NF3,
and other fluorinated GHGs such as
fluorinated ethers. Specifically, it covers
emissions that are never counted as
‘‘mass produced’’ under the proposed
requirements for suppliers of industrial
GHGs discussed in Section OO of this
preamble. These emissions include
fluorinated GHG products that are
emitted upstream of the production
measurement and fluorinated GHG
byproducts that are generated and
emitted either without or despite
recapture or destruction.71 These
emissions exclude generation and
emissions of HFC–23 during the
production of HCFC–22, which are
discussed in Section O of this preamble.
Emissions can occur from leaks at
flanges and connections in the
production line, during separation of
71 Byproducts that are emitted or destroyed at the
production facility are excluded from the proposed
definition of ‘‘produce a fluorinated GHG.’’ Any
HFC–23 generated during the production of HCFC–
22 is also excluded from this definition, even if the
HFC–23 is recaptured. However, other fluorinated
GHG byproducts that are recaptured for any reason
would be considered to be ‘‘produced.’’
PO 00000
Frm 00057
Fmt 4701
Sfmt 4702
16503
byproducts and products, during
occasional service work on the
production equipment, and during the
filling of tanks or other containers that
are distributed by the producer (e.g., on
trucks and railcars). Fluorinated GHG
emissions from U.S. facilities producing
fluorinated GHGs are estimated to range
from 0.8 percent to 2 percent of the
amount of fluorinated GHGs produced,
depending on the facility.
In 2006, 12 U.S. facilities produced
over 350 million metric tons CO2e of
HFCs, PFCs, SF6, and NF3. These
facilities are estimated to have emitted
approximately 5.3 million metric tons
CO2e of HFCs, PFCs, SF6, and NF3,
based on an emission rate of 1.5 percent.
We estimate that an additional 6
facilities produced approximately 1
million metric tons CO2e of fluorinated
anesthetics. At an emission rate of 1.5
percent, these facilities would emit
approximately 15,000 metric tons CO2e
of these anesthetics.
The production of fluorinated gases
causes both combustion and fluorinated
GHG emissions. Fluorinated GHG
production facilities would be required
to follow the requirements of proposed
40 CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary fuel combustion. In addition,
these facilities would be required to
report their production of industrial
GHGs under proposed 40 CFR part 98,
subpart OO. This section of the
preamble discusses only the procedures
for calculating and reporting emissions
of fluorinated GHGs.
2. Selection of Reporting Threshold
We propose that owners and operators
of facilities estimate and report
fluorinated GHG and combustion
emissions if those emissions together
exceed 25,000 metric tons CO2e.
In developing the threshold, we
considered emissions thresholds of
1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e and their
capacity equivalents. Facility-specific
emissions were estimated by
multiplying an emission factor of 1.5
percent by the estimated production at
each facility. The capacity thresholds
were developed based on emissions of
fluorinated GHGs, assuming full
capacity utilization and an emission rate
of 2 percent of production. Because EPA
had little information on combustionrelated emissions at fluorinated GHG
production facilities, these emissions
were not incorporated into the capacity
thresholds or the threshold analysis.
Table L–1 of this preamble illustrates
the HFC, PFC, SF6, and NF3 emissions
E:\FR\FM\10APP2.SGM
10APP2
16504
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
and facilities that would be covered
under these various thresholds.
TABLE L–1. THRESHOLD ANALYSIS FOR FLUORINATED GHG EMISSIONS FROM PRODUCTION OF HFCS, PFCS, SF6, AND
NF3
Threshold level (metric tons CO2e/r)
Total
national
emissions
(metric tons
CO2e)
Emissions covered
Number of
facilities
Metric tons
CO2e
Facilities covered
Percent
Number
Percent
Emission-Based Thresholds
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
5,300,000
5,300,000
5,300,000
5,300,000
12
12
12
12
5,300,000
5,300,000
5,300,000
5,100,000
100
100
100
97
12
12
12
9
100
100
100
75
50,000 ......................................................
500,000 ....................................................
1,250,000 .................................................
5,000,000 .................................................
5,300,000
5,300,000
5,300,000
5,300,000
12
12
12
12
5,300,000
5,300,000
5,300,000
5,200,000
100
100
100
98
12
12
12
10
100
100
100
83
As can be seen from the tables, most
HFC, PFC, SF6, and NF3 production
facilities would be covered by all
emission- and capacity-based
thresholds. Although we do not have
facility-specific production information
for producers of fluorinated anesthetics,
we believe that few or none of these
facilities are likely to have emissions
above the proposed threshold.
EPA requests comment on whether it
should adopt a capacity-based threshold
for this sector, and if so, what
fluorinated GHG and combustionrelated emission rates should be used to
develop this threshold. Where EPA has
reasonably good information on the
relationship between production
capacity and emissions, and where this
relationship does not vary excessively
from facility to facility, EPA is generally
proposing capacity-based thresholds to
make it easy for facilities to determine
whether or not they must report. In this
case, however, EPA has little data on
combustion emissions and their likely
magnitude compared to fluorinated
GHG emissions from this source.
As noted above, the capacity
thresholds in Table L–1 of this preamble
were developed based on a fluorinated
GHG emission rate of 2 percent of
production. While EPA believes that
this emission rate is an upper-bound for
fluorinated GHGs, neither the rate nor
the thresholds account for combustionrelated emissions. Thus, it is possible
that the production capacities listed in
Table L–1 of this preamble are
inappropriately high.
In the event that a capacity-based
threshold were adopted, facilities would
be required to multiply the production
capacity of each production line by the
GWP of the fluorinated GHG produced
on that line. Facilities would then be
required to sum the resulting CO2e
capacities across all lines. Where more
than one fluorinated GHG could be
produced by a production line, yielding
more than one possible production
capacity for that line in CO2e terms,
facilities would be required to use the
highest possible production capacity (in
CO2e terms) in their threshold
calculations.
A full discussion of the threshold
selection analysis is available in the
Fluorinated GHG Production TSD
(EPA–HQ–OAR–2008–0508–012). For
specific information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
Production Capacity-Based Thresholds
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
3. Selection of Proposed Monitoring
Methods
In developing this proposed rule, we
reviewed a number of protocols for
estimating fluorinated GHG emissions
from fluorocarbon production, such as
the 2006 IPCC Guidelines. In general,
these protocols present three methods.
In the first approach, a default emission
factor is applied to the total production
of the plant. In the second approach,
fluorinated GHG emissions are equated
to the difference between the mass of
reactants fed into the process and the
sum of the masses of the main product
and those of any by-products and/or
wastes. In the third approach, the
composition and mass flow rate of the
gas streams actually vented to the
atmosphere are monitored either
continuously or during a period long
enough to establish an emission factor.
PO 00000
Frm 00058
Fmt 4701
Sfmt 4702
If you produce fluorinated GHGs, we
are proposing that you monitor
fluorinated GHG emissions using the
second approach, known as the massbalance or yield approach. There are
two variants of the mass-balance
approach. In the first variant, only some
of the reactants and products, including
the fluorinated GHG product, are
considered. In the second variant, all of
the reactants, products, and by-products
are considered. Both variants are
discussed in more detail in the
Fluorinated GHG Production TSD
(EPA–HQ–OAR–2008–0508–012).
We are proposing that you monitor
emissions using the first variant. In this
approach, you would calculate the
difference between the expected
production of each fluorinated GHG
based on the consumption of reactants
and the measured production of that
fluorinated GHG, accounting for yield
losses related to byproducts (including
intermediates permanently removed
from the process) and wastes. Yield
losses that could not be accounted for
would be attributed to emissions of the
fluorinated GHG product. This
calculation would be performed for each
reactant, and estimated emissions of the
fluorinated GHG product would be
equated to the average of the results
obtained for each reactant. If fluorinated
GHG byproducts were produced and
were not completely recaptured or
completely destroyed, you would also
estimate emissions of each fluorinated
GHG byproduct.
To carry out this approach, you would
daily weigh or meter each reactant fed
into the process, the primary fluorinated
GHG produced by the process, any
reactants permanently removed from the
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
process (i.e., sent to the thermal oxidizer
or other equipment, not immediately
recycled back into the process), any
byproducts generated, and any streams
that contain the product or byproducts
and that are recaptured or destroyed.
For these measurements you would be
required to use scales and/or flowmeters
with an accuracy and precision of 0.2
percent of full scale. If monitored
process streams included more than one
component (product, byproducts, or
other materials) in more than trace
concentrations,72 you would be required
to monitor concentrations of products
and byproducts in these streams at least
daily using equipment and methods
(e.g., gas chromatography) with an
accuracy and precision of 5 percent or
better at the concentrations of the
process samples. Finally, you would be
required to perform daily mass balance
calculations for each product produced.
In general, we understand that
production facilities already perform
these measurements and calculations to
the proposed level of accuracy and
precision in order to monitor their
processes and yields. However, we
request comment on this issue. We
specifically request comment on the
proposed scope and frequency of
process stream concentration
measurements. As noted above,
concentration measurements would be
triggered when products or byproducts
occur in more than trace concentrations
with other components in process
streams (which include waste streams).
However, it is possible that products or
byproducts could occur in more than
trace concentrations but still result in
negligible yield losses (e.g., less than 0.2
percent). In this case, ignoring these
losses may not significantly affect the
accuracy of the overall GHG emission
estimate. (This issue is discussed in
more detail in the Fluorinated GHG
Production TSD (EPA–HQ–OAR–2008–
0508–012).) Similarly, decreasing the
frequency of stream sampling may not
have a significant impact on accuracy or
precision if previous monitoring has
shown that the concentrations of
products and byproducts in process
streams are stable or vary in a
predictable and quantifiable way (e.g.,
seasonally due to differences in
condenser cooling water temperature).
EPA recognizes that the proposed
mass-balance approach would assume
that all yield losses that are not
accounted for are attributable to
emissions of the fluorinated GHG
product. In some cases, the losses may
72 EPA is proposing to define ‘‘trace
concentration’’ as any concentration less than 0.1
percent by mass of the process stream.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
be untracked emissions or other losses
of reactants or fluorinated by-products.
In general, EPA understands that
reactant flows are measured at the inlet
to the reactor; thus, any losses of
reactant that occur between the point of
measurement and the reactor are likely
to be small. However, reactants that are
recovered from the process, whether
they are recycled back into it or
removed permanently, may experience
some losses that the proposed method
does not account for. EPA requests
comment on the extent to which such
losses occur, and how these might be
measured.
Fluorocarbon by-products, according
to the IPCC Guidelines, generally have
‘‘radiative forcing properties similar to
those of the desired fluorochemical.’’ If
this is always the case (with the
exception of HFC–23 generated during
production of HCFC–22, which is
addressed in Section V.O of this
preamble), then assuming by-product
emissions are product emissions would
not lead to large errors in estimating
overall fluorinated GHG emissions. If
the GWPs of emitted fluorinated byproducts are sometimes significantly
different from those of the fluorinated
GHG product, and if the quantity of byproduct emitted can be estimated (e.g.,
based on periodic or past sampling of
process streams), then the quantity of
emitted product could be adjusted to
reflect this. EPA requests comment on
whether it is necessary or practical to
distinguish between emissions of
fluorinated GHG products and
emissions of fluorinated by-products,
and if so, on the best approach for doing
so.
We also request comment on the
proposed accuracy and precision
requirements for flowmeters and scales.
If a waste or by-product stream is
significantly smaller than the reactant
and product streams, a less precise
measurement of this stream (e.g., 0.5
percent) may not have a large impact on
the precision of the fluorinated GHG
emission estimate and may therefore be
acceptable. Similarly, if a measurement
is repeated multiple times over the
course of the reporting period, the
precision of individual measurements
could be relaxed without seriously
compromising the precision of the
monthly or annual estimates. One way
of adding flexibility to the precision
requirements would be to require that
the error of the fluorinated GHG
emissions estimate be no greater than
some fraction of the yield, e.g., 0.3
percent, on a monthly basis. Facilities
could achieve this level of precision
however they chose. We request
comment on this issue and on the
PO 00000
Frm 00059
Fmt 4701
Sfmt 4702
16505
accuracy, precision, and cost of the
proposed approach as a whole.
Analysis of Alternative Methods. EPA
is not proposing the approach using the
default emission factor. While this
approach is simple, it is also highly
imprecise; emissions in U.S. plants are
estimated to vary from 0.8 percent to 2
percent of production, more than a
factor of two.73 Thus, applying a default
factor (1.5 percent, for example) is likely
to significantly overestimate emissions
at some plants while significantly
underestimating them at others.
EPA is not proposing the second
variant of the mass-balance approach.
This variant is implemented by
comparing the total mass of reactants to
the total mass of monitored products
and byproducts, without regard for
chemical identity. The drawbacks of
this variant are that it is not the method
currently used by facilities to track their
production, and it would count losses of
non-GHG products (e.g., HCl) as GHG
emissions. EPA requests comment on
this understanding and on the potential
usefulness and accuracy of the second
variant of the mass-balance approach for
estimating fluorinated GHG emissions.
EPA is not proposing the third
approach because it is our
understanding that facilities do not
routinely monitor their process vents,
and therefore such monitoring is likely
to be more expensive than the proposed
mass-balance approach. However, the
cost of monitoring may not be
prohibitive, particularly if it is
performed for a relatively short period
of time for the purpose of developing an
emission factor, similar to the approach
for estimating smelter-specific slope
coefficients for aluminum production.74
Moreover, if the vent monitoring
approach reduces the uncertainty of the
emissions measurement by even 10
percent relative to the mass-balance
approach, this would reduce the
absolute uncertainty at the typical
production facility by 40,000 metric
tons CO2e. (The extent to which
uncertainty would be reduced would
depend in part on the sensitivity and
73 Fluorinated GHG Production TSD (EPA–HQ–
OAR–2008–0508–012).
74 Conversations with representatives of
fluorocarbon producers indicate that robust
emission factors could often be developed by
monitoring emissions (and a related parameter,
such as production) for one month under
representative operating conditions. Where
emissions vary seasonally (e.g., due to changes in
condenser cooling water temperature), two separate
monitoring periods of one month each would often
suffice. However, the length and frequency of
monitoring would depend on the variability of the
process.
E:\FR\FM\10APP2.SGM
10APP2
16506
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
precision of the vent concentration
measurements.)
For completeness, monitoring of
process vents would need to be
supplemented by monitoring of
equipment leaks, whose emissions
would not occur through process vents.
To capture emissions from equipment
leaks, we could require use of EPA
Method 21 and the Protocol for
Equipment Leak Estimates (EPA–453/R–
95–017). The Protocol includes four
methods for estimating equipment leaks.
These are, from least to most accurate,
the Average Emission Factor Approach,
the Screening Ranges Approach, EPA
Correlation Approach, and the UnitSpecific Correlation Approach. Most
recent EPA leak detection and repair
regulations require use of one of the
Correlation Approaches in the Protocol.
To use any approach other than the
Average Emission Factor Approach, you
would need to have (or develop)
Response Factors relating
concentrations of the target fluorinated
GHG to concentrations of the gas with
which the leak detector was calibrated.
We understand that at least two
fluorocarbon producers currently use
methods in the Protocol to quantify their
emissions of fluorinated GHGs with
different levels of accuracy and
precision.75
We request comment on the
accuracies and costs of the approaches
in the Protocol as they would be applied
to fluorinated GHG production. We also
request comment on the significance of
equipment leaks compared to process
vents as a source of fluorinated GHG
emissions.
In addition, we request comment on
whether we should require the vent
monitoring approach, what sensitivity
and precision would be appropriate for
the vent concentration measurements,
and on the increase in cost and
improvements in accuracy and
precision that would be associated with
this approach relative to the proposed
approach.
Emissions from Evacuation of
Returned Containers. We request
comment on whether you should be
required to measure and report
75 One producer estimates HFC and other
fluorocarbon emissions by using the Average
Emission Factor Approach. This approach simply
assigns an average emission factor to each
component without any evaluation of whether or
how much that component is actually leaking. The
second producer estimates emissions using the
Screening Ranges Approach, which assigns
different emission factors to components based on
whether the concentrations of the target chemical
are above or below 10,000 ppmv. This producer has
developed a Response Factor for HCFC–22, which
is present in the same streams as the HFC–23 whose
leaks are being estimated. (HFC–23 emissions are
discussed in Section O of this preamble.)
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
fluorinated GHG emissions associated
with the evacuation of cylinders or
other containers that are returned to the
facility containing either residual GHGs
(heels) or GHGs that would be reclaimed
or destroyed. We are not proposing to
require reporting of these emissions
because they are not associated with
new production; instead, they are
downstream emissions associated with
earlier production.76 Requiring
reporting of these emissions could
therefore lead to double-counting.77
Nevertheless, according to the 2006
IPCC Guidelines, the overall emission
rate of a production facility can increase
by nearly an order of magnitude (up to
8 percent) if the residual GHG
remaining in the cylinders is vented to
the atmosphere. One method of tracking
such emissions would be to subtract the
quantities of GHG reclaimed (purified)
and sold or otherwise sent back to users
from the quantities of residual and used
GHGs returned to the facility in
cylinders by users. This approach
would be similar to the mass-balance
approach proposed for estimating SF6
emissions from users and manufacturers
of electrical equipment.
Emissions of Fluorinated GHGs
Associated with Production of ODS. We
request comment on whether you
should be required to report emissions
of fluorinated GHGs associated with
production of ODS (other than
emissions of HFC–23 associated with
production of HCFC–22, which are
discussed in Section O of this
preamble). These emissions would be
by-product emissions, for example of
HFCs, since the definition of fluorinated
GHGs excludes ODS. We specifically
request comment on the likely
magnitude of these emissions, both in
absolute terms and relative to
fluorinated GHG emissions from
fluorinated GHG production. We believe
that these emissions may occur due to
the chemical similarities between HFCs,
HCFCs, and CFCs and the common use
of halogen replacement chemistry to
produce them. Although production of
HCFCs and CFCs is limited under the
regulations implementing Title VI of the
CAA, production of these substances for
76 Emissions from the filling or refilling of
containers with new product may or may not be
covered by proposed 40 CFR part 98, subpart L,
depending on where production is measured. If
production is measured upstream of filling, then the
emissions would not be covered by proposed 40
CFR part 98, subpart L. If production is measured
downstream of filling, then the emissions would be
covered by subpart L.
77 However, this double-counting could be
avoided if the emissions from returned cylinders
were clearly distinguished from other production
facility emissions in the emissions report.
PO 00000
Frm 00060
Fmt 4701
Sfmt 4702
use as feedstocks is permitted to
continue indefinitely.
4. Selection of Procedures for Estimating
Missing Data
In the event that a scale or flowmeter
normally used to measure reactants,
products, by-products, or wastes fails to
meet an accuracy or precision test,
malfunctions, or is rendered inoperable,
we are proposing that facilities be
required to estimate these quantities
using other measurements where these
data are available. For example,
facilities that ordinarily measure
production by metering the flow into
the day tank could use the weight of
product charged into shipping
containers for sale and distribution as a
substitute. It is our understanding that
the types of flowmeters and scales used
to measure fluorocarbon production
(e.g., Coriolis meters) are generally quite
reliable, and therefore that it should
rarely be necessary to rely solely on
secondary production measurements. In
general, production facilities rely on
accurate monitoring and reporting of the
inputs and outputs of the production
process.
If concentration measurements are
unavailable for some period, we are
proposing that the facility use the
average of the concentration
measurements from just before and just
after the period of missing data.
There is one proposed exception to
these requirements: If either method
would result in a significant under- or
overestimate of the missing parameter,
then the facility would be required to
develop an alternative estimate of the
parameter and explain why and how it
developed that estimate.
We request comment on these
proposed methods for estimating
missing data.
5. Selection of Data Reporting
Requirements
Under the proposed rule, owners and
operators of facilities producing
fluorinated GHGs would be required to
report both their fluorinated GHG
emissions and the quantities used to
estimate them, including the masses of
the reactants, products, by-products,
and wastes, and, if applicable, the
quantities of any product in the byproducts and/or wastes (if that product
is emitted at the facility). We are
proposing that owners and operators
report annual totals of these quantities.
Where fluorinated GHG production
facilities have estimated missing data,
you would be required to report the
reason the data were missing, the length
of time the data were missing, the
method used to estimate the missing
E:\FR\FM\10APP2.SGM
10APP2
16507
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
data, and the estimates of those data.
Where the missing data was estimated
by a method other than one of those
specified, the owner or operator would
be required to report why the specified
method would lead to a significant
under- or overestimate of the
parameter(s) and the rationale for the
methods used to estimate the missing
data.
We propose that facilities report these
data because the data are necessary to
verify facilities’ calculations of
fluorinated GHG emissions. We request
comment on these proposed reporting
requirements.
6. Selection of Records That Must Be
Retained
Under the proposed rule, owners and
operators of facilities producing
fluorinated GHGs would be required to
retain records documenting the data
reported, including records of daily and
monthly mass-balance calculations and
calibration records for flowmeters,
scales, and gas chromatographs. These
records are necessary to verify that the
GHG emissions monitoring and
calculations were performed correctly.
M. Food Processing
1. Definition of the Source Category
Food processing facilities prepare raw
ingredients for consumption by animals
or humans. Many facilities in the meat
and poultry, and fruit, vegetable, and
juice processing industries have on-site
wastewater treatment. This can include
the use of anaerobic and aerobic
lagoons, screening, fat traps and
dissolved air flotation. These facilities
can also include onsite landfills for
waste disposal. In 2006, CH4 emissions
from wastewater treatment at food
processing facilities were 3.7 million
metric tons CO2e, and CH4 emissions
from onsite landfills were 7.2 million
metric tons CO2e. Data are not available
to estimate stationary fuel combustionrelated GHG emissions at food
processing facilities.
Proposed requirements for stationary
fuel combustion emissions are set forth
in proposed 40 CFR part 98, subpart C.
Wastewater GHG emissions are
described and considered in Section V.II
of this preamble. For more information
on wastewater treatment at food
processing facilities, please refer to the
Food Processing TSD (EPA–HQ–OAR–
2008–0508–013).
Landfill GHG emissions are described
and considered in Section V.HH of this
preamble. For more information on
landfills at food processing facilities,
please refer to the Landfills TSD (EPA–
HQ–OAR–2008–0508–034).
The sources of GHG emissions at food
processing facilities that must be
reported under the proposed rule are
stationary fuel combustion, onsite
landfills and onsite wastewater
treatment.
2. Selection of Reporting Threshold
We considered using annual GHG
emissions-based threshold levels of
1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e for food
processing facilities. The proposed
threshold for reporting emissions from
food processing facilities is 25,000
metric tons CO2e total emissions from
combined stationary fuel combustion,
on-site landfills, and on-site wastewater
treatment. Table M–1 of this preamble
illustrates the emissions and facilities
that would be covered under these
various thresholds.
TABLE M–1. THRESHOLD ANALYSIS FOR FOOD PROCESSING FACILITIES
Emissions covered
Threshold
National
1,000 mtCO2e ..........................................
10,000 mtCO2e ........................................
25,000 mtCO2e ........................................
100,000 mtCO2e ......................................
Total
NE
NE
NE
NE
Metric tons
CO2e/year
5,719
5,719
5,719
5,719
Facilities covered
Percent
NE
NE
NE
NE
Number
NE
NE
NE
NE
Percent
802
170
100
10
14.0
3.0
1.7
0.2
NE = Not Estimated.
Data were unavailable at the time of
this analysis to estimate stationary
combustion emissions onsite, or the colocation of landfills and wastewater
treatment at food processing faculties.
Facility coverage based on onsite
wastewater GHG emissions and landfill
GHG emissions was estimated as
described in the Wastewater Treatment
TSD and Landfills TSD (EPA–HQ–
OAR–2008–0508–035) and (EPA–HQ–
OAR–2008–0508–034). We estimate that
at the 25,000 metric tons CO2e
threshold, a small percentage of
facilities are covered by this rule,
resulting in potentially a large
percentage of emissions data reporting
from this significant emissions source
but avoiding small facilities.
For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
3. Selection of Proposed Monitoring
Methods
Refer to Sections V.C, V.HH, and V.II
of this preamble for monitoring methods
for general stationary fuel combustion
sources, landfills, and wastewater
treatment, respectively, occurring onsite at food production facilities.
4. Selection of Procedures for Estimating
Missing Data
Refer to Sections V.C, V.HH, and V.II
of this preamble for procedures for
estimating missing data for general
stationary fuel combustion sources,
landfills, and wastewater treatment,
respectively, occurring on-site at food
processing facilities.
Fmt 4701
Sfmt 4702
Refer to Sections V.C, V.HH, and V.II
of this preamble for recordkeeping
requirements for general stationary fuel
combustion sources, landfills, and
wastewater treatment, respectively,
occurring on-site at food processing
facilities.
1. Definition of the Source Category
Refer to Sections V.C, V.HH, and V.II
of this preamble for reporting
Frm 00061
6. Selection of Records That Must Be
Maintained
N. Glass Production
5. Selection of Data Reporting
Requirements
PO 00000
requirements for general stationary fuel
combustion, landfills, and wastewater
treatment, respectively, occurring onsite at food processing facilities. In
addition, you would be required to
report the quantity of CO2 captured for
use (if applicable) and the end use, if
known.
Glass is a common commercial item
that is produced by melting a mixture of
E:\FR\FM\10APP2.SGM
10APP2
16508
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
minerals and other substances, then
cooling the molten materials in a
manner that prevents crystallization.
Glass is typically classified as container
glass, flat (or window) glass, or pressed
and blown glass. Pressed and blown
glass includes textile fiberglass, which
is used primarily as a reinforcement
material in a variety of products, as well
as other types of glass. Wool fiberglass,
which is commonly used for insulation,
is generally classified separately from
textile fiberglass and other pressed and
blown glass. However, for the purposes
of GHG reporting, wool fiberglass
production is included in the glass
manufacturing source category.
Glass can be produced using a variety
of raw material formulations. Most
commercial glass is made using a sodalime glass formulation, which consists
of silica (SiO2), soda (Na2O), and lime
(CaO), with small amounts of alumina
(Al2O3), magnesia (MgO), and other
minor ingredients. Several specialty
glasses, including fiberglass, are made
using borosilicate or
aluminoborosilicate recipes, which can
consist primarily of silica and boric
oxides, along with varying amounts of
soda, lime, alumina, and other minor
ingredients. Other formulations used in
the production of specialty glasses
include aluminosilicate and lead silicate
formulations.
Major carbonates used in the
production of glass are limestone
(CaCO3), dolomite (CaMg(CO3)2), and
soda ash (Na2CO3). The use of these
carbonates in the furnace during glass
manufacturing results in a complex
high-temperature reaction that leads to
process-related GHG emissions. Glass
manufacturers may also use recycled
scrap glass (cullet) in the production of
glass, thereby reducing the carbonate
input to the process and resulting GHG
emissions.
National emissions from glass
manufacturing were estimated to be 4.43
million metric tons CO2e (0.1 percent of
U.S. GHG emissions) in 2005. These
emissions include both process-related
emissions (CO2) and on-site stationary
combustion emissions (CO2, CH4, and
N2O) from 374 glass manufacturing
facilities across the U.S. and Puerto
Rico. Process-related emissions account
for 1.65 million metric tons CO2, or 37
percent of the total, while on-site
stationary combustion sources account
for the remaining 2.78 million metric
tons CO2e emissions.
For additional background
information on glass manufacturing,
refer to the Glass Manufacturing TSD
(EPA–HQ–OAR–2008–0508–014).
2. Selection of Reporting Threshold
In developing the threshold for glass
manufacturing, we considered an
emissions-based threshold of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e. Table N–1 of
this preamble summarizes the emissions
and number of facilities that would be
covered under these various thresholds.
TABLE N–1. THRESHOLD ANALYSIS FOR GLASS MANUFACTURING
Total national
emissions
metric tons
CO2e/yr
Threshold level
metric tons CO2e/yr
Emissions covered
Total number
of facilities
Metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
4,425,269
4,425,269
4,425,269
4,425,269
The glass manufacturing industry is
heterogeneous in terms of the types of
facilities. There are some relatively
large, emissions-intensive facilities, but
small artisan shops are common as well.
For example, at a 1,000 metric tons
CO2e threshold, 98 percent of emissions
would be covered, with only 58 percent
of facilities being required to report.
The proposed threshold for reporting
emissions from glass manufacturing is
25,000 metric tons CO2e. We are
proposing a 25,000 metric tons CO2e
threshold to reduce the compliance
burden on small businesses, while still
including half of the GHG emissions
from the industry. In comparison to the
100,000 metric tons CO2e threshold, the
25,000 metric tons CO2e threshold
achieves reporting of 11 times more
emissions while requiring less than 15
percent of the facilities to report.
Compared to the 10,000 metric tons
CO2e threshold, the 25,000 metric tons
CO2e threshold captures more than half
of those emissions, but only requires a
third of the number of reporters. We
consider this a significant coverage of
the emissions, while impacting a
relatively small portion of the industry.
For a full discussion of the threshold
analysis, please refer to the Glass
Manufacturing TSD (EPA–HQ–OAR–
2008–0508–014). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
374
374
374
374
Many of the domestic and
international GHG monitoring
guidelines and protocols include
methodologies for estimating processrelated CO2 emissions from glass
manufacturing (e.g., the 2006 IPCC
Guidelines, U.S. Inventory, the
Technical Guidelines for the DOE
1605(b), and the EU Emissions Trading
System). These methodologies coalesce
around four different options. Two
options are output-based (productionbased): One applies appropriate
emission factors to the type of glass
produced, and the other applies a
default emission factor to total glass
PO 00000
Frm 00062
Fmt 4701
Sfmt 4702
Percent
4,336,892
4,012,319
2,243,583
207,535
3. Selection of Proposed Monitoring
Methods
Facilities covered
Number
98
91
51
5
217
158
55
1
Percent
58
42
15
0.3
production. A third option is based on
measuring the carbonate input to the
furnace. The final option uses direct
measurement to estimate emissions.
Option 1. The first production-based
option we considered applies a default
emission factor to the total quantity of
all glass produced, correcting for the
amount of cullet supplied to the
process.
Option 2. The second productionbased approach we considered applies
default emission factors to each of the
types of glass produced at the facility
(e.g., container, flat, pressed and blown,
and fiberglass).
Option 3. The carbonate-input
approach calculates emissions based on
actual input data and the mass fractions
of the carbonates that are volatilized and
emitted as CO2. More specifically, this
option considers the type, quantity, and
mass fraction of carbonate inputs to the
furnace and develops a facility-specific
emission factor.
Option 4. This approach directly
measures emissions using a CEMS.
CEMS can be used to measure both
combustion-related and process-related
CO2 emissions from glass melting
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
furnaces. These emissions generally are
exhausted through a common furnace
stack. Therefore, separate CEMS would
not be needed to quantify both types of
emissions from glass melting furnaces.
Proposed Option. Under the proposed
rule, if you are required to use an
existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, you would be required to use
CEMS to estimate CO2 emissions. Where
the CEMS capture all combustion- and
process-related CO2 emissions, you
would be required to follow the
requirements of proposed 40 CFR part
98, subpart C to estimate CO2 emissions
from the industrial source.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS would
not adequately account for process
emissions, the proposed monitoring
method would require estimating
combustion emissions and process
emissions separately. For combustion
emissions, you would be required to
follow the requirements of proposed 40
CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary combustion. For process
emissions, the carbonate input approach
(Option 3) is proposed. This section of
the preamble provides only those
procedures for calculating and reporting
process-related emissions.
To estimate process CO2 emissions
from glass melting furnaces, we propose
that facilities measure the type,
quantity, and mass fraction of carbonate
inputs to each furnace and apply the
appropriate emission factors for the
carbonates consumed. This method for
determining process emissions is
consistent with the IPCC Tier 3 method.
The proposed rule distinguishes
between carbonate-based minerals and
carbonate-based raw materials used in
glass production. Carbonate-based raw
materials are fired in the furnace during
glass manufacturing. These raw
materials are typically limestone, which
is primarily CaCO3; dolomite, which is
primarily CaMg(CO3)CO2; and soda ash,
which is primarily NaCO2CO3. Because
it is the calcination of the mineral
fraction of the raw material (e.g., CaCO3
fraction in limestone) that leads to CO2
emissions, the purity of the limestone or
other carbonate input is important for
emissions estimation.
In order to assess the composition of
the carbonate input, we propose that
facilities use data from the raw material
supplier to determine the carbonatebased mineral mass fraction of the
carbonate-based raw materials charged
to an affected glass melting furnace. As
an alternative to using data provided by
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
the supplier, facilities can assume a
value of 1.0 for the mass fraction of the
carbonate-based mineral in the
carbonate-based raw material. We also
propose that emissions are estimated
under the assumption that 100 percent
of the carbon in the carbonate-based raw
materials is volatilized and released
from the furnace as CO2. Using the
carbonate-based mineral mass fractions,
the carbonate-based raw material feed
rates, and the emission factors, the mass
emissions of CO2 emitted from a glass
melting furnace can be determined.
Using values of 1.0 for the carbonatebased mineral mass fractions is based on
the assumption that the raw materials
consist of 100 percent of the respective
carbonate-based mineral (i.e., the
limestone charged to the furnace
consists of 100 percent CaCO3, the
dolomite charged consists of 100
percent CaMg(CO3)2, and the soda ash
consists of 100 percent Na3CO3). Using
this assumption generally overestimates
CO2 emissions. However, given the
relative purity of the raw materials used
to produce glass, this method provides
accurate estimates of process CO2
emissions from glass melting furnaces,
while avoiding the costs associated with
sampling and analysis of the raw
materials.
We have concluded that the carbonate
input method specified in the proposed
option is more certain as it involves
measuring the consumption of each
carbonate material charged to a glass
melting furnace. According to the 2006
IPCC Guidelines, the uncertainty
involved in the proposed carbonate
input approach is 1 to 3 percent; in
contrast, the uncertainty with using the
default emission factor and cullet ratio
for the production-based approach is 60
percent.
We considered use of a CO2 CEMS
which does tend to provide the most
accurate CO2 emissions measurements
and can measure both the combustionand process-related CO2 emissions.
However, given the limited variability
in the process inputs and outputs
contributing to emissions from glass
production, installation of CEMS would
require significant additional burden to
facilities given that few glass facilities
currently have CO2 CEMS.
We also considered, but decided not
to propose, the production-based default
emission factor-based approach
referenced above for quantifying
process-related CO2 emissions based on
the quantity of glass produced. In
general, the default emission factor
method results in less certainty because
the method involves multiplying
production data by emission factors that
are based on default assumptions
PO 00000
Frm 00063
Fmt 4701
Sfmt 4702
16509
regarding carbonate-based mineral
content and degree of calcination.
As part of normal business practices,
glass manufacturing plants maintain the
records that would be needed to
calculate emissions under the proposed
option. Given the greater accuracy
associated with the input method and
the minimal additional burden, we have
determined that this requirement would
not add additional burden to current
practices at the facility, while providing
accurate estimates of process-based CO2
emissions.
The various approaches to monitoring
GHG emissions are elaborated in the
Glass Manufacturing TSD (EPA–HQ–
OAR–2008–0508–014).
4. Selection of Procedures for Estimating
Missing Data
To estimate process emissions of CO2
based on carbonate input, data are
needed on the carbonate chemical
analysis of the carbonate-based raw
materials and the carbonate-based raw
material input rate (process feed rate).
Glass manufacturing facilities must
monitor raw material feed rate carefully
in order to maintain product quality.
Therefore, we do not expect missing
data on raw material input to be an
issue. However, if these data were
missing, we propose requiring facilities
to use average data from the previous
and following months for the mass of
carbonate-based raw materials charged
to the furnace. Given that glass furnaces
generally operate continuously at a
relatively constant production rate, we
do not expect much variation in the
amounts of carbonates charged to the
furnace from month to month.
Furthermore, it would be unusual for a
glass manufacturing plant to change its
glass formulation. Therefore, we believe
using average data from the previous
and following months would provide a
reliable estimate of raw materials
charged.
For missing data on carbonate-based
mineral mass fractions, we propose
requiring facilities to assume that the
mass fraction of each carbonate-based
mineral in the carbonate-based raw
materials is 1.0. This assumption may
result in a slight overestimate of
emissions, but should still provide a
reasonably accurate estimate of
emissions for the period with missing
data.
5. Selection of Data Reporting
Requirements
We propose that facilities report total
annual emissions of CO2 from each
affected continuous glass melting
furnace, as well as any stationary fuel
combustion emissions. The proposed
E:\FR\FM\10APP2.SGM
10APP2
16510
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
rule would also require facilities to
report the quantity of each carbonatebased raw material charged to each
continuous glass melting furnace in tons
per year, and the quantity of glass
produced by each continuous glass
melting furnace. For facilities that
calculate process emissions of CO2
based on the mass fractions of
carbonate-based minerals, the proposed
rule would require facilities to report
those values. These data are requested
because they provide the basis for
calculating process-based CO2 emissions
and are needed for us to understand the
emissions data and verify the
reasonableness of the reported
emissions. The data on raw material
composition and charge rates are
needed to verify process-based
emissions of CO2. The data on glass
production are needed to verify that the
reported quantities of raw materials
charged to continuous furnaces are
reasonable. The production data also
can be used to identify potential
outliers.
A full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and N.
6. Selection of Records That Must Be
Retained
In addition to the data to be reported,
we propose that facilities retain monthly
records of the data used to calculate
GHG emissions. This would include
records of the amounts of each
carbonate-based raw material charged to
a continuous glass melting furnace and
glass production (by type). This
requirement would be consistent with
current business practices and the
reporting requirements for emissions of
other pollutants for the glass
manufacturing industry.
The proposed rule also would require
facilities to retain the results of all tests
used to determine carbonate-based
mineral mass fractions, as well as any
other supporting information used in
the calculation of GHG emissions. These
data are directly used to calculate
emissions that are reported and are
necessary to enable verification that the
GHG emissions monitoring and
calculations were performed correctly.
A full list of records that must be
retained on site is included in proposed
40 CFR part 98, subparts A and N.
O. HCFC–22 Production and HFC–23
Destruction
1. Definition of the Source Category
This source category includes the
generation, emissions, sales, and
destruction of HFC–23. The source
category includes facilities that produce
HCFC–22, generating HFC–23 in the
process. This source category also
includes facilities that destroy HFC–23,
which are sometimes, but not always,
also facilities that produce HCFC–22.
HFC–23 is generated during the
production of HCFC–22. HCFC–22 is
primarily employed in refrigeration and
A/C systems and as a chemical
feedstock for manufacturing synthetic
polymers. Because HCFC–22 depletes
stratospheric O3, its production for nonfeedstock uses is scheduled to be
phased out by 2020 under the CAA.
Feedstock production, however, is
permitted to continue indefinitely.
HCFC–22 is produced by the reaction
of chloroform (CHCl3) and hydrogen
fluoride (HF) in the presence of a
catalyst, SbClB5. In the reaction, the
chlorine in the chloroform is replaced
with fluorine, creating HCFC–22. Some
of the HCFC–22 is over-fluorinated,
producing HFC–23. Once separated
from the HCFC–22, the HFC–23 may be
vented to the atmosphere as an
unwanted by-product, captured for use
in a limited number of applications, or
destroyed.
2006 U.S. emissions of HFC–23 from
HCFC–22 production were estimated to
be 13.8 million metric tons CO2e. This
quantity represents a 13 percent decline
from 2005 emissions and a 62 percent
decline from 1990 emissions despite an
11 percent increase in HCFC–22
production since 1990. Both declines
are primarily due to decreases in the
HFC–23 emission rate. The ratio of
HFC–23 emissions to HCFC–22
production has decreased from 0.022 to
0.0077 since 1990, a reduction of 66
percent. These decreases have occurred
because an increasing fraction of U.S.
HCFC–22 production capacity has
adopted controls to reduce HFC–23
emissions. Three HCFC–22 production
facilities operated in the U.S. in 2006,
two of which used recapture and/or
thermal oxidation to significantly lower
their HFC–23 emissions. All three
plants are part of a voluntary agreement
to report and reduce their collective
HFC–23 emissions.
The production of HCFC–22 and
destruction of HFC–23 causes both
combustion and HFC–23 emissions.
HCFC–22 production and HFC–23
destruction facilities are required to
follow the requirements of proposed 40
CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary fuel combustion. This section
of the preamble provides only those
procedures for calculating and reporting
generation, emissions, sales, and
destruction of HFC–23.
For additional background
information on HCFC–22 production,
please refer to the HCFC–22 Production
and HFC–23 Destruction TSD (EPA–
HQ–OAR–2008–0508–015).
2. Selection of Reporting Threshold
We propose that all facilities
producing HCFC–22 be required to
report under this rule. Facilities
destroying HFC–23 but not producing
HCFC–22 would be required to report if
they destroyed more than 25,000 metric
tons CO2e of HFC–23.
For HCFC–22 production facilities,
we considered emission-based
thresholds of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e
and capacity-based thresholds
equivalent to these. The capacity-based
thresholds are shown in Table O–1 of
this preamble, and are based on full
utilization of HCFC–22 capacity and the
emission rate given for older plants in
the 2006 IPCC Guidelines. (One plant is
relatively new, but the emission rate for
older plants was used to be consistent
and somewhat conservative.)
TABLE O–1. CAPACITY-BASED THRESHOLDS
Threshold level (HCFC–22 capacity in
tons)
2 ...............................................................
21 .............................................................
53 .............................................................
214 ...........................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total national
emissions
(metric tons
CO2e)
Total national
facilities
13,848,483
13,848,483
13,848,483
13,848,483
3
3
3
3
PO 00000
Emissions covered
Frm 00064
Fmt 4701
Metric tons
CO2e/yr
Sfmt 4702
Facilities covered
Percent
13,848,483
13,848,483
13,848,483
13,848,483
E:\FR\FM\10APP2.SGM
100
100
100
100
10APP2
Facilities
Percent
3
3
3
3
100
100
100
100
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Our analysis showed that all of the
facilities, which have capacities ranging
from 18,000 to 100,000 metric tons of
HCFC–22, exceeded all of the capacitybased thresholds by wide margins. The
smallest plant exceeded the largest
capacity-based threshold by a factor of
85.
We are not presenting a table for
emission-based thresholds because we
do not have facility-specific emissions
information. (Under the voluntary
emission reduction agreement, total
emissions from the three facilities are
aggregated by a third party, who submits
only the total to us.) Since two of the
three facilities destroy or capture most
or all of their HFC–23 by-product, one
or both of them probably have emissions
below at least some of the emissionbased thresholds discussed above.
However, if the thermal oxidizers
malfunctioned, were not operated
properly, or were unused for some other
reason, emissions of HFC–23 from each
of the plants could easily exceed all
thresholds. Reporting is therefore
important both for tracking the
considerable emissions of facilities that
do not use thermal oxidation and for
verifying the performance of thermal
oxidation where it is used. For this
reason, we propose that all HCFC–22
manufacturers report their HFC–23
emissions.
We are aware of one facility that
destroys HFC–23 but does not produce
HCFC–22. Although we do not know the
precise quantity of HFC–23 destroyed
by this facility, the Agency has
concluded that the facility destroys a
substantial share of the HFC–23
generated by the largest HCFC–22
production facility in the U.S. If the
destruction facility destroys even one
percent of this HFC–23, it is likely to
destroy considerably more than the
proposed threshold of 25,000 metric
tons CO2e.
For additional background
information on the threshold analysis
for HCFC–22 production, please refer to
the HCFC–22 Production and HFC–23
Destruction TSD (EPA–HQ–OAR–2008–
0508–015). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
a. Review of Monitoring Methods
In developing these proposed
requirements, we reviewed several
protocols and guidance documents,
including the 2006 IPCC Guidelines,
guidance developed under our
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
voluntary program for HCFC–22
manufacturers, the WRI/WBCSD
protocols, the TRI, the TSCA Inventory
Update Rule, The DOE 1605(b)
Voluntary Reporting Program, EPA
Climate Leaders, and TRI.
We also considered the findings and
conclusions of a recent report that
closely reviewed the methods that
facilities use to estimate and assure the
quality of their estimates of HCFC–22
production and HFC–23 emissions. As
noted above, the production facilities
currently estimate and report these
quantities to us (across all three plants)
under a voluntary agreement. The
report, by RTI International, is entitled
‘‘Verification of Emission Estimates of
HFC–23 from the Production of HCFC–
22: Emissions from 1990 through 2006’’
and is available in the docket for this
rulemaking.
The 2008 Verification Report found
that the estimation methods used by the
three HCFC–22 facilities currently
operating in the U.S. were all equivalent
to IPCC Tier 3 methods. Under the Tier
3 methodology, facility-specific
emissions are estimated based on direct
measurement of the HFC–23
concentration and the flow rate of the
streams, accounting for the use of
emissions abatement devices (thermal
oxidizers) where they are used. In
general, Tier 3 methods for this source
category yield far more accurate
estimates than Tier 2 or Tier 1 methods.
Even at the Tier 3 level, however, the
emissions estimation methods used by
the three facilities differed significantly
in their levels of absolute uncertainty.
The uncertainty of the one facility that
does not thermally destroy its HFC–23
emissions dominates the uncertainty for
the national emissions from this source
category.
In general, the methods proposed in
this rule are very similar to the
procedures already being undertaken by
the facilities to estimate HFC–23
emissions and to assure the quality of
these estimates. The differences (and the
rationale for them) are discussed in the
HCFC–22 Production and HFC–23
Destruction TSD (EPA–HQ–OAR–2008–
0508–015).
b. Proposed Monitoring Methods
This section of the preamble includes
two proposed monitoring methods for
HCFC–22 production facilities and one
for HFC–23 destruction facilities. The
proposed monitoring methods differ for
HCFC–22 facilities that do and do not
use a thermal oxidizer connected to the
HCFC–22 production equipment. All
the monitoring methods rely on
measurements of HFC–23
concentrations in process or emission
PO 00000
Frm 00065
Fmt 4701
Sfmt 4702
16511
streams and on measurements of the
flow rates of those streams, although the
proposed frequency of these
measurements varies.
Proposed Methods for Estimating
HFC–23 Emissions from Facilities that
Do Not Use a Thermal Oxidizer or
Facilities that Use a Thermal Oxidizer
that is Not Directly Connected to the
HCFC–22 Production Equipment. Under
the proposed rule, you would be
required to:
(1) Monitor the concentration of HFC–
23 in the reaction product stream
containing the HFC–23 (which could be
either the HCFC–22 or the HCl product
stream) on at least a daily basis. This
proposed requirement is intended to
account for day-to-day fluctuations in
the rate at which HFC–23 is generated;
this rate can vary depending on process
conditions.
(2) Monitor the mass flow of the
product stream containing the HFC–23
either directly or by weighing the other
reaction product. The other product
could be either HCFC–22 or HCl. Plants
would be required to make or sum these
measurements on at least a daily basis.
If the HCFC–22 or HCl product were
measured significantly downstream of
the reactor (e.g., at storage tanks or the
shipping dock), facilities would be
required to add a factor that accounted
for losses to the measurement. This
factor would be 1.5 percent or another
factor that could be demonstrated, to the
satisfaction of the Administrator, to
account for losses. This adjustment is
intended to account for upstream
product losses, which are estimated to
range from one to two percent. Without
the adjustment, HCFC–22 production
and therefore HFC–23 generation at
affected facilities would be
systematically underestimated
(negatively biased). A one-to twopercent underestimate could translate
into an underestimate of HFC–23
emissions of 100,000 metric tons CO2e
or more for each affected facility.
We request comment on this proposed
approach for compensating for the
negative bias caused by HCFC–22
emissions. We specifically request
comment on the 1.5 percent factor,
which is the midpoint of the one-to-twopercent range of product loss rates cited
by the affected facility. We also request
comment on what methods and data
would be required to verify a loss rate
other than 1.5 percent, if a facility
wished to demonstrate a lower loss rate.
One option would be a mass-balance
approach using measurements with very
fine precisions (e.g., 0.2 percent or
better).
(3) Facilities that do not use a thermal
oxidizer connected to the HCFC–22
E:\FR\FM\10APP2.SGM
10APP2
16512
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
production equipment would also be
required to estimate the mass of HFC–
23 produced either by multiplying the
HFC–23 concentration measurement by
the mass flow of the stream containing
both the HFC–23 and the other product
or by multiplying the ratio of the
concentrations of HFC–23 and of the
other product by the mass of the other
product.
(4) Facilities would also be required
to measure the masses of HFC–23 sold
or sent to other facilities for destruction.
This step would ensure that any losses
of HFC–23 during filling of containers
were included in the HFC–23 emission
estimates for facilities that capture
HFC–23 for use as a product or for
transfer to a destruction facility.
(5) Facilities would also be required
to estimate the HFC–23 emitted by
subtracting the masses of HFC–23 sold
or sent for destruction from the mass of
HFC–23 generated.
This calculation assumes that all
production that is not sold or sent to
another facility for destruction is
emitted. Such emissions may be the
result of the packaging process;
additional emissions can be attributed
to the number of flanges in a line and
other on-site equipment that is specific
to each facility.
Proposed Methods for Estimating
HFC–23 Emissions from Plants that Use
a Thermal Oxidizer Connected to the
HCFC–22 Production Equipment. Under
the proposed rule, you would be
required to estimate HFC–23 emissions
from equipment leaks, process vents,
and the thermal oxidizer. To estimate
emissions from leaks, you would be
required to estimate the number of leaks
using EPA Method 21 of 40 CFR part 60,
Appendix A–7 and a leak definition of
10,000 ppmv. Leaks registering above
and below 10,000 ppmv would be
assigned different default emission
rates, depending on the component and
service (gas or light liquid). These leak
rates would be drawn from Table 2–5
from the Protocol for Equipment Leak
Estimates (EPA–453/R–95–017) and
data on the concentration of HFC–23 in
the process stream.78 (The relevant
portions of Table 2–5 are included in
the proposed regulatory text for this
rule.) To estimate emissions from
process vents, you would be required to
use the results of annual emissions tests
at process vents, adjusting for changes
78 Although EPA recognizes that the proposed
method for estimating emissions from equipment
leaks is rather uncertain, EPA believes that the level
of precision is not unreasonable given the small size
of the HFC–23 emissions that would be estimated
using the method. These emissions are estimated to
account for a fraction of a percent of U.S. HFC–23
emissions from this source.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
in HCFC–22 production rates since the
measurements occurred. Tests would
have to be conducted in accordance
with EPA Method 18 of 40 CFR part 60,
Appendix A–6, Measurement of
Gaseous Organic Compounds by Gas
Chromatography. Although HFC–23
emissions from process vents are
believed to be quite low, this monitoring
would ensure that any year-to-year
variability in the emission rate was
captured by the reporting. Finally, to
estimate emissions from the thermal
oxidizer, you would be required to
apply the DE of the oxidizer to the mass
of HFC–23 fed into the oxidizer.
Destruction. Under the proposed rule,
if you use thermal oxidation to destroy
HFC–23 you would be required to
measure the quantities of HFC–23 fed
into the oxidizer. You would also be
required to account for any decreases in
the DE of the oxidizer that occurred
when the oxidizer was not operating
properly (as defined in State or local
permitting requirements and/or oxidizer
manufacturer specifications). Finally,
you would be required to perform
annual HFC–23 concentration
measurements by gas chromatography to
confirm that emissions from the
oxidizer were as low as expected based
on the rated DE of the device. If
emissions were found to be higher, then
facilities would have the option of using
the DE implied by the most recent
measurements or of conducting more
extensive measurements of the DE of the
device.
As discussed in the HCFC–22
Production and HFC–23 Destruction
TSD (EPA–HQ–OAR–2008–0508–015),
the initial testing and parametric
monitoring that facilities currently
perform on their oxidizers provides
general assurance that the oxidizer is
performing correctly. However, the
proposed requirement to measure HFC–
23 concentrations at the oxidizer outlet
would provide additional assurance at
relatively low cost. Even a one- or twopercent decline in the DE of the oxidizer
could lead to emissions of over 100,000
metric tons CO2e, making this a
particularly important factor to monitor
accurately.
Startups, shutdowns, and
malfunctions. Under the proposed rule,
if you produce HCFC–22 you would be
required to account for HFC–23
production and emissions that occur as
a result of startups, shutdowns, and
malfunctions. This would be done
either by recording HFC–23 production
and emissions during these events, or
documenting that these events do not
result in significant HFC–23 production
and/or emissions. Depending on the
circumstances, startups, shutdowns, and
PO 00000
Frm 00066
Fmt 4701
Sfmt 4702
malfunctions (including both the
process equipment and any thermal
oxidation equipment) can be significant
sources of emissions, and the Agency
believes that emissions during these
process disturbances should therefore
be tracked.
Precision and Accuracy
Requirements. We are proposing to
require that HCFC–22 production
facilities and HFC–23 destruction
facilities monitor the masses that would
be reported under this rule using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 1.0 percent of full scale or
better. Our understanding is that some
HCFC–22 production facilities currently
use devices with this level of accuracy
and precision. However, flowmeters
with considerably better precisions are
available, e.g., 0.2 percent. We request
comment on the option of requiring
plants to use flowmeters or scales with
an accuracy and precision of 0.2 percent
or some other precision better than 1
percent. Given the large quantities of
HFC–23 generated by each plant, this
higher precision may be appropriate.
We are also proposing to require that
HCFC–22 production facilities and
HFC–23 destruction facilities measure
concentrations using equipment and
methods with an accuracy and precision
of 5 percent or better at the
concentrations of the samples.
Calibration Requirements. Under the
proposed rule, if you produce HCFC–22
or destroy HFC–23 you would be
required to perform the following
activities to assure the quality of their
measurements and estimates:
(1) Calibrate gas chromatographs used
to determine the concentration of HFC–
23 by analyzing, on a monthly basis,
certified standards with known HFC–23
concentrations that are in the same
range (percent levels) as the process
samples. This proposed requirement is
intended to verify the accuracy and
precision of gas chromatographs at the
concentrations of interest; calibration at
other concentrations does not verify this
accuracy with the same level of
assurance. The proposed requirement is
similar to requirements in protocols for
the use of gas chromatography, such as
EPA Method 18, Measurement of
Gaseous Organic Compound Emissions
by Gas Chromatography.
(2) Initially verify each weigh scale,
flow meter, and combination of
volumetric and density measurements
used to measure quantities that are to be
reported under this rule, and calibrate it
thereafter at least every year. We request
comment on these proposed
requirements.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
4. Selection of Procedures for Estimating
Missing Data
We are proposing that in the cases
when an upstream flow meter (i.e., near
reactor outlet) is ordinarily used but is
not available for some period, the
facility can compensate by using
downstream production measures (e.g.,
quantity shipped) and adding 1.5
percent to account for product losses. If
HFC–23 concentration measurements
are unavailable for some period, we
propose that the facility use the average
of the concentration measurements from
just before and just after the period of
missing data.
There is one proposed exception to
these requirements: If either method
would result in a significant under- or
overestimate of the missing parameter
(e.g., because the monitoring failure was
linked to a process disturbance that is
likely to have significantly increased the
HFC–23 generation rate), then the
facility would be required to develop an
alternative estimate of the parameter
and explain why and how it developed
that estimate.
We request comment on these
methods for estimating missing data. We
also request comment on the option of
estimating missing production data
based on consumption of reactants,
assuming complete stoichiometric
conversion.
5. Selection of Data Reporting
Requirements
If you produce HCFC–22 and do not
use a thermal oxidizer connected to the
HCFC–22 production equipment, you
would be required to report the total
mass of the HFC–23 generated in metric
tons, the mass of any HFC–23 packaged
for sale in metric tons, the mass of any
HFC–23 sent off site for destruction in
metric tons, and the mass of HFC–23
emitted in metric tons. If you produce
HCFC–22 and destroy HFC–23 using a
thermal oxidizer connected to the
HCFC–22 production equipment, you
would be required to report the mass of
HFC–23 emitted from the thermal
oxidizer, the mass of HFC–23 emitted
from process vents, and the mass of
HFC–23 emitted from equipment leaks,
in metric tons.
In addition, if you produce HCFC–22
you would also be required to submit
the following supplemental data, as
applicable, for QA purposes: Annual
HCFC–22 production, annual
consumption of reactants (including
factors to account for quantities that
typically remain unreacted), by reactant,
annual mass of materials other than
HCFC–22 and HFC–23 (i.e., unreacted
reactants, HCl and other byproducts)
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
that are permanently removed from the
process, and the method for tracking
startups, shutdowns, and malfunctions
and HFC–23 generation/emissions
during these events. You would also be
required to report the names and
addresses of facilities to which any
HFC–23 was sent for destruction, and
the quantities sent to each.
Where HCFC–22 production facilities
have estimated missing data, you would
be required to report the reason the data
were missing, the length of time the data
were missing, the method used to
estimate the missing data, and the
estimates of those data. Where the
missing data was estimated by a method
other than one of those specified, the
owner or operator would be required to
report why the specified method would
lead to a significant under- or
overestimate of the parameter(s) and the
rationale for the methods used to
estimate the missing data.
If you destroy HFC–23, you would be
required to report the mass of HFC–23
fed into the thermal oxidizer, the mass
of HFC–23 destroyed, and the mass of
HFC–23 emitted from the thermal
oxidizer. You would also be required to
submit the results of your annual HFC–
23 concentration measurements at the
outlet of the oxidizer. In addition, you
would be required to submit a one-time
report similar to that required under
EPA’s stratospheric protection
regulations at 40 CFR 82.13(j).
We propose that facilities report these
data either because the data are
necessary to verify facilities’
calculations of HFC–23 generation,
emissions, or destruction or because the
data allow us to implement other QA
checks (e.g., calculation of an HFC–23/
HCFC–22 generation factor that can be
compared across facilities and over
time). We request comment on these
proposed reporting requirements.
6. Selection of Records That Must Be
Retained
If you produce HCFC–22, you would
be required to keep records of the data
used to estimate emissions and records
documenting the initial and periodic
calibration of the gas chromatographs,
scales, and flowmeters used to measure
the quantities reported under this rule.
If you destroy HFC–23, you would be
required to keep records of information
documenting your one-time and annual
reports.
These records are necessary to enable
verification that the GHG emissions
monitoring and calculations were
performed correctly.
PO 00000
Frm 00067
Fmt 4701
Sfmt 4702
16513
P. Hydrogen Production
1. Definition of the Source Category
Approximately nine million metric
tons of hydrogen are produced in the
U.S. annually. Hydrogen is used for
industrial applications such as
petrochemical production, metallurgy,
and food processing. Some of the largest
users of hydrogen are ammonia
production facilities, petroleum
refineries, and methanol production
facilities.
About 95 percent of all hydrogen
produced in the U.S. today is made from
natural gas via steam methane
reforming. This process consists of two
basic chemical reactions: (1)
Reformation of the CH4 feedstock with
high temperature steam supplied by
burning natural gas to obtain a synthesis
gas (CH4 + H2O = CO + 3H2); and (2)
Using a water-gas shift reaction to form
hydrogen and CO2 from the carbon
monoxide produced in the first step (CO
+ H2O = CO2 + H22).
Other processes used for hydrogen
production include steam naptha
reforming, coal or biomass gasification,
partial oxidation of coal or
hydrocarbons, autothermal reforming,
electrolysis of water, recovery of
byproduct hydrogen from electrolytic
cells used to produce chlorine and other
products, and dissociation of ammonia.
Hydrogen is produced in large
quantities at approximately 77 merchant
hydrogen production facilities (which
produce hydrogen to sell) and 145
captive hydrogen production facilities
(which consume hydrogen at the site
where it is produced, e.g. petroleum
refineries, ammonia, and methanol
facilities). Hydrogen is also produced in
small quantities at numerous other
locations.
National emissions from hydrogen
production were estimated to be
approximately 60 million metric tons
CO2 (1 percent of U.S. GHG emissions)
annually.
The source category covered by the
hydrogen production subpart of the
proposed rule is merchant hydrogen
production. CO2 emissions from captive
hydrogen production facilities at
ammonia facilities, petrochemical
facilities, and petroleum refineries are
covered in proposed 40 CFR part 98,
subparts G, X, and Y, respectively.
For additional background
information on hydrogen production,
please refer to the Hydrogen Production
TSD (EPA–HQ–OAR–2008–0508–016).
2. Selection of Reporting Threshold
In developing the threshold for
hydrogen production, we considered
emissions-based thresholds of 1,000
E:\FR\FM\10APP2.SGM
10APP2
16514
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. This
threshold is based on combined
combustion and process CO2 emissions
at the hydrogen production facility.
In selecting a threshold, we
considered emissions data from
merchant hydrogen facilities only,
which together account for an estimated
15.2 million metric tons CO2e in 2006.
Table P–1 of this preamble illustrates
the emissions and facilities that would
be covered under these various
thresholds.
TABLE P–1. THRESHOLD ANALYSIS FOR HYDROGEN PRODUCTION
H2 Production
capacity (tons
H2/year)
CO2 Threshold level (metric tons CO2e/year)
No threshold .........................................................................
1,000 ....................................................................................
10,000 ..................................................................................
25,000 ..................................................................................
100,000 ................................................................................
The hydrogen production industry is
heterogeneous in terms of the types of
facilities. There are some relatively
large, emissions intensive facilities, but
small facilities are common as well. At
a 25,000 ton threshold, although 98.4
percent of emissions would be covered,
only 53 percent of facilities would be
required to report.
The proposed threshold for reporting
emissions from hydrogen production is
25,000 metric tons CO2e. We are
proposing a 25,000 metric tons CO2e
threshold to reduce the compliance
burden on small businesses, while still
including a majority of GHG emissions
from the industry.
For a full discussion of the threshold
analysis, please refer to the Hydrogen
Production TSD (EPA–HQ–OAR–2008–
0508–016). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
Several domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from hydrogen production (e.g., the
American Petroleum Institute
Compendium, the DOE 1605(b), and the
CARB Mandatory GHG Emissions
Reporting Program). These methods
coalesce around variants of two
methods for merchant hydrogen
production facilities: Direct
measurement of CO2 emissions by
CEMS, and the feedstock material
balance method.
Option 1. Direct measurement. The
CEMS would capture both combustion
and process-related CO2 emissions from
a hydrogen facility. Facilities that do not
currently employ a CEMS could
voluntarily elect to install CEMS for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Tons CO2e/
year
0
116
1,160
2,900
11,600
PO 00000
Frm 00068
Fmt 4701
Sfmt 4702
Percent
15,226,620
15,225,220
15,130,255
14,984,365
14,251,265
reporting under this subpart. This
approach is consistent with DOE’s
1605(b) ‘‘A’’ rated method and the
CARB Mandatory GHG Emissions
Reporting Program.
Option 2. Feedstock material balance
method. This method accounts for the
difference between the quantity and
carbon content of all feedstock delivered
to the facility and of all products leaving
the facility. This approach is consistent
with IPCC Tier 3 methods for similar
processes (i.e., steam reformation in
ammonia production), the DOE 1605(b)
‘‘A’’ rated method, and the CARB
Mandatory GHG Emissions Reporting
Program.
Based on our review of the above
approaches, we propose both methods
for quantifying GHG emissions from
hydrogen production, to be
implemented depending on current
circumstances at your facility. If you are
required to use an existing CEMS to
meet the requirements outlined in
proposed 40 CFR part 98, subpart C, you
would be required to use CEMS to
estimate CO2 emissions. Where the
CEMS capture combustion- and processrelated CO2 emissions you would be
required to follow the calculation
procedures, monitoring and QA/QC
methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
CO2 emissions from the industrial
source. Also, refer to proposed 40 CFR
part 98, subpart C to estimate
combustion-related emissions from fuels
not captured in the CEMS, as well as
CH4 and N2O.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS does not
measure process emissions, the
proposed monitoring method is Option
2. You would be required to follow the
Facilities covered
100.0
100.0
99.4
98.4
93.6
Number
Percent
77
73
51
41
30
100
95
66
53
39
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
combustion-related emissions from each
hydrogen production unit and any other
stationary combustion units. This
section of the preamble provides only
those procedures for calculating and
reporting process-related CO2 emissions.
For CO2 collected and used onsite or
transferred offsite, you must follow the
methodology provided in proposed 40
CFR part 98, subpart PP of this part
(Suppliers of CO2).
The feedstock material balance
method entails measurements of the
quantity and carbon content of all
feedstock delivered to the facility and of
all products leaving the facility, with
the assumption that all the carbon
entering the facility in the feedstock that
is not captured and sold outside the
facility is converted to CO2 and emitted.
The quantity of feedstock consumed
must be measured continuously using a
flowmeter. The carbon fraction in the
feedstock may be provided as part of an
ultimate analysis performed by the
supplier (e.g., the local gas utility in the
case of natural gas feedstock). If the
feedstock supplier does not provide the
gas composition or ultimate analysis
data, the facility would be required to
analyze the carbon content of the
feedstock on a monthly basis using the
appropriate test method in proposed 40
CFR 98.7.
We also considered three other
methods for quantifying process-related
emissions. The first method requires
direct measurement of emissions by
CEMS from all reporting facilities. The
second method applies a constant
proportionality factor, based on the
facility’s historical data on natural gas
consumption, to the facility’s hydrogen
production rate. The third method we
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
considered applies a national default
emission factor to the natural gas
consumption rate at a facility.
The first method would generally
increase accuracy of reported data. We
invite comment on the practicality of
adopting the first method. In general,
the latter two methods are less certain,
as they involve multiplying production
and feedstock consumption data by
default emission factors based on purity
assumptions.
In contrast, the feedstock material
balance method is more certain as it
involves measuring the consumption
and carbon content of the feedstock
input. Because 95 percent of hydrogen
is produced using steam methane
reforming, and the carbon content of
natural gas is always within 1 percent
of the ratio: One mole of carbon per
mole of natural gas, the local utility
QA/QC requirements should be more
than adequate.
Given the increase in accuracy of the
direct measurement and feedstock
material balance methods coupled with
the minimal additional burden for
facilities that already employ CEMS, we
propose that facilities utilize the direct
measurement method where currently
employed, and the feedstock material
balance method for all facilities that do
not employ CEMS. We have concluded
that this requirement does not add
additional burden to current practices at
the facilities, thereby minimizing costs.
The primary additional burden for
facilities associated with this method
would be in conducting a gas
composition analysis of the feedstock on
a monthly basis, in cases where this
information is not provided by the
supplier.
The various approaches to monitoring
GHG emissions are elaborated in the
Hydrogen Production TSD (EPA–HQ–
OAR–2008–0508–016).
4. Selection of Procedures for Estimating
Missing Data
Sources using CEMS to comply with
this rule would be required to comply
with the missing data requirements of
proposed 40 CFR part 98, subpart C.
In the event that a facility lacks
feedstock supply rates for a certain time
period, we propose that facilities use the
lesser of the maximum supply rate that
the unit is capable of processing or the
maximum supply rate that the meter can
measure. In the event that a monthly
value for carbon content is determined
to be invalid, an additional sample must
be collected and tested. The likelihood
for missing data is small, since the fuel
meter and carbon content data are
needed for financial accounting
purposes.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
5. Selection of Data Reporting
Requirements
We propose that facilities submit their
annual CO2, and N2O emissions data.
Facilities that use CEMS must comply
with the procedures specified in
proposed 40 CFR 98.36(d)(iv). In
addition, we propose that facilities
submit the following data on an annual
basis for each process unit. These data
are needed for us to understand the
emissions data and verify the
reasonableness of the reported
emissions, and are the basis of the
feedstock material balance calculation.
The data should include the total
quantity of feedstock consumed for
hydrogen production, the quantity of
CO2 captured for use and the end use,
if known, the monthly analyses of
carbon content for each feedstock used
in hydrogen production, the annual
quantity of hydrogen produced, and the
annual ammonia produced, if
applicable.
A full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and P.
6. Selection of Records That Must Be
Retained
We propose that each hydrogen
production facility comply with the
applicable recordkeeping requirements
for stationary combustion units in
proposed 40 CFR part 98, subpart C,
which are also discussed in Section V.C
of this preamble.
Also, we propose that each hydrogen
production facility maintain records of
feedstock consumption and the method
used to determine the quantity of
feedstock consumption, QA/QC records
(including calibration records and any
records required by the QAPP), monthly
carbon content analyses, and the
method used to determine the carbon
content. A full list of records that must
be retained onsite is included in
proposed 40 CFR part 98, subparts A
and P. These records consist of values
that are directly used to calculate the
emissions that are reported and are
necessary to enable verification that the
GHG emissions monitoring and
calculations were done correctly.
Q. Iron and Steel Production
1. Definition of the Source Category
The iron and steel industry in the U.S.
is the third largest in the world,
accounting for about 8 percent of the
world’s raw iron and steel production
and supplying several industrial sectors,
such as construction (building and
bridge skeletons and supports), vehicle
bodies, appliances, tools, and heavy
equipment. In this proposed rule, we are
PO 00000
Frm 00069
Fmt 4701
Sfmt 4702
16515
defining the iron and steel production
source category to be taconite iron ore
processing facilities, integrated iron and
steelmaking facilities, electric arc
furnace steelmaking facilities that are
not located at integrated iron and steel
facilities, and cokemaking facilities that
are not located at integrated iron and
steel facilities. Coke, sinter, and electric
arc furnace steel production operations
at integrated iron and steel facilities are
part of integrated iron and steel
facilities. Direct reduced iron furnaces
are located at and are part of electric arc
furnace steelmaking facilities.
Currently, there are 18 integrated iron
and steel steelmaking facilities that
make iron from iron ore and coke in a
blast furnace and refine the molten iron
(and some ferrous scrap) in a basic
oxygen furnace to make steel. In
addition, there are over 90 electric arc
furnace steelmaking facilities that
produce steel primarily from recycled
ferrous scrap. There are also eight
taconite iron ore (pellet) processing
facilities, 18 cokemaking facilities,
seven of which are co-located at
integrated iron and steel facilities, and
one direct reduced iron furnace located
at an electric arc furnace steelmaking
facility.
The primary operation units that emit
GHG emissions are blast furnace stoves
(24 million metric tons CO2e/yr),
taconite indurating furnaces, basic
oxygen furnaces, electric arc furnaces
(about 5 million metric tons CO2e/yr
each), coke oven battery combustion
stacks (6 million metric tons CO2e/yr),
and sinter plants (3 million metric tons
CO2e/yr). Smaller amounts of GHG
emissions are produced by coke pushing
(160,000 metric tons CO2e/yr) and direct
reduced iron furnaces (140,000 metric
tons CO2e/yr).
Based on production in 2007, GHG
emissions from the source category are
estimated at about 85 million metric
tons CO2e/yr or just over 1 percent of
total U.S. GHG emissions. Emissions
from both process units (47 million
metric tons CO2e/yr) and miscellaneous
combustion units (38 million metric
tons CO2e/yr) are significant. Small
amounts of N2O and CH4 are also
emitted during the combustion of
different types of fuels.
Although by-product recovery coke
batteries and blast furnaces operations
produce coke and pig iron, respectively,
we are proposing that their emissions be
reported as required for combustion
units in proposed 40 CFR part 98,
subpart C because the majority of their
GHG emissions originate from fuel
combustion. Emissions from the blast
furnace operation occur primarily from
the combustion of blast furnace gas and
E:\FR\FM\10APP2.SGM
10APP2
16516
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
natural gas in the blast furnace stoves.
Emissions from by-product recovery
coke batteries are generated from the
combustion of coke oven gas in the coke
battery’s underfiring system. In addition
to the blast furnace stoves and byproduct coke battery underfiring
systems, the other combustion units
where fuel is the only source of GHG
emissions include boilers, process
heaters, reheat and annealing furnaces,
flares, flame suppression systems, ladle
reheaters, and other miscellaneous
sources. Emissions from these other
combustion sources in 2007 are
estimated at 16.8 million metric tons
CO2e/yr for integrated iron and steel
facilities, 18.6 million metric tons
CO2e/yr for electric arc furnace
steelmaking facilities, and 2.7 million
metric tons CO2e/yr for coke facilities
not located at integrated iron and steel
facilities. As noted, the proposed
requirements for combustion units in
proposed 40 CFR part 98, subpart C
would apply for estimating the CO2,
CH4, and N2O emissions from the
following combustion units:
• By-product recovery coke oven
battery combustion stacks.
• Blast furnace stoves.
• Boilers.
• Process heaters.
• Reheat furnaces.
• Annealing furnaces.
• Flares.
• Ladle reheaters.
• Other miscellaneous combustion
sources.
Emissions from the remaining
operation units are generated from the
carbon in process inputs and in some
cases, from fuel combustion in the
process. The process-related CO2, CH4
and N2O emissions from the operation
units listed below except for coke
pushing would be reported according to
the proposed requirements in this
section:
• Taconite indurating furnaces.
• Nonrecovery coke oven battery
combustion stacks.
• Coke pushing.
• Basic oxygen furnaces.
• Electric arc furnaces.
• Direct reduced iron furnaces.
• Sinter plants.
Emissions from nonrecovery coke
batteries do not result from the
combustion of a fuel input. In the
nonrecovery battery, the volatiles that
evolve as the coal is heated are ignited
in the crown above the coal mass and
in flues used to heat the oven. All of the
combustible compounds distilled from
the coal are burned, and the exhaust
gases containing CO2 are emitted
through the battery’s combustion stack.
For all types of coke batteries, a small
amount of CO2 is formed when the
incandescent coke is pushed from the
oven, and prior to quenching with
water, some of the coke burns. The CO2
emissions from taconite plants come
primarily from the indurating furnaces
where coal and/or natural gas are
burned in the pelletizing process, and
carbon in the process feed materials
(iron ore, limestone, bentonite) is
converted to CO2. The CO2 emissions
from direct reduced iron furnaces result
from the combustion of natural gas in
the furnace and from the process inputs,
primarily from the carbonaceous
materials (such as coal or coke) that is
mixed with iron ore. During steelmaking
in the basic oxygen furnace, most of the
GHGs result from blowing oxygen into
the molten iron to produce steel by
removing carbon, primarily as CO2. CO2
emissions also result from the addition
of fluxing materials and other process
inputs that may contain carbon.
Emissions from electric arc furnaces are
produced by the same mechanisms as
for basic oxygen furnaces, and in
addition, the consumption of carbon
electrodes during the melting and
refining stages contribute to CO2
emissions.
Emissions of CH4 and N2O occur from
the combustion of fuels in both
combustion units and process units. For
fuels that contain CH4, combustion of
CH4 is not complete, and a small
amount of CH4 is not burned and is
emitted. In addition, a small amount of
N2O can be formed as a by-product of
combustion from the air (nitrogen and
oxygen) that is required for combustion.
Additional background information
about GHG emissions from the iron and
steel production source category is
available in the Iron and Steel
Production TSD (EPA–HQ–OAR–2008–
0508–017).
2. Selection of Reporting Threshold
In evaluating potential thresholds for
iron and steel production, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e per year. This
threshold is based on combined
combustion and process CO2 emissions
at an iron and steel production facility.
Table Q–1 of this preamble illustrates
that the various thresholds do not have
a significant effect on the amount of
emissions that would be covered. To
avoid placing a reporting burden on the
smaller specialty stainless steel
producers which may operate as small
businesses while still requiring the
reporting of GHG emissions from those
facilities releasing most of the GHG
emissions in this source category, we
are proposing a threshold of 25,000
metric tons CO2e per year for reporting
of emissions. This threshold level is
consistent with the threshold level
being proposed for other source
categories with similar facility size
characteristics. We are proposing that
facilities emitting greater than 25,000 in
the iron and steel production source
category would be subject to the
proposed rule because of the magnitude
of their emissions. All integrated iron
and steel facilities and taconite facilities
exceed the highest emissions threshold
considered. Most electric arc furnace
facilities (with the possible exception of
about 9 facilities) exceed the 25,000
metric tons CO2e emissions threshold.
Requiring facilities that emit 25,000
metric tons CO2e a year or more to
report would capture nearly 100 percent
of the emissions without significantly
increasing the number of affected
facilities.
For a full discussion of the threshold
analysis, refer to the Iron and Steel
Production TSD (EPA–HQ–OAR–2008–
0508–017). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
TABLE Q–1. THRESHOLD ANALYSIS FOR IRON AND STEEL PRODUCTION
Threshold level metric tons CO2e
all in ..........................................................
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total national
emissions
(metric tons
CO2e)
Emissions covered
Total number
of facilities
85,150,877
85,150,877
85,150,877
85,150,877
PO 00000
Frm 00070
Metric tons
CO2e/yr
130
130
130
130
Fmt 4701
Sfmt 4702
Facilities covered
Percent
85,150,877
85,150,877
85,141,500
85,013,059
E:\FR\FM\10APP2.SGM
100
100
100
100
10APP2
Number
130
130
128
121
Percent
100
100
98
93
16517
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE Q–1. THRESHOLD ANALYSIS FOR IRON AND STEEL PRODUCTION—Continued
Threshold level metric tons CO2e
Total national
emissions
(metric tons
CO2e)
100,000 ....................................................
85,150,877
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating emissions from process and
combustion sources (e.g. 2006 IPCC
Guidelines, U.S. Inventory, the WBCSD/
WRI GHG protocol, DOE 1605(b), TCR,
EU Emissions Trading System, the
American Iron and Steel Institute
Protocol, International Iron and Steel
Institute Protocol, and Environment
Canada’s mandatory reporting
guidelines). We considered these
methodologies for measuring or
estimating GHG emissions from the iron
and steel source category. The following
five options were considered for
reporting process-related CO2 emissions
from these sources.
Option 1. Apply a default emission
factor based on the type of process and
an annual activity rate (e.g. quantity of
raw steel, sinter, or direct reduced iron
produced). This option is the same as
the IPCC Tier 1 approach.
Option 2. Perform a carbon balance of
all inputs and outputs using default or
typical values for the carbon content of
the inputs and outputs. Facility
production and other records would be
used to determine the annual quantity
of process inputs and outputs. CO2
emissions from the difference of carbonin minus carbon-out, assuming all is
converted to CO2, would be calculated.
This option is the same as the IPCC Tier
2 approach, the WRI default approach,
and the DOE 1605(b) approach that is
rated ‘‘B.’’ It is similar to the approach
recommended by American Iron and
Steel Institute except that the carbon
balance for Option 2 is based on the
individual processes rather than the
entire plant.
Option 3. Perform a monthly carbon
balance of all inputs and outputs using
measurements of the carbon content of
specific process inputs and process
outputs and measure the mass rate of
process inputs and process outputs.
Calculate CO2 emissions from the
difference of carbon-in minus carbonout assuming all is converted to CO2.
This is consistent with an IPCC Tier 3
approach (if direct measurements are
not available), the WRI/WBCSD
preferred approach, the approach used
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
Metric tons
CO2e/yr
130
PO 00000
Frm 00071
Fmt 4701
Sfmt 4702
Percent
84,468,696
in the EU Emissions Trading System,
and the DOE 1605(b) approach that is
rated ‘‘A.’’
Option 4. Develop a site-specific
emission factor based on simultaneous
and accurate measurements of CO2
emissions and production rate or
process input rate during representative
operating conditions. Multiply the sitespecific factor by the annual production
rate or appropriate periodic production
rate (or process input rate, as
appropriate). This approach is included
in Environment Canada’s methodologies
and might be considered a form of direct
measurement consistent with the IPCC’s
Tier 3 approach.
Option 5. Direct and continuous
measurement of CO2 emissions using
CEMS for CO2 concentration and stack
gas volumetric flow rate based on the
requirements in 40 CFR part 75. This is
the IPCC Tier 3 approach (direct
measurement).
Proposed option. Under this proposed
rule, if you are required to use an
existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, you would be required to use
CEMS to estimate CO2 emissions. Where
the CEMS capture all combustion- and
process-related CO2 emissions you
would be required to follow the
requirements of proposed 40 CFR part
98, subpart C to estimate CO2 emissions
from the industrial source. Also, you
would use proposed 40 CFR part 98,
subpart C to estimate combustionrelated CH4 and N2O.
If you do not currently have CEMS
that meet the requirements outlined in
proposed 40 CFR part 98, subpart C, or
where the CEMS would not adequately
account for process emissions, we
propose that Options 3, 4 or 5 could be
implemented. You would be required to
follow the requirements of proposed 40
CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary combustion. This section of
the preamble provides procedures only
for calculating and reporting processrelated emissions.
We identified Options 3, 4, and 5 as
the approaches that have acceptable
uncertainty for facility-specific
estimates. All of these options would
provide insight into different levels of
emissions caused by facility-specific
Facilities covered
99.2
Number
111
Percent
85
differences in feedstock or process
operation. Options 3, 4, and 5 are forms
of the IPCC’s highest tier methodology
(Tier 3), therefore, we propose these
options as equal options. After
consideration of public comments, we
may promulgate one or more of the
options or a combination based on the
additional information that is provided.
We considered but decided against
Options 1 and 2 because the use of
default values and lack of direct
measurements results in a very high
level of uncertainty in the emission
estimates. These default approaches
would not provide site-specific
estimates of emissions that would
reflect differences in feedstocks,
operating conditions, fuel combustion
efficiency, variability in fuels and other
differences among facilities. In general,
we decided against proposing existing
methodologies that relied on default
emission factors or default values for
carbon content of materials because the
differences among facilities described
above could not be discerned, and such
default approaches are inherently
inaccurate for site-specific
determinations. The use of default
values is more appropriate for sector
wide or national total estimates from
aggregated activity data than for
determining emissions from a specific
facility. According to the IPCC’s 2006
guidelines, the uncertainty associated
with default emission factors for
Options 1 and 2 is ±25 percent, and the
uncertainty in the production data used
with the default emission factor is ±10
percent, which results in a combined
overall uncertainty greater than ±25
percent. If process-specific carbon
contents and actual mass rate data for
the process inputs and outputs are used
(i.e., Option 3) or if direct measurements
are used (i.e., Options 4 and 5), the
guidelines state that the uncertainty
associated with the emission estimates
would be reduced.
For Option 3, we are proposing that
facilities may estimate process
emissions based on a carbon balance
that uses facility-specific information on
the carbon content of process inputs and
outputs and measurements of the mass
rate of process inputs and outputs.
Monthly determinations of the mass of
process inputs and outputs other than
E:\FR\FM\10APP2.SGM
10APP2
16518
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
fuels would be required. These data are
readily available for almost all process
inputs and outputs on a monthly basis
from purchasing, accounting, and
production records that are routinely
maintained by each facility. The mass
rates of fuels would be measured
according to the procedures for fuels in
combustion units in proposed 40 CFR
part 98, subpart C. The carbon content
of each process input and output other
than fuels would also be measured each
month. A sample would be taken each
week, composited for the monthly
analysis, and sent to an independent
laboratory for analysis of carbon content
using the test methods in proposed 40
CFR part 98, subpart A. The carbon
content of fuels would be determined
using the procedures for fuels in
combustion units in proposed 40 CFR
part 98, subpart C. The CO2 emissions
would be estimated each month using
the carbon balance equations in the
proposed rule and then summed to
provide the totals for the quarter and for
the year.
While this proposed approach is
consistent with how iron and steel
production facilities are currently
developing facility level GHG
inventories, there are three components
of this approach for which the Agency
is requesting comment and supporting
information. One issue is the ability to
obtain accurate measurements of the
process inputs and outputs, especially
materials that are bulk solids and
molten metal and slag. A second issue
is the ability to obtain representative
samples of the process inputs and
outputs to determine the carbon
content, especially for non-homogenous
materials such as iron and steel scrap.
The third issue is the level of
uncertainty in the emission estimates
for processes where there is a significant
amount of carbon leaving the process
with product (such as coke plants).
These and other factors may result in an
unacceptable level of uncertainty,
especially for certain processes, when
using the carbon balance approach to
estimate emissions.
While we are proposing that
emissions from blast furnace stoves and
coke battery combustion stacks be
reported as would be required for
combustion sources under proposed 40
CFR part 98, subpart C, we are also
requesting comment on how the carbon
balance approach (Option 3) could be
implemented as an alternative
monitoring option for the entire blast
furnace operation and the entire coke
plant operation at integrated iron and
steel facilities. Comments should
address the advantages, disadvantages,
types and frequency of measurements
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
that should be required, and whether
(and if so, how) the emissions can be
determined with reasonable certainty.
Comments must demonstrate that the
procedures produce results that are
reproducible and clearly specify the
sampling methods and QA procedures
that would ensure accurate results.
For the site-specific emission factor
approach (Option 4), the owner or
operator may conduct a performance
test and determine CO2 emissions from
all exhaust stacks for the process using
EPA reference methods to continuously
measure the CO2 concentration and
stack gas volumetric flow rate during
the test. In addition, either the feed rate
of materials into the process or the
production rate during the test would be
measured. The performance test would
be conducted under normal process
operating conditions and at a
production rate no less than 90 percent
of the process rated capacity. For
continuous processes (taconite
indurating furnaces, non-recovery coke
batteries, and sinter plants), the testing
would cover at least nine hours of
continuous operation. For batch or
cyclic processes (basic oxygen furnaces,
electric arc furnaces, and direct
reduction furnaces), the testing would
cover at least nine complete production
cycles that start when the furnace is
being charged and end after steel or iron
and slag have been tapped. We are
proposing testing for nine hours or nine
production cycles, as applicable,
because nine tests should provide a
reasonable measure of variability (i.e.,
the standard deviation for nine
production cycles or nine 1-hour runs).
If an electric arc furnace is used to
produce both carbon steel and low
carbon steel (including stainless or
specialty steel), separate emission
factors would be developed for carbon
steel and low carbon steel.
The site-specific emission factor for
the process would be calculated in
metric tons CO2 per metric ton of feed
or production, as applicable, by
dividing the CO2 emission rate by the
feed or production rate. The CO2
emissions for the process would be
calculated by multiplying the emission
factor by the total amount of feed or
production, as applicable. A new
performance test would be required
each year to develop a new site-specific
emission factor. Whenever there is a
significant change in fuel type or mix,
change in the process in a manner that
affects energy efficiency by more than
10 percent, or a change in the process
feed materials in a manner that changes
the carbon content of the feed or fuel by
more than 10 percent, a new
performance test would be conducted
PO 00000
Frm 00072
Fmt 4701
Sfmt 4702
and a new site-specific emission factor
calculated.
We are also requesting comment on
the advantages and disadvantages of
Option 4, along with supporting
documentation. We have concluded that
there may be situations in which the
site-specific emission factor approach
may result in an uncertainty lower than
that associated with the carbon balance
approach and provide more reasonable
emission estimates. An example is
nonrecovery coke plants, where a
carbon balance approach may result in
an unacceptably high level of
uncertainty from subtracting two very
large numbers (carbon in with coal and
carbon out with coke) to estimate
emissions that could instead be
accurately and directly measured at the
combustion stack.
The primary sources of variability that
affect CO2 emissions from process
sources in general are the carbon
content of the process inputs and fuel
and any changes to the process that alter
energy efficiency. For most processes,
the carbon content of process inputs and
fuels is consistent and stable, and if a
process change alters energy efficiency,
a re-test could be performed to develop
a new emission factor that reflected the
change. We are requesting comment and
supporting information on the
minimum time or number of production
cycles needed for testing to develop a
representative emission factor, and how
often periodic re-testing should be
required (e.g., annually, quarterly, or
only when there is a process change).
We are also requesting that any
comments on Option 4 address how
changes in process inputs, fuels, or
process energy efficiency should be
accounted for, such as requiring a re-test
if the carbon content of inputs change
by more than some specified percent, if
the type or mix of fuel is changed, or if
there is a significant change in fuel
consumption due to a process change.
We are also proposing that you may
use direct measurements, noting that
CEMS (Option 5) provide the lowest
uncertainty of the three options. This
approach overcomes many of the
limitations associated with other
options considered such as accounting
for the variability in emissions due to
changes in the process, feed materials,
or fuel over time. It would be applied to
stacks that are already equipped with
sampling ports and access platforms;
consequently, it is technically feasible
and cost effective. For those emission
sources already equipped with CEMS,
we are proposing that they be modified
(if necessary) and used to determine
CO2 emissions for that emission source.
We are proposing this requirement
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
because it provides direct emission
measurements that have low uncertainty
with only a minimal additional cost
burden. We also request comment, along
with supporting documentation, on the
advantages and disadvantages of Option
5.
We are also proposing that CH4 and
N2O emissions from the combustion of
fuels in both combustion units and
process units be determined and
reported. All of the fuels used at iron
and steel production processes are
included in the methodologies in
proposed 40 CFR part 98, subpart C for
N2O and CH4. Consequently, EPA is
proposing to use the same methodology
as in proposed 40 CFR part 98, subpart
C for determining and reporting
emissions of N2O and CH4 from both
stationary combustion units and process
units.
Miscellaneous Emissions Sources.
Emissions may also occur when the
incandescent coke is pushed from the
coke oven and transported to the
quench tower where it is cooled
(quenched) with water. A small portion
of the coke burns during this process
prior to quenching. We updated the
coke oven section of the AP–42 79
compilation of emission factors in May
2008, and the update included an
emission factor for CO2 emissions
developed from 26 tests for particulate
matter from pushing operations. The
emissions factor (0.008 metric tons CO2e
per metric ton of coal charged) was
derived to account for emissions from
the pushing emission control device and
those escaping the capture system. We
are proposing that coke facilities use the
AP–42 emission factor to estimate CO2
emissions from coke pushing
operations.
There are dozens of emission points
and various types of fugitive emissions,
not collected for emission through a
stack, from the production processes
and materials handling and transfer
activities at integrated iron and steel
facilities. These emissions from iron and
steel plants have been of environmental
interest primarily because of the
particulate matter in the emissions.
Examples include ladle metallurgy
operations, desulfurization, hot metal
transfer, sinter coolers, and the charging
and tapping of furnaces. The
information we have examined to date
indicates that these emissions
contribute very little to the overall GHG
emissions from the iron and steel sector
(probably on the order of one percent or
less). For example, emissions of blast
79 See Compilation of Air Pollutant Emission
Factors, Fifth Edition: https://www.epa.gov/ttn/
chief/ap42/ch12/final/c12s02_may08.pdf.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
furnace gas may be emitted during
infrequent process upsets (called
‘‘slips’’) when gas is vented for a short
period or from leaks in the ductwork
that handles the gas. However, the mass
of GHG emissions is expected to be
small because most of the carbon in
blast furnace gas is from carbon
monoxide, which is not a GHG. Fugitive
emissions and emissions from control
device stacks may also occur from blast
furnace tapping, the charging and
tapping of basic oxygen furnaces and
electric arc furnaces, ladle metallurgy,
desulfurization, etc. However, we have
no information that indicates CO2 is
generated from these operations, and a
review of test reports from systems that
capture these emissions show that CO2
concentrations are very low (at ambient
air levels). Fugitive emissions
containing CH4 may occur from leaks of
raw coke oven gas from the coke oven
battery during the coking cycle.
However, the mass of these emissions is
expected to be small based on the small
number of leaks that are now allowed
under existing Federal and State
standards that regulate these emissions.
In addition, since these emissions are
not captured in a conveyance, there is
no practical way to measure them.
Consequently, we are not proposing that
fugitive emissions be reported because
we believe their GHG content is
negligible and because there is no
practical way of measuring them.
However, we welcome public comment,
along with supporting data and
documentation, on whether fugitive
emissions should be included, and if so,
how these emissions can be estimated.
4. Selection of Procedures for Estimating
Missing Data
For process sources that use Option 3
(carbon balance) or Option 4 (sitespecific emission factor), no missing
data procedures would apply because
100 percent data availability would be
required. For process sources that use
Option 5 (direct measurement by
CEMS), the missing data procedures
would be the same as for units using
Tier 4 in the general stationary fuel
combustion source category in proposed
40 CFR part 98, subpart C.
5. Selection of Data Reporting
Requirements
We are proposing that facilities
submit annual emission estimates for
CO2 presented by calendar quarters for
coke oven battery combustion stacks,
coke pushing, blast furnace stoves,
taconite indurating furnaces, electric arc
furnaces, argon-oxygen decarburization
vessel, direct reduced iron furnaces, and
sinter plants.
PO 00000
Frm 00073
Fmt 4701
Sfmt 4702
16519
In addition we propose that facilities
submit the following data to assist in
checks for reasonableness and for other
data quality considerations: Total mass
for all process inputs and outputs when
the carbon balance is used for specific
processes by calendar quarters, sitespecific emission factor for all processes
for which the site-specific emission
factor approach is used, annual
production quantity for taconite pellets,
coke, sinter, iron, raw steel by calendar
quarters, annual production capacity for
taconite pellets, coke, sinter, iron, raw
steel, annual operating hours for
taconite furnaces, coke oven batteries,
sinter production, blast furnaces, direct
reduced iron furnaces, and electric arc
furnaces, and the quantity of CO2
captured for use and the end use, if
known.
A full list of data that would be
reported is included in proposed 40
CFR part 98, subparts A and Q.
6. Selection of Records That Must Be
Retained
In addition to the recordkeeping
requirements for general stationary fuel
combustion sources, we propose that
the following additional records be kept
to assist in QA/QC and verification
purposes: GHG emission estimates from
the iron and steel production process by
calendar quarter, monthly total for all
process inputs and outputs when the
carbon balance is used for specific
processes, documentation of calculation
of site-specific emission factor for all
processes for which the site-specific
emission factor approach is used,
monthly analyses of carbon content, and
monthly production quantity for
taconite pellets, coke, sinter, iron, and
raw steel.
R. Lead Production
1. Definition of the Source Category
Lead is a metal used to produce
various products such as batteries,
ammunition, construction materials,
electrical components and accessories,
and vehicle parts. For this proposed
rule, we are defining the lead
production source category to consist of
primary lead smelters and secondary
lead smelters. A primary lead smelter
produces lead metal from lead sulfide
ore concentrates through the use of
pyrometallurgical processes. A
secondary lead smelter produces lead
and lead alloys from lead-bearing scrap
metal.
For the primary lead smelting process
used in the U.S., lead sulfide ore
concentrate is first fed to a sintering
process to burn sulfur from the lead ore.
The sinter is smelted with a
E:\FR\FM\10APP2.SGM
10APP2
16520
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
carbonaceous reducing agent in a blast
furnace to produce molten lead bullion.
From the furnace, the bullion is
transferred to dross kettle furnaces to
remove primarily copper and other
metal impurities. Following further
refining steps, the lead is cast into
ingots or alloy products.
The predominate feed materials
processed at U.S. secondary lead
smelters are used automobile batteries,
but these smelters can also process other
lead-bearing scrap materials including
wheel balance weights, pipe, solder,
drosses, and lead sheathing. These
incoming lead scrap materials are first
pre-treated to partially remove metal
and nonmetal contaminants. The
resulting lead scrap is smelted (U.S.
secondary lead smelters typically use
either a blast furnace or reverberatory
furnace). The molten lead from the
smelting furnace is refined in kettle
furnaces, and then cast into ingots or
alloy products.
Lead production results in both
combustion and process-related GHG
emissions. Combustion-related CO2,
CH4, and N2O emissions are generated
from metallurgical process equipment
used at primary and secondary lead
smelters when natural gas or another
fuel is burned in the unit to produce
heat for drying, roasting, sintering,
calcining, melting, or casting operations.
Process-related CO2 emissions are
released from the lead smelting process
due to the addition of a carbonaceous
reducing agent such as metallurgical
coke or coal to the smelting furnace. The
reduction of lead oxide to lead metal
during the process produces the CO2
emissions.
Currently there is one primary lead
smelter operating in the U.S. There are
26 secondary lead smelters in the U.S.
with widely varying annual lead
production capacities ranging from
approximately 1,000 metric tons to more
than 100,000 metric tons. Total national
GHG emissions from lead production in
the U.S. were estimated to be
approximately 0.9 million metric tons
CO2e in 2006. These emissions include
both on-site stationary combustion
emissions (CO2, CH4, and N2O) and
process-related emissions (CO2). The
majority of these emissions were from
the combustion of carbon-based fuels.
Combustion GHG emissions were 0.6
million metric tons CO2e emissions (69
percent of the total emissions). The
remaining 0.3 million metric tons CO2e
(31 percent of the total emissions) were
process-related GHG emissions.
Additional background information
about GHG emissions from the lead
production source category is available
in the Lead Production TSD (EPA–HQ–
OAR–2008–0508–018).
2. Selection of Reporting Threshold
In developing the threshold for lead
production facilities, we considered
using annual GHG emissions-based
threshold levels of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000
metric tons CO2e and 100,000 metric
tons CO2e. This threshold is based on
combined combustion and process CO2
emissions at the lead production
facility. Table R–1 of this preamble
presents the estimated emissions and
number of facilities that would be
subject to GHG emissions reporting,
based on existing facility lead
production capacities, under these
various threshold levels.
TABLE R–1. THRESHOLD ANALYSIS FOR LEAD SMELTERS
Threshold level metric tons CO2e/yr
Total
nationwide
emissions
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
866,000
866,000
866,000
866,000
Secondary lead smelters in the U.S.
vary greatly in production capacity and
include 10 small facilities with
production capacities less than 4,000
tons per year. Table R–1 of this
preamble shows approximately 92
percent of the GHG emissions that result
from lead production are released from
the one primary smelter and 12
secondary smelters that emit more than
25,000 metric tons CO2e annually. Of
the facilities with annual GHG
emissions below 25,000 metric tons
CO2e, 10 secondary smelters are
estimated to emit less than 1,000 metric
tons CO2e annually.
To avoid placing a reporting burden
on the smaller secondary lead smelters
which may operate as small businesses
while still requiring the reporting of
GHG emissions from those facilities
releasing most of the GHG emissions in
this source category, we are proposing a
threshold of 25,000 metric tons CO2e
per year for reporting of emissions. This
threshold level is consistent with the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Nationwide
number of
facilities
Emissions covered
metric tons
CO2e/yr
27
27
27
27
3. Selection of Proposed Monitoring
Methods
We reviewed existing domestic and
international GHG monitoring
guidelines and protocols including the
2006 IPCC Guidelines for National
Greenhouse Gas Inventories, U.S. GHG
Inventory, the EU Emissions Trading
System, the Canadian Mandatory
Greenhouse Gas Reporting Program, and
the Australian National Greenhouse Gas
Reporting Program. These methods
coalesce around the following four
options for estimating process-related
CO2 emissions from lead production
PO 00000
Frm 00074
Fmt 4701
Sfmt 4702
Facility
number
Percent
859,000
853,000
798,000
0
threshold level being proposed for other
source categories with similar facility
size characteristics. More discussion of
the threshold selection analysis is
available in the Lead Production TSD
(EPA–HQ–OAR–2008–0508–018). For
specific information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
Facilities covered
99
98
92
0
Percent
17
16
13
0
63
59
48
0
facilities. A full summary of methods
reviewed is available in the Lead
Production TSD (EPA–HQ–OAR–2008–
0508–018).
Option 1. Apply a default emission
factor for the process-related emissions
to the facility’s lead production rate.
This is a simplified emission calculation
method using only default emission
factors to estimate process-related CO2
emissions. The method requires
multiplying the amount of lead
produced by the appropriate default
emission factors from the 2006 IPCC
Guidelines. This method is consistent
with the IPCC Tier 1 method.
Option 2. Perform monthly
measurements of the carbon content of
specific process inputs and measure the
mass rate of these inputs. This is the
IPCC Tier 3 approach and the higher
order methods in the Canadian and
Australian reporting programs.
Implementation of this method requires
owners and operators of affected lead
smelters to determine the carbon
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
contents of materials added to the
smelting furnace by analysis of
representative samples collected of the
material or from information provided
by the material suppliers. In addition,
you must measure and record the
quantities of these input materials
consumed during production. To obtain
the process-related CO2 emission
estimate, the material carbon content
would be multiplied by the
corresponding mass of the carboncontaining input material consumed
and a conversion factor of carbon to
CO2. This method assumes that all of
the carbon is converted to CO2 during
the reduction process. The facility
owner or operator would determine the
average carbon content of the material
for each calendar month using
information provided by the material
supplier or by collecting a composite
sample of material and sending it to an
independent laboratory for chemical
analysis.
Option 3. Use CO2 emissions data
from a stack test performed using EPA
reference test methods to develop a sitespecific process emissions factor which
is then applied to quantity measurement
data of feed material or product for the
specified reporting period. This
monitoring method is applicable to
furnace configurations for which the
GHG emissions are contained within a
stack or vent. Using site-specific
emissions factors based on short-term
stack testing is appropriate for those
facilities where process inputs (e.g., feed
materials, carbonaceous reducing
agents) and process operating
parameters remain relatively consistent
over time.
Option 4. Use direct emission
measurement of CO2 emissions. For
furnace configurations in which the
process off-gases are contained within a
stack or vent, direct measurement of the
CO2 emissions can be made by
continuously measuring the off-gas
stream CO2 concentration and flow rate
using a CEMS. For a smelting furnace
used for lead production where both
combustion and process-related
emissions are released by a source (e.g.
blast furnace) emissions reported by
using a CEMS would be total CO2
emissions including both combustion
and process-related CO2 emissions.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS to meet the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
emissions you would be required to
follow requirements of proposed 40 CFR
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
part 98, subpart C to estimate CO2
emissions. Also, refer to proposed 40
CFR part 98, subpart C to estimate
combustion-related CH4 and N2O.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where CEMS would not
adequately account for combustion and
process related CO2 emissions, the
proposed monitoring method for
process-related CO2 from lead
production is Option 2. You would be
required to follow the calculation
procedures, monitoring and QA/QC
methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary combustion. This section of
the preamble provides procedures only
for calculating and reporting processrelated emissions.
We propose Option 2, due to the
operating variations between the
individual U.S. lead production
facilities, including differences in
equipment configurations, mix of lead
feedstocks charged, and types of carbon
materials used. Further, Option 2 would
result in lower uncertainty as compared
to applying a default emissions factor
based approach to these units.
Although we are not proposing to
require you to directly measure process
emissions, unless you meet the
requirements of proposed 40 CFR part
98, subpart C and the CEMS account for
both combustion and process-relate
emissions, you could opt to use direct
measurement of CO2 emissions as an
alternative GHG emissions estimation
method because it would best reflect
actual operating practices at your
facility, and therefore, reduce
uncertainty. While we recognize that the
costs for conducting direct
measurements may be higher than other
methods, we are proposing to include
this alternative because it provides GHG
emissions data that have low
uncertainty. The additional cost burden
may be acceptable to owners and
operators with site-specific reasons for
choosing this alternative.
We decided not to propose the use of
the default CO2 emission factors (Option
1) because their application is more
appropriate for GHG estimates from
aggregated process information on a
sector-wide or nationwide basis than for
determining GHG emissions from
specific facilities. We considered the
additional burden of the material
measurements required for the carbon
calculations under Option 2 small in
relation to the increased accuracy
expected from using this site-specific
PO 00000
Frm 00075
Fmt 4701
Sfmt 4702
16521
information to calculate the processrelated CO2 emissions.
We also decided not to propose
Option 3 because of the potential for
significant variations at lead smelters in
the characteristics and quantities of the
furnace inputs (e.g., lead scrap
materials, carbonaceous reducing
agents) and process operating
parameters. A method using periodic,
short-term stack testing would not be
practical or appropriate for those lead
smelters where the furnace inputs and
operating parameters do not remain
relatively consistent over the reporting
period.
Further details about the selection of
the monitoring methods for GHG
emissions is available in the Lead
Production TSD (EPA–HQ–OAR–2008–
0508–018).
4. Selection of Procedures for Estimating
Missing Data
For smelting furnaces for which the
owner or operator calculates process
GHG emissions using site-specific
carbonaceous input material data, the
proposed rule requires the use of
substitute data whenever a qualityassured value of a parameter that is used
to calculate GHG emissions is
unavailable, or ‘‘missing.’’ If the carbon
content analysis of carbon inputs is
missing or lost the substitute data value
would be the average of the qualityassured values of the parameter
immediately before and immediately
after the missing data period. In those
cases when an owner or operator uses
direct measurement by a CO2 CEMS, the
missing data procedures would be the
same as the Tier 4 requirements
described for general stationary fuel
combustion sources in proposed 40 CFR
part 98, subpart C. The likelihood for
missing data is low, as businesses
closely track their purchase of
production inputs.
5. Selection of Data Reporting
Requirements
The proposed rule would require
annual reporting of the total annual CO2
process-related emissions from each
smelting furnace at lead production
facilities, as well as any stationary fuel
combustion emissions. In addition, we
are proposing that additional
information that forms the basis of the
emissions estimates also be reported so
that we can understand and verify the
reported emissions. This addition
information includes the total number
of smelting furnaces operated at the
facility, the facility lead product
production capacity, the annual facility
production quantity, annual quantity
and type of carbon-containing input
E:\FR\FM\10APP2.SGM
10APP2
16522
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
materials consumed or used, annual
weighted average carbon contents by
material type, and the number of facility
operating hours in the calendar year. A
complete list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and R.
6. Selection of Records That Must Be
Retained
Maintaining records of the
information used to determine the
reported GHG emissions is necessary to
enable us to verify that the GHG
emissions monitoring and calculations
were done correctly. In addition to the
information reported as described in
Section V.R.5 of this preamble, we
propose that all facilities estimating
emissions according to the carbon input
method maintain records of each
carbon-containing input material
consumed or used (other than fuel) the
monthly material quantity, monthly
average carbon content determined for
material, and records of the supplier
provided information or analyses used
for the determination. If you use the
CEMS procedure, you would maintain
the CEMS measurement records
according to the procedures in proposed
40 CFR part 98, subpart C. These
records would be required to be
maintained onsite for 5 years. A
complete list of records to be retained is
included in the proposed rule.
S. Lime Manufacturing
1. Definition of the Source Category
Lime is an important manufactured
product with many industrial, chemical,
and environmental applications. Its
major uses are in steel making, flue gas
desulfurization systems at coal-fired
electric power plants, construction, and
water purification. Lime is used for the
following purposes: Metallurgical uses
(36 percent), environmental uses (29
percent), chemical and industrial uses
(21 percent), construction uses (13
percent), and to make dolomite
refractories (1 percent).
For U.S. operations, the term ‘‘lime’’
actually refers to a variety of chemical
compounds. These compounds include
calcium oxide (CaO), or high-calcium
quicklime; calcium hydroxide
(Ca(OH)2), or hydrated lime; dolomitic
quicklime ((CaO∑MgO)); and dolomitic
hydrate ((Ca(OH)2∑MgO) or
(Ca(OH)2∑Mg(OH)2)). Lime
manufacturing involves three main
processes: Stone preparation,
calcination, and hydration. During the
calcination process, the carbonate in
limestone is sufficiently heated and
reduced to CO2 gas. In certain
applications, lime reabsorbs CO2 during
use thereby reducing onsite GHG
emissions.
National emissions from the lime
industry were estimated to be 25.4
million metric tons CO2e in 2004 (or
<0.4 percent of national emissions).
These emissions include both processrelated emissions and on-site stationary
combustion emissions from 89 lime
manufacturing facilities across the U.S.
and Puerto Rico. Process-related
emissions account for 14.3 million
metric tons CO2e, or 56 percent of the
total, while on-site stationary
combustion emissions account for the
remaining 11.1 million metric tons
CO2e.
For additional background
information on lime manufacturing,
please refer to the Lime Manufacturing
TSD (EPA–HQ–OAR–2008–0508–019).
2. Selection of Reporting Threshold
In developing the proposed reporting
threshold for the lime manufacturing
source category, we considered
emissions-based thresholds of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. This
threshold is based on combined
combustion and process CO2 emissions
at a lime production facility. Table S–
1 of this preamble illustrates the
emissions and facilities that would be
covered under various thresholds.
TABLE S–1. THRESHOLD ANALYSIS FOR LIME MANUFACTURING
Threshold level metric tons CO2e/yr
Total national
emissions
metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
25,421,043
25,421,043
25,421,043
25,421,043
The lime manufacturing sector
consists primarily of large facilities and
a few smaller facilities. All facilities,
except four, exceed the 25,000 metric
tons CO2e threshold.
Consistent with National Lime
Association recommendations, and in
order to simplify the proposed rule and
avoid the need to calculate and report
whether the threshold value has been
exceeded, we are proposing that all lime
manufacturing facilities report GHG
emissions. This captures 100 percent of
emissions without significantly
increasing the number of facilities that
would have reported at 1,000, 10,000, or
25,000 metric ton thresholds. For a full
discussion of the threshold analysis,
please refer to the Lime Manufacturing
TSD (EPA–HQ–OAR–2008–0508–019).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
metric tons
CO2e/yr
89
89
89
89
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from lime manufacturing (e.g., the 2006
IPCC Guidelines, U.S. Inventory, DOE
1605(b), National Lime Association CO2
Protocol, and the EU Emissions Trading
System). These methodologies can be
summarized by the following two
overall approaches to estimating
emissions, based on measuring either
the carbonate inputs to the kiln or
PO 00000
Frm 00076
Fmt 4701
Sfmt 4702
Percent
25,421,043
25,396,036
25,371,254
23,833,273
For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
Facilities covered
100
99.9
99.8
94
Number
Percent
89
86
85
52
100
97
96
58
production outputs of the lime
manufacturing process.
Input-based Options. We considered
the IPCC Tier 3 method which requires
facilities to estimate process emissions
by measuring the quantity of carbonate
inputs to the kiln(s) and applying the
appropriate emission factors and
calcination fractions to the carbonates
consumed. In order to assess the
composition of carbonate inputs,
facilities would send samples of their
inputs and lime kiln dust produced to
an off-site laboratory for analysis on a
monthly basis using ASTM C25–06,
‘‘Standard Test Methods for Chemical
Analysis of Limestone, Quicklime, and
Hydrated Lime’’ (incorporated by
reference, see proposed 40 CFR 98.7).
For greater accuracy, facilities would
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
also estimate the calcination fraction of
each carbonate consumed on a monthly
basis. However, it is generally accepted
that the calcination fraction of
carbonates during lime production is
100 percent or very close to it.
Output-based Options. We also
considered three output-based methods
for quantifying process-related
emissions based on the quantity of lime
produced. IPCC’s Tier 1 method applies
default emission factors to each of the
three types of lime produced (high
calcium lime, dolomitic lime, or
hydraulic lime). The IPCC Tier 2
method applies a default emissions
factor based on lime type to the
corresponding quantity of all lime
produced (by type), correcting for the
amount of calcined byproduct/waste
product (such as lime kiln dust)
produced in the process.
The third output method, developed
by the National Lime Association,
improves upon the IPCC Tier 2
procedure. In this method, facilities
multiply the amount of lime produced
at each kiln and the amount of calcined
byproducts/wastes at the kiln by an
emission factor. The emission factor is
derived based on facility specific
chemical analysis of the CaO and
magnesium oxide (MgO) content of the
lime produced at the kiln. To assess the
composition of the lime and calcined
byproduct/waste product, facilities
would send samples to an off-site
laboratory for analysis on a monthly
basis following the procedures
described in the National Lime
Association’s method protocol, along
with the procedures in ASTM C25–06,
‘‘Standard Test Methods for Chemical
Analysis of Limestone, Quicklime, and
Hydrated Lime’’ (incorporated by
reference, see proposed 40 CFR 98.7).
This third output approach is also
consistent with 1605(b)’s ‘‘A’’ rated
approach and EU Emission Trading
System’s calculation B method.
We compared the various methods for
estimating process-related CO2
emissions. In general, the IPCC output
methods are less certain, as they involve
multiplying production data by
emission and correction factors for lime
kiln dust that are likely default values
based on purity assumptions (i.e. the
total CaO and MgO content of the lime
products). In contrast, the input method
is more certain as it involves measuring
the consumption of each carbonate
input and calculating purity fractions.
According to the 2006 IPCC Guidelines,
the uncertainty involved in the
carbonate input approach for the IPCC
Tier 3 method is 1 to 3 percent and the
uncertainty involved in using the
default emission factor and lime kiln
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
dust correction factor for the Tier 1 and
Tier 2 production-based approaches is
15 percent. However, IPCC states that
the major source of uncertainty in the
above approaches is the CaO content of
the lime produced.
Proposed Option. Under this
proposed rule, if you are using an
existing CEMS that meets the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
emissions you would be required to
follow the requirements of proposed 40
CFR part 98, subpart C to estimate both
combustion and process CO2 emissions.
Also, you would refer to proposed 40
CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions.
Under this proposed rule, if you do
not have CEMS that meet the conditions
outlined in proposed 40 CFR part 98,
subpart C, you would use the National
Lime Association method in this section
of the preamble to calculate processrelated CO2 emissions. Refer to
proposed 40 CFR part 98, subpart C
specifically for procedures to estimate
combustion-related CO2, CH4 and N2O
emissions.
We are proposing the National Lime
Association’s output-based procedure
because this method is already in use by
U.S. facilities and the improvement in
accuracy compared to default
approaches can be achieved at minimal
additional cost. The measurement of
production quantities is common
practice in the industry and is usually
measured through the use of scales or
weigh belts so additional costs to the
industry are not anticipated. The
primary additional burden for facilities
would include conducting a CaO and
MgO analysis of each lime product on
a monthly basis (to be averaged on an
annual basis). However, approximately
two thirds of the lime manufacturing
facilities in the U.S. are already
undertaking sampling efforts to meet
reporting goals set forth by the National
Lime Association.
We request comment on the
advantages and disadvantages of the
IPCC Tier 3 method and supporting
documentation. After consideration of
public comments, we may promulgate
the IPCC Tier 3 input-based procedure,
the National Lime Association outputbased procedure, or a combination
based on additional information that is
provided.
The various approaches to monitoring
GHG emissions are elaborated in the
Lime Manufacturing TSD (EPA–HQ–
OAR–2008–0508–019).
PO 00000
Frm 00077
Fmt 4701
Sfmt 4702
16523
4. Selection of Procedures for Estimating
Missing Data
It is assumed that a facility would be
able to supply facility-specific
production data. Since the likelihood
for missing data is low because
businesses closely track production, 100
percent data availability is required for
lime production (by type) in the
proposed rule. If analysis for the CaO
and MgO content of the lime product
are unavailable or ‘‘missing’’, facility
owners or operators would substitute a
data value that is the average of the
quality-assured values of the parameter
immediately before and immediately
after the missing data period.
5. Selection of Data Reporting
Requirements
We propose that in addition to
stationary fuel combustion GHG
emissions, you report annual CO2
emissions for each kiln. In addition, for
each kiln we are proposing that facilities
report the following data used as the
basis of the calculations to assist in
verification of estimates, checks for
reasonableness, and other data quality
considerations for process emissions:
Annual lime production and production
capacity, emission factor by lime type,
and number of operating hours in the
calendar year. A full list of data to be
reported is included in proposed 40
CFR part 98, subparts A and S.
6. Selection of Records That Must be
Retained
Maintaining records of the
information used to determine the
reported GHG emissions are necessary
to enable us to verify that the GHG
emissions monitoring and calculations
were done correctly. In addition to the
data to be reported, we are proposing
that the facilities maintain records of the
calculation of emission factors, results
of the monthly chemical composition
analyses, total lime production for each
kiln by month and type, total annual
calcined byproducts/wastes produced
by each kiln averaged from monthly
data, and correction factor for
byproducts/waste products for each
kiln. A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and S.
T. Magnesium Production
1. Definition of the Source Category
Magnesium is a high-strength and
light-weight metal that is important for
the manufacture of a wide range of
products and materials, such as portable
electronics, automobiles, and other
machinery. The U.S. accounts for less
than 10 percent of world primary
E:\FR\FM\10APP2.SGM
10APP2
16524
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
magnesium production but is a
significant importer of magnesium and
producer of cast parts. The production
and processing of magnesium metal
under common practice results in
emissions of SF6. For further
information, see the Magnesium
Production TSD (EPA–HQ–OAR–2008–
0508–020).
The magnesium metal production
(primary and secondary) and casting
industry typically uses SF6 as a cover
gas to prevent the rapid oxidation and
burning of molten magnesium in the
presence of air. A dilute gaseous
mixture of SF6 with dry air and/or CO2
is blown over molten magnesium metal
to induce and stabilize the formation of
a protective crust. A small portion of the
SF6 reacts with the magnesium to form
a thin molecular film of mostly
magnesium oxide and magnesium
fluoride. The amount of SF6 reacting in
magnesium production and processing
is under study but is presently assumed
to be negligible. Thus, all SF6 used is
presently assumed to be emitted into the
atmosphere.
Cover gas systems are typically used
to protect the surface of a crucible of
molten magnesium that is the source for
a casting operation and to protect the
casting operation itself (e.g., ingot
casting). SF6 has been used in this
application in most parts of the world
for the last twenty years. Due to
increasing awareness of the GWP of SF6,
the magnesium industry has begun
exploring climate-friendly alternative
melt protection technologies. At this
time the leading alternatives include
HFC–134a, a fluorinated ketone (FK 5–
1–12, C3F7C(O)C2F5), and dilute sulfur
dioxide (SO2). The application of the
fluorinated alternatives mentioned here
may generate byproduct emissions of
concern including PFCs. We are
proposing that magnesium production
and processing facilities report process
emissions of SF6, HFC–134a, FK 5–1–
12, and CO2.
Total U.S. emissions of SF6 from
magnesium production and processing
in the U.S. were estimated to be 3.2
metric tons CO2e in 2006. Primary and
secondary production activities at 3
facilities accounted for about 64 percent
of total emissions, or 2 metric tons
CO2e. Approximately 20 magnesium die
casting facilities in the U.S. accounted
for more than 30 percent, or more than
0.9 metric tons CO2e of total
magnesium-related SF6 emissions. Other
smaller casting activities such as sand
and permanent mold casting accounted
for the remaining magnesium-related
emissions of SF6. The term ‘‘metal
processed’’ used here is defined as the
mass of magnesium melted to cast or
create parts. This should not be
confused with the mass of finished
magnesium parts because varying
amounts of the metal may be lost as
scrap when performing casting
operations.
2. Selection of Reporting Threshold
We considered emissions thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e as well as
capacity based thresholds as shown in
Tables T–1 and T–2 of this preamble.
TABLE T–1. THRESHOLD ANALYSIS FOR MG PRODUCTION BASED ON EMISSIONS
Threshold level metric tons CO2e/yr
Total
nationwide
emissions
metric tons
CO2e/Yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
Emissions covered
Nationwide
number of
facilities
3,200,000
3,200,000
3,200,000
3,200,000
Metric tons
CO2e/yr
13
13
13
13
Facilities covered
Percent
2,954,559
2,939,741
2,939,741
2,872,982
Facilities
92
92
92
90
Percent
13
11
11
9
100
85
85
69
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
production levels.
TABLE T–2. THRESHOLD ANALYSIS FOR MG PRODUCTION BASED ON MG PRODUCTION CAPACITY
Capacity threshold level Mg/yr
Total
nationwide
emissions
metric tons
CO2e/Yr
26 .............................................................
262 ...........................................................
656 ...........................................................
2,622 ........................................................
Emissions covered
Number of
facilities
3,200,000
3,200,000
3,200,000
3,200,000
Metric tons
CO2e/yr
13
13
13
13
Facilities Covered
Percent
2,954,559
2,949,732
2,949,732
2,780,717
Facilities
92
92
92
87
Percent
13
12
12
9
100
92
92
69
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
production levels.
Under the proposed rule, magnesium
metal production and parts casting
facilities would have to report their total
GHG emissions if those emissions
exceeded 25,000 metric tons CO2e. This
threshold covers all currently identified
operating U.S. primary and secondary
magnesium producers and most die
casters, accounting for over 99 percent
of emissions from these source
categories.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
The proposed emissions threshold of
25,000 metric tons CO2e is equal to
emissions of 1,046 kg of SF6; 19,231 kg
of HFC–134a; or 25,000,000 kg of CO2 or
FK 5–1–2. Other emission threshold
options that we considered were 1,000
metric tons CO2e, 10,000 metric tons
CO2e, and 100,000 metric tons CO2e.
The 10,000 metric tons CO2e emission
threshold yielded results identical to
those of the proposed option.
PO 00000
Frm 00078
Fmt 4701
Sfmt 4702
We also considered capacity-based
thresholds of 26, 262, 656, and 2,622
metric tons, based on 100 percent
capacity utilization and an SF6 emission
rate of 1.6 kg SF6 per metric ton of
magnesium produced or processed. This
emission factor represents the sum of (1)
the average of the emission factors
reported for secondary production and
die casting through our magnesium
Partnership (excluding outliers), and (2)
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the standard deviation of those emission
factors. The 1.6 kg-per-ton factor is
higher than most, though not all, of the
emission factors reported, which ranged
from 0.7 to 7 kg/ton Mg in 2006. The
resulting capacity thresholds yielded
results very similar to those of the
emission-based thresholds.
The emissions based threshold was
selected over the capacity based
threshold for several reasons. The
emissions based threshold is simple to
evaluate because magnesium production
and processing facilities can use readily
available data regarding consumption of
SF6 and would also possess similar data
for alternatives such as HFC–134a as
these are phased-in over time. To
determine whether they exceeded the
thresholds, magnesium facilities would
multiply the total consumption of each
of these gases by a GWP-unit conversion
factor that could be compared to the
25,000 metric ton threshold. The
equation for this calculation is provided
in the proposed regulatory text.
The emissions-based threshold of
25,000 metric tons CO2e also takes into
account the variability in cover gas
identities, usage rates, and process
conditions. Alternatives to SF6 have
considerably lower GWPs than SF6. In
facilities where SF6 is used, the usage
rate can vary by an order of magnitude
depending on the casting process and
operating conditions. Therefore, cover
gas emissions are not well predicted by
production capacity. Because emissions
of each cover gas are assumed to equal
use, and facilities are expected to track
gas use in the ordinary course of
business, facilities should have little
difficulty determining whether or not
they must report under this rule. For a
full discussion of the threshold analysis,
please refer to the Magnesium
Production TSD (EPA–HQ–OAR–2008–
0508–020). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
We reviewed a wide range of
protocols and guidance in developing
this proposal, including the 2006 IPCC
Guidelines, EPA’s SF6 Emission
Reduction Partnership for the
Magnesium Industry, the U.S. GHG
Inventory, DOE 1605(b), EPA’s Climate
Leaders Program, and TCR.
The methods described in these
protocols and guidance were similar to
the methods described by the IPCC
Guidelines and the U.S. GHG Inventory
methodology. These methods range
from a Tier 1 approach, based on default
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
consumption factors per unit Mg
produced or processed, to a Tier 3
approach based on facility-specific
measured emissions data.
Under this proposed rule, if you are
required to use an existing CEMS to
meet the requirements outlined in
proposed 40 CFR part 98, subpart C, you
would be required to use CEMS to
estimate CO2 emissions. Where the
CEMS capture all combustion- and
process-related CO2 emissions you
would be required to follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
CO2 emissions. Also, refer to proposed
40 CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS would
not adequately account for process
emissions, you would be required to
follow the proposed monitoring method
discussed below. The proposed method
outlined below accounts for processrelated SF6, HFC–134a, FK 5–1–12, and
CO2 emissions. Refer to proposed 40
CFR part 98, subpart C specifically for
procedures to estimate combustionrelated CO2, CH4 and N2O emissions.
The proposed method for monitoring
SF6, HFC–134a, FK 5–1–12, and CO2
cover gas emissions from magnesium
production and processing is similar to
the Tier 2 approach in the 2006 IPCC
Guidelines for magnesium production.
This approach is based on facilityspecific information on cover gas
consumption and assumes that all gases
consumed are emitted. This
methodology applies to any cover gas
that is a GHG, including SF6, CO2, HFC–
134a and FK 5–1–12.
We propose three options for
measuring gas consumption:
1. Weighing gas cylinders as they are
brought into and out of service allowing
a facility to accurately track the actual
mass of gas used.
2. Using a mass flow meter to
continuously measure the mass of global
warming gases used.
3. Performing a facility level mass
balance for all global warming gases
used at least once annually. Using this
approach, a facility would review its gas
purchase records and inventory to
determine actual mass of gas used and
subtract a 10 percent default heel factor
to account for residual gas in cylinders
returned to the gas suppliers.
When weighing cylinders to
determine cover gas consumption,
PO 00000
Frm 00079
Fmt 4701
Sfmt 4702
16525
facilities would weigh all gas cylinders
that are returned to the gas supplier, or
have the gas supplier weigh the
cylinders, to determine the residual gas
still in the cylinder. The weight of
residual gas would be subtracted from
the weight of gas delivered to determine
gas consumption. Gas suppliers can
provide detailed monthly spreadsheets
with exact residual gas amounts
returned.
Facilities would be required to follow
several procedures to ensure the quality
of the consumption data. These
procedures could be readily adopted, or
would be based on information that is
already collected for other reasons.
Facilities would be required to track
specific cylinders leaving and entering
storage with check-out and weigh-in
sheets and procedures. Scales used for
weighing cylinders and mass flow
meters would need to be accurate to
within 1 percent of true mass, and
would be periodically calibrated.
Facilities would calculate the facility
usage rate, compare it to known default
emission rates and historical data for the
facility, and investigate any anomalies
in the facility usage rate. Finally,
facilities would need to have procedures
to ensure that all production lines have
provided information to the manager
compiling the emissions report, if this is
not already handled through an
electronic inventory system.
We are not proposing IPCC’s Tier 1 or
3 methodologies for calculating
emissions. Although the Tier 1
methodology is straightforward, the
default consumption factor for the SF6
usage rate is significantly uncertain due
to the variability in production
processes and operating conditions. The
Tier 3 methodology of conducting
facility-specific measurements of
emissions to account for potential cover
gas destruction and byproduct
formation is the most accurate, but also
poses significant economic challenges
for implementation because of the cost
of direct emission measurements.
4. Selection of Procedures for Estimating
Missing Data
In general, it is unlikely that cover gas
consumption data would be missing.
Facilities are expected to know the
quantities of cover gas that they
consume because facility operations rely
on accurate monitoring and tracking of
costs. Facilities would possess invoices
from gas suppliers during a given year
and many facilities currently track the
weight of SF6 consumed by weighing
individual cylinders prior to
replacement.
However, where cover gas
consumption information is missing, we
E:\FR\FM\10APP2.SGM
10APP2
16526
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
propose that facilities estimate
emissions by multiplying production by
the average cover gas usage rate (kg gas
per ton of magnesium produced or
processed) from the most recent period
when operating conditions were similar
to those for the period for which the
data are missing, i.e., using the same
cover gas concentrations and flow rates
and, if applicable, casting parts of a
similar size.
5. Selection of Data Reporting
Requirements
Facilities would be required to report
total facility GHG emissions and
emissions by process type: Primary
production, secondary production, die
casting, or other type of casting. For
total facility and process emissions,
emissions would be reported in metric
tons of SF6, HFC–134a, FK 5–1–12, and
CO2 (used as a carrier gas).
Along with their total emissions from
cover gas use, facilities would be
required to submit supplemental data
(as well as the supplemental data
required in the combustion and
calcination sections) including the type
of production processes (e.g., primary,
secondary, die casting), mass of
magnesium produced or processed in
metric tons for each process type, cover
gas flow rate and composition, and mass
of any CO2 used as a carrier gas during
reporting period.
If data were missing, facilities would
be required to report the length of time
the data were missing, the method used
to estimate emissions in their absence,
and the quantity of emissions thereby
estimated. Facilities would also submit
an explanation for any significant
change in emission rate. Examples
could include installation of new melt
protection technology that would
account for reduced emissions in any
given year, or occurrence or repair of
leaks in the cover gas delivery system.
These non-emissions data need to be
reported because they are needed to
understand the nature of the facilities
for which data are being reported and
for verifying the reasonableness of the
reported data.
6. Selection of Records That Must Be
Retained
We are proposing that magnesium
producers and processors be required to
keep records documenting adherence to
the QA/QC requirements specified in
the proposed rule. These records would
include: Check-out and weigh-in sheets
and procedures for cylinders; accuracy
certifications and calibration records for
scales; residual gas amounts in
cylinders sent back to suppliers; and
invoices for gas purchases and sales.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
These records are being specified
because they are the values that are used
to calculate the GHG emissions that are
reported. They are necessary to verify
that the GHG emissions monitoring and
calculations were done correctly and
accurately.
U. Miscellaneous Uses of Carbonates
1. Definition of the Source Category
Limestone (CaCO3), dolomite
(CaMg(CO3)2) and other carbonates are
inputs used in a number of industries.
The most common applications of
limestone are used as a construction
aggregate (78 percent of specified
national consumption in 2006), the
chemical and metallurgy industries (18
percent), and other specialized
applications (three percent). The
breakdown of reported specified
dolomite national consumption was
similar to that of limestone, with the
majority being used as a construction
aggregate, and a lesser but still
significant percent used in chemical and
metallurgical applications.
For some of these applications, the
carbonates undergo a calcination
process in which the carbonate is
sufficiently heated, generating CO2 as a
by-product. Examples of such emissive
applications include limestone used as
a flux or purifier in metallurgical
furnaces, as a sorbent in flue gas
desulfurization systems for utility and
industrial plants, and as a raw material
in the production of mineral wool or
magnesium. Non-emissive applications
include limestone used in producing
poultry grit and asphalt filler.
The use of limestone, dolomite and
other carbonates is purely an industrial
process source of emissions. Emissions
from the use of carbonates in the
manufacture of cement, ferroalloys,
glass, iron and steel, lead, lime, pulp
and paper, and zinc are elaborated in
proposed 40 CFR part 98, subparts H, K,
N, Q, R, S, AA and GG, since they are
relatively significant emitters. Facilities
that include only these source categories
would not need to follow the methods
presented in this section to estimate
emissions from the miscellaneous use of
carbonates. The methods presented in
this section should be used by facilities
that use carbonates in source categories
other than those listed above, but which
are covered by the proposed rule.
As estimated in the U.S. GHG
Inventory, national process emissions
from other limestone and dolomite uses
(i.e., excluding cement, lime, and glass
manufacturing) were 7.9 million metric
tons CO2e in 2006 (0.1 percent of U.S.
emissions). CH4 and N2O are not
PO 00000
Frm 00080
Fmt 4701
Sfmt 4702
released from the calcination of
carbonates.
For additional background
information on the use of limestone,
dolomite and other carbonates, please
refer to the Miscellaneous Uses of
Carbonates TSD (EPA–HQ–OAR–2008–
0508–021).
2. Selection of Reporting Threshold
A separate threshold analysis is not
proposed for uses of limestone,
dolomite and other carbonates as these
emissions occur in a large number of
facilities across a range of industries.
We propose that facilities with source
categories identified in proposed 40
CFR 98.2(a)(1) or (a)(2) consuming
limestone, dolomite and other
carbonates calculate the relevant
emissions from their facility, including
emissions from calcination of
carbonates, to determine whether they
surpass the proposed threshold for that
industry. Data were not available to
quantify emissions from the calcination
of carbonates across all industries;
therefore, these emissions were
considered where appropriate in the
thresholds analysis for the respective
industries.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from the use of limestone, dolomite and
other carbonates (e.g., the 2006 IPCC
Guidelines, U.S. Inventory, DOE
1605(b), the EU Emissions Trading
System, and the Australian National
Greenhouse Gas Reporting Program).
These methodologies all rely on
measuring the consumption of
carbonate inputs, but differ in their use
of default values. The range of default
values reflect differing assumptions of
the carbonate weight fraction in process
inputs; for example, the 2006 IPCC
Guidelines Tier 1 and 2 assume that
carbonate inputs are 95 percent pure
(i.e., 95 percent of the mass consumed
is carbonate), whereas the Australian
Program assumes a default purity of 90
percent for limestone, 95 percent for
dolomite, and 100 percent for
magnesium carbonate.
We propose that facilities estimate
process emissions by measuring the
type and quantity of carbonate input to
a kiln or furnace and applying the
appropriate emissions factors for the
carbonates consumed. In order to assess
the composition of the carbonate input,
we propose that facilities send samples
of each carbonate consumed to an offsite laboratory for a chemical analysis of
E:\FR\FM\10APP2.SGM
10APP2
16527
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the carbonate weight fraction on an
annual basis. Emission factors are based
on stoichiometry and are presented in
Table U–1 of this preamble. You would
also be required to determine the
calcination fraction for each of the
carbonate-based minerals consumed,
using an appropriate test method. The
calcination fraction is the fraction of
carbonate that is volatilized in the
process. A calcination fraction of 1.0
could over estimate CO2 emissions. You
would refer to proposed 40 CFR part 98,
subpart C specifically for procedures to
estimate combustion-related CO2, CH4
and N2O emissions.
analysis on the fraction calcination of
carbonates consumed were lost or
missing, the analysis would have to be
repeated. It is assumed that a facility
would be able to supply facility-specific
carbonate consumption data. The
likelihood for missing data is low, as
businesses closely track production
inputs.
5. Selection of Data Reporting
Requirements
We propose that facilities report
annual CO2 emissions from carbonate
consumption. In addition, we are
proposing that facilities submit the
following data which are the basis of the
TABLE U–1. CO2 EMISSION FACTORS emission calculation and are needed for
us to understand the emissions data and
FOR COMMON CARBONATES
assess the reasonableness of the
CO2 emission reported emissions: annual carbonate
factor
consumption (in metric tons, by
(metric tons
carbonate) and the total fraction of
Mineral name—carbonate
ons CO2/metcalcination achieved (for each
ric tons on
carbonate). A full list of data to be
carbonate)
reported is included in proposed 40
Limestone—CaCO3 ..............
0.43971 CFR part 98, subparts A and U.
Magnesite—MgCO3 ..............
Dolomite—CaMg(CO3)2 ........
Siderite—FeCO3 ...................
Ankerite—
Ca(Fe,Mg,Mn)(CO3)2 ........
Rhodochrosite—MnCO3 .......
Sodium Carbonate/Soda
Ash—Na2CO3 ....................
0.52197
0.47732
0.37987
6. Selection of Records That Must Be
Retained
We propose that facilities retain
* 0.44197
0.38286 records on monthly carbonate
consumption (by type), annual records
0.41492 on the fraction of calcination achieved
(by carbonate type), and results of the
* This is an average of the range provided
annual chemical analysis. These records
by the 2006 IPCC Guidelines.
provide values that are directly used to
We also considered but decided not to calculate the emissions that are reported
propose simplified methods (similar to
and are necessary to allow
IPCC Tier 1 and 2) for quantifying
determination of whether the GHG
process-related emissions from this
emissions monitoring and calculations
source, which assumes that limestone
were done correctly. A full list of
and dolomite are the only carbonates
records that must be retained onsite is
consumed, and allow for the use of
included in proposed 40 CFR part 98,
default fractions of the two carbonates
subparts A and U.
(85 percent for limestone and 15 percent
V. Nitric Acid Production
for dolomite). Default factors do not
account for variability in relative
1. Definition of the Source Category
carbonate consumption by other sources
Nitric acid is an inorganic chemical
and therefore inaccurately estimate
that is used in the manufacture of
emissions.
The various approaches to monitoring nitrogen-based fertilizers, adipic acid,
and explosives. Nitric acid is also used
GHG emissions are elaborated in the
for metal etching and processing of
Miscellaneous Uses of Carbonates TSD
ferrous metals. A nitric acid production
(EPA–HQ–OAR–2008–0508–021).
facility uses oxidation, condensation,
4. Selection of Procedures for Estimating and absorption to produce a weak nitric
Missing Data
acid (30 to 70 percent in strength). The
We propose that 100 percent data
production process begins with the
availability is required. If chemical
stepwise catalytic oxidation of ammonia
(NH3) through nitric oxide (NO) to
nitrogen dioxide (NO2) at high
temperatures. Then the NO2 is absorbed
in and reacted with water (H2O) to form
nitric acid (HNO3).
According to a facility-level inventory
for 2006, there are 45 nitric acid
production facilities operating in 25
States with a total of 65 process lines.
These facilities represent the best
available data at the time of this
rulemaking. Using the facility-level
inventory, production levels for 2006
have been estimated at 6.6 million
metric tons of nitric acid and indicate
an estimated 17.7 million metric tons
CO2e of process-related emissions (this
represents the CO2 equivalent of N2O
emissions, which is the primary
process-related GHG). Nitric Acid
process emissions were estimated in the
U.S. GHG Inventory at 15.4 million
metric tons CO2e in 2006 or 0.2 percent
of total U.S. GHG emissions. The main
reason for the difference in estimates is
that the methodology of the U.S.
Inventory assumed 20 percent of the
nitric acid facilities were using
nonselective catalytic reduction as an
N2O abatement technology. The facilitylevel analysis showed that only five
percent of the nitric acid facilities are
using nonselective catalytic reduction.
Stationary combustion emissions
were not estimated at the source
category level in the U.S. GHG
Inventory. Stationary combustion
emissions at nitric acid facilities may be
associated with other chemical
production processes as well (such as
adipic acid production, phosphoric acid
production, or ammonia
manufacturing).
For additional background
information on nitric acid production,
please refer to the Nitric Acid
Production TSD (EPA–HQ–OAR–2008–
0508–022).
2. Selection of Reporting Threshold
In developing the proposed threshold
for nitric acid production, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Table V–1 of
this preamble illustrates the emissions
and facilities that would be covered
under these various thresholds.
TABLE V–1. THRESHOLD ANALYSIS FOR NITRIC ACID PRODUCTION
Process N2O emissions covered
(metric tons CO2e/yr)
N2O emission threshold
(metric tons CO2e)
Number
1,000 ..............................................................................................................
10,000 ............................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00081
Fmt 4701
Percent
17,731,650
17,723,576
Sfmt 4702
E:\FR\FM\10APP2.SGM
100
99.9
10APP2
Facilities
covered
Number
Percent
45
44
100
97.8
16528
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE V–1. THRESHOLD ANALYSIS FOR NITRIC ACID PRODUCTION—Continued
Process N2O emissions covered
(metric tons CO2e/yr)
N2O emission threshold
(metric tons CO2e)
Number
25,000 ............................................................................................................
100,000 ..........................................................................................................
We are proposing all nitric acid
facilities report in order to simplify the
rule and avoid the need for each facility
to calculate and report whether it
exceeds the threshold value. Facilitylevel emissions estimates based on plant
production suggests that all known
facilities, except two, exceed the 25,000
metric tons CO2e threshold. When
facility-level production data were not
known, capacity data were used along
with a utilization factor of 70 percent.
The utilization factor is based on total
2006 nitric acid production from the
U.S. Census Bureau and capacity
estimates from publicly available
sources.
This analysis, however, only took into
account process-related emissions, as
combustion-related emissions were not
available. Had combustion-related
emissions been included, it is probable
that additional facilities would have
been covered at each threshold. An ‘‘all
in’’ threshold captures 100 percent of
emissions without significantly
increasing the number of facilities
required to report. Finally, the cost of
reporting using the proposed monitoring
method does not vary significantly
between the four different emissions
based thresholds.
For a full discussion of the threshold
analysis, please refer to the Nitric Acid
Production TSD (EPA–HQ–OAR–2008–
0508–022). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating these emissions (e.g. 2006
IPCC Guidelines, U.S. GHG Inventory,
DOE 1605(b), TCR, and EPA NSPS).
These methodologies coalesce around
the five options discussed below.
Option 1. Apply default emission
factors to total facility production of
nitric acid using the Tier 1 approach
established by the IPCC. The emissions
are calculated using the total production
of nitric acid and the highest
international default emission factor
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
17,706,259
17,511,444
available in the 2006 IPCC Guidelines,
based on technology type. It also
assumes no abatement of N2O
emissions.
Option 2. Apply default emission
factors on a site-specific basis using the
Tier 2 approach established by the IPCC.
This approach is also consistent with
the DOE 1605(b) ‘‘B’’ rated approach.
These emission factors are dependent
on the type of nitric acid process used,
the type of abatement technology used,
and the production activity. The
process-related N2O emissions are then
estimated by multiplying the emission
factor by the production level of nitric
acid (on a 100 percent acid basis).
Option 3. Follow the Tier 3 approach
established by IPCC using periodic
direct monitoring of N2O emissions to
determine the relationship between
nitric acid production and the amount
of N2O emissions; i.e., develop a sitespecific emissions factor. The sitespecific emission factor would be
determined from an annual
measurement or a single annual stack
test. The site-specific emissions factor
developed from this test and production
rate (activity level) is used to calculate
N2O emissions. After the initial test,
annual testing of N2O emissions would
be required each year to estimate the
emission factor and applied to
production to estimate emissions. The
yearly testing would assist in verifying
the emission factor. Testing would also
be required whenever the production
rate is changed by more than 10 percent
from the production rate measured
during the most recent performance test.
Option 4. Follow the approach used
by the Nitric Acid NSPS (40 CFR part
60, subpart G). This option would
require monitoring NOX emissions on a
continuous basis and measuring N2O
emissions to establish a site-specific
emission factor that relates NOX
emissions to N2O emissions. The
emission factor would then be used to
estimate N2O emissions based on
continuous reading of NOX emissions.
Periodic measurement would also be
required to verify the emission factor
over time. Testing would also be
required whenever the production rate
is changed by more than 10 percent
PO 00000
Frm 00082
Fmt 4701
Percent
Sfmt 4702
99.9
98.8
Facilities
covered
Number
Percent
43
40
95.6
88.9
from the production rate measured
during the most recent performance test.
Option 5. Follow the Tier 3 approach
established by IPCC using continuous
monitoring. Use CEMS to directly
measure N2O concentration and flow
rate to directly determine N2O
emissions. CEMS that measure N2O
emissions directly are available, but the
nitric acid industry is currently using
only NOX CEMS.
Proposed Option. We are proposing
Option 3 to quantify N2O process
emissions from all nitric acid facilities.
You would be required to follow the
requirements in proposed 40 CFR part
98, subpart C to estimate emissions of
CO2, CH4 and N2O from stationary
combustion. We identified Options 3, 4,
and 5 as the approaches providing the
highest certainty and the best sitespecific estimates. These three options
span the range of types of
methodologies currently used that do
not apply default values. These options
all use site-specific approaches that
would provide insight into different
levels of emissions caused by sitespecific differences in process operation
and abatement technologies. Option 3
requires an annual test of N2O emissions
and the establishment of a site-specific
emissions factor that relates N2O
emissions with the nitric acid
production rate.
Options 4 and 5 are similar in that
both use continuous monitoring to
calculate N2O emissions. Option 5
directly measures the N2O emissions.
Option 4 uses continuous measurement
of NOX emissions to estimate a sitespecific emission factor that relates NOX
emissions to N2O emissions. The
emission factor is then used to estimate
N2O emissions based on continuous
readings of NOX emissions.
Option 5 would provide the highest
certainty of the three options and
capture the smallest changes in N2O
emissions over time, but N2O CEMS are
not currently in use in the industry and
there is no existing EPA method for
certifying N2O CEMS. Option 3 and
Option 4 use site-specific emission
factors so the margin of error is much
lower than using default emission
factors. Option 4 would require the use
of NOX CEMS that are already in use by
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
many nitric acid facilities to
automatically capture and record any
changes in NOX emissions over time.
However, NOX CEMS only capture
emissions of NO and NO2 and not N2O.
Therefore they would not be useful in
the estimation of N2O emissions from
nitric acid production facilities.
Although the amount of NOX and N2O
emissions from nitric acid production
may be directly related, direct
measurement of NOX does not
automatically correlate to the amount of
N2O in the same exhaust stream.
Periodic testing of N2O emissions
(Option 3) would not indicate changes
in emissions over short periods of time,
but does offer direct measurement of the
GHG.
We request comment, along with
supporting documentation, on the
advantages and disadvantages of using
Options 3, 4 and 5. After consideration
of public comments, EPA may
promulgate one or more of these options
or a combination based on the
additional information that is provided.
We decided not to propose Options 1
and 2 because the use of default values
and lack of direct measurements results
in a high level of uncertainty. Although
different default emissions factors have
been developed for different processes
(e.g., low pressure, high pressure) and
abatement techniques, the use of these
default values is more appropriate for
sector wide or national total estimates
than for determining emissions from a
specific facility. Site-specific emission
factors are more appropriate for
reflecting differences in process design
and operation.
The various approaches to monitoring
GHG emissions are elaborated in the
Nitric Acid Production TSD (EPA–HQ–
OAR–2008–0508–022).
4. Selection of Procedures for Estimating
Missing Data
For process sources that use a sitespecific emission factor, no missing data
procedures would apply because the
site-specific emission factor is derived
from an annual performance test and
used in each calculation. The emission
factor would be multiplied by the
production rate, which is readily
available. If the test data is missing or
lost, the test would have to be repeated.
Therefore, 100 percent data availability
would be required.
5. Selection of Data Reporting
Requirements
We propose that facilities report
annual N2O emissions (in metric tons)
from each nitric acid production line. In
addition, we propose that facilities
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
submit the following data to understand
the emissions data and verify the
reasonableness of the reported
emissions. The data should include
annual nitric acid production capacity,
annual nitric acid production, type of
nitric acid production process used,
number of operating hours in the
calendar year, the emission rate factor
used, abatement technology used (if
applicable), abatement technology
efficiency, and abatement utilization
factor.
Capacity, actual production, and
operating hours would be helpful in
determining the potential for growth in
the nitric acid industry. The production
rate can be determined through sales
records or by direct measurement using
flow meters or weigh scales. This
industry generally measures the
production rate as part of normal
operating procedures.
A list of abatement technologies
would be helpful in assessing how
widespread the use of abatement is in
the nitric acid source category,
cataloging any new technologies that are
being used, and documenting the
amount of time that the abatement
technologies are being used.
A full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and V.
6. Selection of Records That Must Be
Retained
We propose that facilities maintain
records of significant changes to
process, N2O abatement technology
used, abatement technology efficiency,
abatement utilization factor (percent of
time that abatement system is
operating), annual testing of N2O
emissions, calculation of the sitespecific emission rate factor, and annual
production of nitric acid.
A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and V.
W. Oil and Natural Gas Systems
1. Definition of the Source Category
The U.S. petroleum and natural gas
industry encompasses hundreds of
thousands of wells, hundreds of
processing facilities, and over a million
miles of transmission and distribution
pipelines. This section of the preamble
identifies relevant facilities and outlines
methods and procedures for calculating
and reporting fugitive emissions (as
defined in this section) of CH4 and CO2
from the petroleum and natural gas
industry. Methods and reporting
procedures for emissions resulting from
natural gas or crude oil combustion in
PO 00000
Frm 00083
Fmt 4701
Sfmt 4702
16529
prime movers such as compressors are
covered under Section V.C of this
preamble.
The natural gas segment involves
production, processing, transmission
and storage, and distribution of natural
gas. The U.S. also receives, stores, and
processes imported liquefied natural gas
(LNG) at LNG import terminals. The
petroleum segment involves crude oil
production, transportation and refining.
The relevant facilities covered in this
section are offshore petroleum and
natural gas production facilities,
onshore natural gas processing facilities
(including gathering/boosting stations),
onshore natural gas transmission
compression facilities, onshore natural
gas storage facilities, LNG storage
facilities, and LNG import facilities.
Fugitive emissions from petroleum
refineries are proposed for inclusion in
the rulemaking, but these emissions are
addressed in the petroleum refinery
section (Section V.Y) of this preamble.
Under this section of the preamble, we
seek comment on methods for reporting
fugitive emissions data from: On-shore
petroleum and natural gas production
and natural gas distribution facilities.
For this rulemaking, fugitive
emissions from the petroleum and
natural gas industry are defined as
unintentional equipment emissions and
intentional or designed releases of CH4and/or CO2-containing natural gas or
hydrocarbon gas (not including
combustion flue gas) from emissions
sources including, but not limited to,
open ended lines, equipment
connections or seals to the atmosphere.
In the context of this rule, fugitive
emissions also mean CO2 emissions
resulting from combustion of natural gas
in flares. These emissions are hereafter
collectively referred to as ‘‘fugitive
emissions’’ or ‘‘emissions’’. We seek
comment on the proposed definition of
fugitives, which is derived from the
definition of fugitive emissions outlined
in the 2006 IPCC Guidelines for
National GHG Inventories, and is often
used in the development of GHG
inventories. We acknowledge that there
are multiple definitions for fugitives, for
example, defining the term fugitives to
include ‘‘those emissions which could
not reasonably pass through a stack,
chimney, vent, or other functionallyequivalent opening’’. According to the
2008 U.S. Inventory, total fugitive
emissions of CH4 and CO2 from the
natural gas and petroleum industry were
160 metric tons CO2e in 2006. The
breakdown of these fugitive emissions is
shown in Table W–1 of this preamble.
E:\FR\FM\10APP2.SGM
10APP2
16530
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE W–1. FUGITIVE EMISSIONS FROM PETROLEUM AND NATURAL GAS SYSTEMS (2006)
Fugitive
CH4
(MMTCO2e)
Sector
Natural Gas Systems1 .....................................................................................................................................................
Petroleum Systems ..........................................................................................................................................................
1 Emissions
102.4
28.4
28.5
0.3
account for Natural Gas STAR Partner Reported Reductions.
Natural gas system fugitive CH4
emissions resulted from onshore and
offshore natural gas production facilities
(27 percent); onshore natural gas
processing facilities (12 percent);
natural gas transmission and
underground natural gas storage,
including LNG import and LNG storage
facilities (37 percent); and natural gas
distribution facilities (24 percent).
Natural gas segment fugitive CO2
emissions were primarily from onshore
natural gas processing facilities (74
percent), followed by onshore and
offshore natural gas production facilities
(25 percent), and less than 1 percent
each from natural gas transmission and
underground natural gas storage and
distribution facilities.80
Petroleum segment fugitive CH4
emissions are primarily associated with
onshore and offshore crude oil
production facilities (>97 percent of
emissions) and petroleum refineries (2
percent) and are negligible in crude oil
transportation facilities (<0.5 percent).
Petroleum segment fugitive CO2
emissions are only estimated for
onshore and offshore production
facilities.
With over 160 different sources of
fugitive CH4 and CO2 emissions in the
petroleum and natural gas industry,
identifying those sources most relevant
for a reporting program was a challenge.
We developed a decision tree analysis
and undertook a systematic review of
each emissions source category
included in the Inventory of U.S. GHG
Emissions and Sinks. In determining the
most relevant fugitive emissions sources
for inclusion in this reporting program,
we applied the following criteria: the
coverage of fugitive emissions for the
source category as a whole, the coverage
of fugitive emissions per unit of the
source category, feasibility of a viable
monitoring method, including direct
measurement and engineering
estimations, and an administratively
manageable number of reporting
facilities.
80 The distribution of CO emissions is slightly
2
misleading due to current U.S. Inventory
convention which assumes that all CO2 from
natural gas processing facilities is emitted. In fact,
approximately 7,000 metric tons CO2e is captured
and used for EOR.
VerDate Nov<24>2008
Fugitive
CO2
(MMTCO2e)
15:41 Apr 09, 2009
Jkt 217001
Another factor we considered in
assessing the applicability of certain
petroleum and natural gas industry
fugitive emissions in a mandatory
reporting program is the definition of a
facility. In other words, what physically
constitutes a facility? This definition is
important to determine who the
reporting entity would be, and to ensure
that delineation is clear and double
counting of fugitive emissions is
minimized. For some segments of the
industry, identifying the facility is clear
since there are physical boundaries and
ownership structures that lend
themselves to identifying scope of
reporting and responsible reporting
entities (e.g., onshore natural gas
processing facilities, natural gas
transmission compression facilities, and
offshore petroleum and natural gas
facilities). In other segments of the
industry, such as the pipelines between
compressor stations, and more
particularly onshore petroleum and
natural gas production, such
distinctions are not straightforward. In
defining a facility, we reviewed current
definitions used in the CAA and ISO
definitions, consulted with industry,
and reviewed current regulations
relevant to the industry. The full results
of our assessment can be found in the
Oil and Natural Gas Systems TSD (EPA–
HQ–OAR–2008–0508–023).
Following is a brief discussion of the
proposed selected and excluded sources
based on our analysis. Additional
information can be found in the Oil and
Natural Gas Systems TSD (EPA–HQ–
OAR–2008–0508–023). This section of
the preamble addresses only fugitive
emissions. Combustion-related
emissions are discussed in Section V.C
of this preamble.
Offshore Petroleum and Natural Gas
Production Facilities. Offshore
petroleum and natural gas production
includes both shallow and deep water
wells in both U.S. State and Federal
waters. These offshore facilities house
equipment to extract hydrocarbons from
the ocean floor and transport it to
storage or transport vessels or onshore.
Fugitive emissions result from sources
housed on the platforms.
In 2006, offshore petroleum and
natural gas production fugitive CO2 and
PO 00000
Frm 00084
Fmt 4701
Sfmt 4702
CH4 emissions accounted for 5.6 million
metric tons CO2e. The primary sources
of fugitive emissions from offshore
petroleum and natural gas production
are from valves, flanges, open-ended
lines, compressor seals, platform vent
stacks, and other source components.
Flare stacks account for the majority of
fugitive CO2 emissions.
Offshore petroleum and natural gas
production facilities are proposed for
inclusion due to the fact that this
represents approximately 4 percent of
emissions from the petroleum and
natural gas industry, ‘‘facilities’’ are
clearly defined, and major fugitive
emissions sources can be characterized
by direct measurement or engineering
estimation.
Onshore Natural Gas Processing
Facilities. Natural gas processing
includes gathering/ boosting stations
that dehydrate and compress natural gas
to be sent to natural gas processing
facilities, and natural gas processing
facilities that remove NGLs and various
other constituents from the raw natural
gas. The resulting ‘‘pipeline quality’’
natural gas is injected into transmission
pipelines. Compressors are used within
gathering/ boosting stations and also
natural gas processing facilities to
adequately pressurize the natural gas so
that it can pass through all of the
processes into the transmission
pipeline.
Fugitive CH4 emissions from
reciprocating and centrifugal
compressors, including centrifugal
compressor wet and dry seals,
reciprocating compressor rod packing,
and all other compressor fugitive
emissions, are the primary CH4 emission
source from this segment. The majority
of fugitive CO2 emissions come from
acid gas removal vent stacks, which are
designed to remove CO2 and hydrogen
sulfide, when present, from natural gas.
While these are the major fugitive
emissions sources in natural gas
processing facilities, if other potential
fugitive sources such as flanges, openended lines and threaded fittings are
present at your facility you would need
to account for them if reporting under
proposed 40 CFR part 98, subpart W.
For this subpart you would assume no
capture of CO2 because capture and
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
transfer of CO2 offsite would be
calculated in accordance with Section
V.PP of this preamble and reported
separately.
Onshore natural gas processing
facilities are proposed for inclusion due
to the fact that these operations
represent a significant emissions source,
approximately 25 percent of emissions
from the natural gas segment.
‘‘Facilities’’ are easily defined and major
fugitive emissions sources can be
characterized by direct measurement or
engineering estimation.
Onshore Natural Gas Transmission
Compression Facilities and
Underground Natural Gas Storage
Facilities. Natural gas transmission
compression facilities move natural gas
throughout the U.S. natural gas
transmission system. Natural gas is also
injected and stored in underground
formations during periods of low
demand (e.g., spring or fall) and
withdrawn, processed, and distributed
during periods of high demand (e.g.,
winter or summer). Storage compressor
stations are dedicated to gas injection
and extraction at underground natural
gas storage facilities.
Fugitive CH4 emissions from
reciprocating and centrifugal
compressors, including centrifugal
compressor wet and dry seals,
reciprocating compressor rod packing,
and all other compressor fugitive
emissions, are the primary CH4 emission
source from natural gas transmission
compression stations and underground
natural gas storage facilities.
Dehydrators are also a significant source
of fugitive CH4 emissions from
underground natural gas storage
facilities. While these are the major
fugitive emissions sources in natural gas
transmission, other potential fugitive
sources include, but are not limited to,
condensate tanks, open-ended lines and
valve seals.
Transmission compression facilities
and underground natural gas storage
facilities are proposed for inclusion due
to the fact that these operations
represent a significant emissions source,
approximately 24 percent of emissions
from the natural gas segment;
‘‘facilities’’ are easily defined, and major
fugitive sources can be characterized by
direct measurement or engineering
estimation.
LNG Import and LNG Storage
Facilities. The U.S. imports natural gas
in the form of LNG, which is received,
stored, and, when needed, processed
and compressed at LNG import
terminals. LNG storage facilities liquefy
and store natural gas from transmission
pipelines during periods of low demand
(e.g., spring or fall) and vaporize for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
send out during periods of high demand
(e.g., summer and winter)
Fugitive CH4 and CO2 emissions from
reciprocating and centrifugal
compressors, including centrifugal
compressor wet and dry seals,
reciprocating compressor rod packing,
and all other compressor fugitive
emissions, are the primary CH4 and CO2
emission source from LNG storage
facilities and LNG import facilities.
Process units at these facilities can
include compressors to liquefy natural
gas (at LNG storage facilities), recondensers, vaporization units, tanker
unloading equipment (at LNG import
terminals), transportation pipelines,
and/or pumps.
LNG storage facilities and LNG import
facilities are proposed for inclusion due
to the fact that fugitive emissions from
these operations represent
approximately 1 percent of emissions
from natural gas systems. LNG storage
‘‘facilities’’ are defined as facilities that
store liquefied natural gas in above
ground storage tanks. LNG import
terminal ‘‘facilities’’ are defined as
facilities that receive imported LNG,
store it in storage tanks, and release regasified natural gas for transportation.
Onshore Petroleum and Natural Gas
Production. Similar to offshore
petroleum and natural gas production,
the onshore petroleum and natural gas
production segment uses wells to draw
raw natural gas, crude oil, and
associated gas from underground
formations. The most dominant sources
of fugitive CH4 and CO2 emissions
include, but are not limited to, natural
gas driven pneumatic valve and pump
devices, field crude oil and condensate
storage tanks, chemical injection
pumps, releases and flaring during well
completion and workovers, and releases
and flaring of associated gas.
We considered proposing the
reporting of fugitive CH4 and CO2
emissions from onshore petroleum and
natural gas production in the rule.
Onshore petroleum and natural gas
production is responsible for the largest
share of fugitive CH4 and CO2 emissions
from petroleum and natural gas industry
(27 percent of total emissions).
However, this segment is not proposed
for inclusion primarily due to the
unique difficulty in defining a ‘‘facility’’
in this sector and correspondingly
determining who would be responsible
for reporting.
Given the significance of fugitive
emissions from the onshore petroleum
and natural gas production, we would
like to take comment on whether we
should consider inclusion of this source
category in the future. Specifically, we
would like to take comment on viable
PO 00000
Frm 00085
Fmt 4701
Sfmt 4702
16531
ways to define a facility for onshore oil
and gas production and to determine the
responsible reporter. In addition, the
Agency also requests comment on the
merits and/or concerns with the
corporate basin level reporting approach
under consideration for onshore oil and
gas production, as outlined below.
One approach we are considering for
including onshore petroleum and
natural gas production fugitive
emissions in this reporting rule is to
require corporations to report emissions
from all onshore petroleum and natural
gas production assets at the basin level.
In such a case, all operators in a basin
would have to report their fugitive
emissions from their operations at the
basin-level. For such a basin-level
facility definition, we may propose
reporting of only the major fugitive
emissions sources; i.e., natural gas
driven pneumatic valve and pump
devices, well completion releases and
flaring, well blowdowns, well
workovers, crude oil and condensate
storage tanks, dehydrator vent stacks,
and reciprocating compressor rod
packing. Under this scenario, we might
suggest that all operators would be
subject to reporting, perhaps exempting
small businesses, as defined by the
Small Business Administration.
This approach could substantially
reduce the reporting complexity and
require individual companies that
produce crude oil and/or natural gas in
each basin to be responsible for
reporting emissions from all of their
onshore petroleum and natural
production operations in that basin,
including from rented sources, such as
compressors. In cases where
hydrocarbons or emissions sources are
jointly owned by more than one
company, each company would report
emissions equivalent to its portion of
ownership.
We considered other options in
defining a facility such as individual
wellheads or aggregating all emissions
sources prior to compression as a
facility. However, such definitions
result in complex reporting
requirements and are difficult to
implement.
We are seeking comments on
reporting of the major fugitive emissions
sources by corporations at the basin
level for onshore petroleum and natural
gas production.
Petroleum and Natural Gas Pipeline
Segments. Natural gas transmission
involves high pressure, large diameter
pipelines that transport gas long
distances from field production and
natural gas processing facilities to
natural gas distribution pipelines or
large volume customers such as power
E:\FR\FM\10APP2.SGM
10APP2
16532
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
plants or chemical plants. Crude oil
transportation involves pump stations to
move crude oil through pipelines and
loading and unloading crude oil tanks,
marine vessels, and rails.
The majority of fugitive emissions
from the transportation of natural gas
occur at the compressor stations, which
are already proposed for inclusion in
the rule and discussed above. We do not
propose to include reporting of fugitive
emissions from natural gas pipeline
segments between compressor stations,
or crude oil pipelines in the rulemaking
due to the dispersed nature of the
fugitive emissions, the difficulty in
defining pipelines as a facility, and the
fact that once fugitives are found, they
are generally fixed quickly, not allowing
time for monitoring and direct
measurement of the fugitives.
Natural Gas Distribution. In the
natural gas distribution segment, highpressure gas from natural gas
transmission pipelines enter ‘‘city gate’’
stations, which reduce the pressure and
distribute the gas through primarily
underground mains and service lines to
individual end users. Distribution
system CH4 and CO2 emissions result
mainly from fugitive emissions from
gate stations (metering and regulating
stations) and vaults (regulator stations),
and fugitive emissions from
underground pipelines. At gate stations
and vaults, fugitive CH4 emissions
primarily come from valves, open-ended
lines, connectors, and natural gas driven
pneumatic valve devices.
Although fugitive emissions from a
single vault, gate station or segment of
pipeline in the natural gas distribution
segment may not be significant,
collectively these fugitive emissions
sources contribute a significant share of
fugitive emissions from natural gas
systems.
We do not propose to include the
natural gas distribution segment of the
natural gas industry in this rulemaking
due to the dispersed nature of the
fugitive emissions and difficulty in
defining a facility such that there would
be an administratively manageable
number of reporters.
One approach to address the concern
with defining a facility for distribution
would be to require corporate-level
reporting of fugitive emissions from
major sources by distribution
companies. We seek comment on this
and other ways of reporting fugitive
emissions from the distribution sector.
Crude Oil Transportation. Crude oil is
commonly transported by barge, tanker,
rail, truck, and pipeline from
production operations and import
terminals to petroleum refineries or
export terminals. Typical equipment
associated with these operations are
storage tanks and pumping stations. The
major sources of CH4 and CO2 fugitive
emissions include releases from tanks
and marine vessel loading operations.
We do not propose to include the
crude oil transportation segment of the
petroleum and natural gas industry in
this rulemaking due to its small
contribution to total petroleum and
natural gas fugitive emissions,
accounting for much less than 1 percent,
and the difficulty in defining a facility.
2. Selection of Reporting Threshold
We propose that facilities with
emissions greater than 25,000 metric
tons CO2e per year be subject to
reporting. This threshold is applicable
to all oil and natural gas system
facilities covered by this subpart:
Offshore petroleum and natural gas
production facilities, onshore natural
gas processing facilities, including
gathering/boosting stations; natural gas
transmission compression facilities,
underground natural gas storage
facilities; LNG storage facilities; and
LNG import facilities.
To identify the most appropriate
threshold level for reporting of fugitive
emissions, we conducted analyses to
determine fugitive emissions reporting
coverage and facility reporting coverage
at four different levels of threshold;
1,000 metric tons CO2e per year, 10,000
metric tons CO2e per year, 25,000 metric
tons CO2e per year, and 100,000 metric
tons CO2e per year. Table W–2 of this
preamble provides coverage of
emissions and number of facilities
reporting at each threshold level for all
the industry segments under
consideration for this rule.
TABLE W–2. THRESHOLD ANALYSIS FOR FUGITIVE EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY
Total national emissions #a
(metric tons
CO2e per
year)
Source category
Total emissions covered by
thresholds s
Total number
of facilities
Offshore Petroleum & Gas Production
Facilities ............................................
10,162,179
2,525
Natural Gas Processing Facilities ........
50,211,548
566
Natural Gas Transmission Compression Facilities ....................................
73,198,355
Underground Natural Gas Storage Facilities ................................................
Threshold
level
(metric tons
CO2e per
year)
Percent
Facilities covered
Number
Percent
1,000
10,000
25,000
100,000
1,000
10,000
25,000
100,000
9,783,496
6,773,885
5,138,076
3,136,185
50,211,548
49,207,852
47,499,976
39,041,555
96
67
51
31
100
98
95
78
1,021
156
50
4
566
394
287
125
40
6
2
0.5
100
70
51
22
1,944
1,000
10,000
25,000
100,000
73,177,039
71,359,167
63,835,288
30,200,243
100
97
87
41
1,659
1311
874
216
85
67
45
11
11,719,044
398
LNG Storage Facilities .........................
1,956,435
157
LNG Import Facilities ...........................
1,896,626
5
1,000
10,000
25,000
100,000
1,000
10,000
25,000
100,000
1,000
11,702,256
10,975,728
9,879,247
5,265,948
1,940,203
1,860,314
1,670,427
637,477
1,896,626
100
94
84
45
99
95
85
33
100
346
197
131
35
54
39
29
3
5
87
49
33
9
34
25
18
2
100
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00086
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16533
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE W–2. THRESHOLD ANALYSIS FOR FUGITIVE EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY—
Continued
Total national emissions #a
(metric tons
CO2e per
year)
Source category
Total emissions covered by
thresholds s
Total number
of facilities
Threshold
level
10,000
25,000
100,000
(metric tons
CO2e per
year)
1,895,153
1,895,153
1,895,153
Percent
Facilities covered
Number
99.9
99.9
99.9
Percent
4
4
4
80
80
80
a The emissions include fugitive CH and CO and combusted CO , N O, and CH gases. The emissions for each industry segment do not
4
2
2
2
4
match the 2008 U.S. Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For additional discussion, refer to the Oil and Natural Gas Systems TSD (EPA–HQ–OAR–2008–0508–023).
A proposed threshold of 25,000
metric tons CO2e applied to only those
emissions sources listed in Table W–2
of this preamble captures approximately
81 percent of fugitive CH4 and CO2
emissions from the entire oil and
natural gas industry, while capturing
only a small fraction of total facilities.
For additional information, please refer
to the Oil and Natural Gas Systems TSD
(EPA–HQ–OAR–2008–0508–023). For
specific information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating fugitive emissions from oil
and natural gas operations, including
the 2006 IPCC Guidelines, U.S. GHG
Inventory, DOE 1605(b), and corporate
industry protocols developed by the
American Petroleum Institute, the
Interstate Natural Gas Association of
America, and the American Gas
Association. The methodologies
proposed vary by the emissions source,
for example fugitive emissions versus
vented emissions, versus emissions
from flares (all of which are considered
‘‘fugitive’’ emissions in this
rulemaking). Generally, approaches
range from direct measurement (e.g.,
high volume samplers), to engineering
equations (where applicable), to simple
emission factor approaches based on
national default factors.
Proposed Option. We propose that
facilities would be required to detect
fugitive emissions from the identified
emissions sources proposed in this
rulemaking, and then quantify
emissions using either engineering
equations or direct measurement.
Fugitive emissions from all affected
emissions sources at the facility,
whether in operating condition or on
standby, would have to be monitored on
an annual basis. The proposed
monitoring method would depend on
the fugitive emissions sources in the
facility to be monitored. Each fugitive
emissions source would be required to
be monitored using one of the two
monitoring methods: (1) Direct
measurement or (2) engineering
estimation. Table W–3 of this preamble
provides the proposed fugitive
emissions source and corresponding
monitoring methods. General guidance
on the monitoring methods is given
below.
TABLE W–3. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION
Emission source
Monitoring method type
Emissions quantification methods
Acid Gas Removal Vent Stacks .........................
Blowdown Vent Stacks .......................................
Engineering estimation ....................................
Engineering estimation ....................................
Centrifugal Compressor Dry Seals .....................
Direct measurement .........................................
Centrifugal Compressor Wet Seals ....................
Direct measurement .........................................
Compressor Fugitive Emissions .........................
Direct measurement .........................................
Dehydrator Vent Stacks .....................................
Flare Stacks .......................................................
Engineering estimation ....................................
Engineering estimation and direct measurement.
(1) Engineering estimation, or (2) Direct
measurement.
Simulation software.
Gas law and temperature, pressure, and volume between isolation valves.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
Simulation software.
Velocity meter and mass/volume equations.
Natural Gas Driven Pneumatic Pumps ..............
Natural Gas Driven Pneumatic Manual Valve
Actuator Devices.
Natural Gas Driven Pneumatic Valve Bleed Devices.
(1) Engineering estimation, or (2) Direct
measurement.
(1) Engineering estimation, or (2) Direct
measurement.
Non-pneumatic Pumps .......................................
Offshore Platform Pipeline Fugitive Emissions ..
Open-ended Lines ..............................................
Direct measurement .........................................
Direct measurement .........................................
Direct measurement .........................................
Pump Seals ........................................................
Direct measurement .........................................
Facility Fugitive Emissions .................................
Direct measurement .........................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00087
Fmt 4701
Sfmt 4702
(1) Manufacturer data, equipment counts, and
amount of chemical pumped, or (2) Calibrated bag.
(1) Manufacturer data and actuation logs, or
(2) Calibrated bag.
(1) Manufacturer data and equipment counts,
or (2) High volume sampler, or (3) Calibrated bag, or (4) Meter.
High volume sampler.
High volume sampler.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
High volume sampler.
E:\FR\FM\10APP2.SGM
10APP2
16534
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE W–3. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION—Continued
Emission source
Monitoring method type
Emissions quantification methods
Reciprocating Compressor Rod Packing ...........
Direct measurement .........................................
Storage Tanks ....................................................
(1) Engineering estimation and direct measurement, or (2) Engineering estimation.
(1) High volume sampler, or (2) Calibrated
bag, or (3) Meter.
(1) Meter, or (2) Simulation software, or (3)
Vasquez-Beggs Equation.
a. Direct Measurement
Fugitive emissions detection and
measurement are both required in cases
where direct measurement is being
proposed. Infrared fugitive emissions
detection instruments are capable of
detecting fugitive CH4 emissions, or
Toxic Vapor Analyzers or Organic
Vapor Analyzers can be used by the
operator to detect fugitive natural gas
emissions. These instruments detect the
presence of hydrocarbons in the natural
gas fugitive emissions stream. They do
not detect any pure CO2 fugitive
emissions. However, because all the
sources proposed for monitoring have
natural gas fugitive emissions that have
CH4 as one of its constituents, there is
no need for a separate detection
instrument for separately detecting CO2
fugitive emissions. The only exception
to this is fugitive emissions from acid
gas removal vent stacks where the
predominant constituent of the fugitive
emissions is CO2. Engineering
estimation is proposed for this source,
and therefore there is no need for
detection of fugitive emissions from
acid gas removal vent stacks.
In the Oil and Natural Gas Systems
TSD (EPA–HQ–OAR–2008–0508–023),
we describe a particular method based
on practicality of application. For
example, using Toxic Vapor Analyzers
or Organic Vapor Analyzers on very
large facilities is not as cost effective as
infrared fugitive emissions detection
instruments. We propose that
irrespective of the method used for
fugitive natural gas emissions detection,
the survey for detection must be
comprehensive. This means that, on an
annual basis, the entire population of
emissions sources proposed for fugitive
emissions reporting has to be surveyed
at least once. When selecting the
appropriate emissions detection
instrument, it is important to note that
certain instruments are best suited for
particular applications and
circumstances. For example, some
optical infrared fugitive emissions
detection instruments may not perform
well in certain weather conditions or
with certain colored backgrounds.
Infrared fugitive emissions detection
instruments are able to scan hundreds of
source components at once, allowing for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
efficient detection of emissions at large
facilities; however, infrared fugitive
emissions detection instruments are
typically much more expensive than
other options. Organic Vapor Analyzers
and Toxic Vapor Analyzers are not able
to detect fugitive emissions from many
components as quickly; however, for
small facilities this may provide a less
costly alternative to infrared fugitive
emissions detection without requiring
overly burdensome labor to perform a
comprehensive fugitive emissions
survey. We propose that operators
choose the instrument from the choices
provided in the proposed rule that is
best suited for their circumstance.
Further information is contained in the
Oil and Natural Gas Systems TSD (EPA–
HQ–OAR–2008–0508–023).
For direct measurement, we have
proposed that high volume samplers,
meters (such as rotameters, turbine
meters, hot wire anemometers, and
others), and/or calibrated bags be
designated for use. However, if fugitive
emissions exceed the maximum range of
the proposed monitoring instrument,
you would be required to use a different
instrument option that can measure
larger magnitude emissions levels. For
example, if a high volume sampler is
pegged by a fugitive emissions source,
then fugitive emissions would be
required to be directly measured using
either calibrated bagging or a meter. In
the Oil and Natural Gas Systems TSD
(EPA–HQ–OAR–2008–0508–023), we
discuss multiple options for
measurement where the range of
emissions measurement instruments is
seen as an issue. CH4 and CO2 fugitive
emissions from the natural gas fugitive
emissions stream can be calculated
using the composition of natural gas.
b. Engineering Estimation
Engineering estimation has been
proposed for calculating CH4 and CO2
fugitive emissions from sources where
the variable in the emissions magnitude
on an annual basis is the number of
times the source releases fugitive CH4
and CO2 emissions to the atmosphere.
For example, when a compressor is
taken offline for maintenance, the
volume of fugitive CH4 and CO2
emissions that are released is the same
during each release and the only
PO 00000
Frm 00088
Fmt 4701
Sfmt 4702
variable is the number of times the
compressor is taken offline. Also,
engineering estimates have been
proposed where safety concerns
prohibit the use of direct measurement
methods. For example, sometimes the
temperature of the fugitive emissions
stream for glycol dehydrator vent stacks
is too high for operators to safely
measure fugitive emissions. Based on
these principles, we propose that direct
measurement is mandatory unless there
is a demonstrated and documented
safety concern or frequency of fugitive
emission releases is the only variable in
emissions, at which time engineering
estimates can be applied.
c. Alternative Monitoring Methods
Considered
Before proposing the monitoring
methods discussed above, we
considered four additional measurement
methods. The use of Method 21 or the
use of activity and emission factors were
considered for fugitive emissions
detection and measurement. Although
Toxic Vapor Analyzers and Organic
Vapor Analyzers were considered but
not proposed for fugitive emissions
direct measurement they are acceptable
for fugitive emissions detection.
Method 21. This is the reference
method for equipment leak detection
and repair regulations for volatile
organic carbon (VOC) emissions under
several 40 CFR part 60 emission
standards. Method 21 of 40 CFR part 60
Appendix A–7 determines a
concentration at a point or points of
emissions expressed in parts per million
concentration of combustible
hydrocarbon in the air stream of the
instrument probe. This concentration is
then compared to the ‘‘action level’’ in
the referenced 40 CFR part 60 regulation
to determine if a leak is present.
Although Method 21 was not developed
for this purpose, it may allow for better
emission estimation than the overall
average emission factors that have been
published for equipment leaks.
Quantification of air emissions from
equipment leaks is generally done using
EPA published guidelines which
correlate the measured concentration to
a VOC mass emission rate based on
extensive measurements of air
emissions from leaking equipment. The
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
correlations are statistically determined
for a very large population of similar
components, but not very accurate for
single leaks or small populations.
Therefore, Method 21 was not found
suitable for fugitive emissions
measurement under this reporting rule.
However, we are seeking comments on
this conclusion, and whether Method 21
should be permitted as a viable
alternative method to estimate
emissions for sources where it is
currently required for VOC emissions.
Activity Factor and Emissions Factor
for All Sources. Fugitive CH4 emissions
factors for all of the fugitive emissions
sources proposed for inclusion in the
rule are available in a study that was
conducted in 1992.81 82 There have been
no subsequent comparable studies
published to replace or revise the
fugitive emissions estimates available
from this study. However, some
petroleum and natural gas industry
operations have changed significantly
with the introduction of new
technologies and improved operating
and maintenance practices to mitigate
fugitive emissions. These are not
reflected in the fugitive emissions
factors available. Also, in many cases
the fugitive emissions factors are not
representative of emission levels for
individual sources or are not relevant to
certain operations because the estimates
were based on limited or no field data.
Hence, they are not representative of the
entire country or specific petroleum and
natural gas facilities and fugitive
emissions sources such as tanks and
wells. Therefore, we did not propose
this method for estimation of the
fugitive emissions for reporting.
Default fugitive CO2 emissions factors
are available only for whole segments of
the industry (e.g., natural gas
processing), and are not available for
individual sources. Further, these are
international default factors, which have
a high uncertainty associated with them
and are not appropriate for facility-level
reporting.
Mass Balance for Quantification. We
considered, but decided not to propose,
the use of a mass balance approach for
quantifying emissions. This approach
would take into account the volume of
gas entering a facility and the amount
81 EPA/GRI (1996) Methane Emissions from the
Natural Gas Industry. Harrison, M., T. Shires, J.
Wessels, and R. Cowgill, (eds.). Radian
International LLC for National Risk Management
Research Laboratory, Air Pollution Prevention and
Control Division, Research Triangle Park, NC. EPA–
600/R–96–080a.
82 EPA (1999) Estimates of Methane Emissions
from the U.S. Oil Industry (Draft Report). Prepared
by ICF International. Office of Air and Radiation,
U.S. Environmental Protection Agency. October
1999.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
exiting the facility, with the difference
assumed to be emitted to the
atmosphere. This is most often
discussed for emissions estimation from
the transportation segment of the
industry. For transportation, the mass
balance is often not recommended
because of the uncertainties
surrounding meter readings and the
large volumes of throughput relative to
fugitive emissions. We are seeking
feedback on the use of a mass balance
approach and the applicability to each
sector of the oil and gas industry
(production, processing, transmission,
and distribution) as a potential
alternative to component level leak
detection and quantification.
Toxic Vapor Analyzers and Organic
Vapor Analyzers for Emissions
Measurement. Toxic Vapor Analyzer
and Organic Vapor Analyzer
instruments quantify the concentration
of combustible hydrocarbon from the
fugitive emission in the air stream, but
do not directly quantify the volumetric
or mass emissions. The instrument
probe rarely ingests all of the natural gas
from a fugitive emissions source.
Therefore, these instruments are used
primarily for fugitive emissions leak
detection. For the proposed rule,
fugitive CH4 emissions detection by
more cost-effective detection
technologies such as infrared fugitive
emissions detection instruments in
conjunction with direct measurement
methodologies such as the high volume
sampler, meters and calibrated bags is
deemed a better overall approach to
fugitive emissions quantification than
the labor intensive Organic Vapor
Analyzers and Toxic Vapor Analyzers,
which do not quantify volumetric or
mass fugitive emissions.
d. Outstanding Issues on Which We
Seek Comments
The proposed rule does not indicate
a particular threshold for detection
above which emissions measurement is
required. This is because the different
emissions detection instruments
proposed have different levels and types
of detection capabilities. Hence the
magnitude of actual emissions can only
be determined after measurement. This,
however, does not serve the purpose of
this rule in limiting burden on
emissions reporting. A facility can have
hundreds of small emissions (as low as
3 grams per hour) and it might not be
practical to measure all such small
emissions for reporting.
To address this issue we intend to
incorporate one of the following two
approaches in the final rule.
The first approach would provide
performance standards for fugitive
PO 00000
Frm 00089
Fmt 4701
Sfmt 4702
16535
emissions detection instruments and
usage such that all instruments follow a
common minimum detection threshold.
We may propose the use of the Alternate
Work Practice to Detect Leaks from
Equipment standards for infrared
fugitive emissions detection instruments
being developed by EPA. In such a case
all detected emissions from components
subject to this rule would require
measurement and reporting.
The second approach would provide
an emissions threshold above which the
source would be identified as an
‘‘emitter’’ for emissions detection using
Organic Vapor Analyzers or Toxic
Vapor Analyzers. When using infrared
fugitive emissions detection instruments
all sources subject to this rule that have
emissions detected would require
emissions quantification. Alternatively,
the operator would be given a choice of
first detecting emissions sources using
the infrared detection instrument and
then verifying for measurement status
using the emissions definition for
Organic Vapor Analyzers or Toxic
Vapor Analyzers.
We are seeking comments on using
the two options discussed above for
determining emission sources requiring
measurement of emissions.
Some fugitive emissions by nature
occur randomly within the facility.
Therefore, there is no way of knowing
when a particular source started
emitting. This proposed rule requires
annual fugitive emissions detection and
measurement. The emissions detected
and measured would be assumed to
continue throughout the reporting year,
unless no emissions detection is
recorded at an earlier and/or later point
in the reporting period. We recognize
that this may not necessarily be true in
all cases and that emissions reported
would be higher than actual. Therefore,
we are seeking comments on how this
issue can be resolved without resulting
in additional reporting burden to the
facilities.
The petroleum and natural gas
industry is already implementing
voluntary fugitive emissions detection
and repair programs. Such voluntary
programs are useful, but pose an
accounting challenge with respect to
emissions reporting for this rule. The
proposed rule requires annual detection
and measurement of fugitive emissions.
This approach does not preclude any
facility from performing emissions
detection and repair prior to the official
detection, measurement, and reporting
of emissions for this rule. We are
seeking comments on how to avoid
under-reporting of emissions as a result
of a preliminary, ‘‘un-official’’ emissions
E:\FR\FM\10APP2.SGM
10APP2
16536
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
survey and repair exercise ahead of the
‘‘official’’ annual survey.
Fugitive emissions from a compressor
are a function of the mode in which the
compressor is operating. Typically, a
compressor station consists of several
compressors with one (or more) of them
on standby based on system redundancy
requirements and peak delivery
capacity. Fugitive emissions at
compressors in standby mode are
significantly different than those from
compressors that are operating. The rule
proposes annual direct measurement of
fugitive emissions. This may not
adequately account for the different
modes in which a particular compressor
is operating through the reporting
period. We are soliciting input on a
method to measure emissions from each
mode in which the compressor is
operating, and the period of time
operated in that mode, that would
minimize reporting burden.
Specifically, given the variability of
these measured emissions, EPA requests
comment on whether engineering
estimates or other alternative methods
that account for total emissions from
compressors, including open ended
lines, could address this issue of
operating versus standby mode.
The fugitive emissions measurement
instruments (i.e. high volume sampler,
calibrated bags, and meters) proposed
for this rule measure natural gas
emissions. CH4 and CO2 emissions are
required to be estimated from the
natural gas mass emissions using
natural gas composition appropriate for
each facility. For this purpose, the
proposed rule requires that facilities use
existing gas composition estimates to
determine CH4 and CO2 components of
the natural gas emissions (flare stack
and storage tank fugitive emissions are
an exception to this general rule). We
have determined that these gas
composition estimates are available
from facilities reporting to this rule. We
are seeking comments on whether this
is a practical assumption. In the absence
of gas composition, an alternative
proposal would be to require the
periodic measurement of the required
gas composition for speciation of the
natural gas mass emissions into CH4 and
CO2 mass emissions.
4. Selection of Procedures for Estimating
Missing Data
The proposal requires data collection
for a single source a minimum of once
a year. If data are lost or an error occurs
during fugitive emissions direct
measurement, the operator should carry
out the direct measurement a second
time to obtain the relevant data point(s).
Similarly, engineering estimates must
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
account for relevant source counts and
frequency of fugitive emissions releases
throughout the year. There should not
be any missing data for estimating
fugitive emissions from petroleum and
natural gas systems.
5. Selection of Data Reporting
Requirements
We propose that fugitive emissions
from the petroleum and natural gas
industry be reported on an annual basis.
The reporting should be at a facility
level with fugitive emissions being
reported at the source type level.
Fugitive emissions from each source
type could be reported at an aggregated
level. In other words, process unit-level
reporting would not be required. For
example, a facility with multiple
reciprocating compressors could report
fugitive emissions from all reciprocating
compressors as an aggregate number.
Since the proposed monitoring method
is fugitive emissions detection and
measurement at the source level, we
determined that reporting at an
aggregate source type level is feasible.
Fugitive emissions from all sources
proposed for monitoring, whether in
operating condition or on standby,
would have to be reported. Any fugitive
emissions resulting from standby
sources would be separately identified
from the aggregate fugitive emissions.
The reporting facility would be
required to report the following
information to us as a part of the annual
fugitive emissions reporting: fugitive
emissions monitored at an aggregate
source level for each reporting facility,
assuming no carbon capture and transfer
offsite; the quantity of CO2 captured for
use and the end use, if known; fugitive
emissions from standby sources; and
activity data for each aggregate source
type level.
Additional data are proposed to be
reported to support verification:
Engineering estimate of total component
count; total number of compressors and
average operating hours per year for
compressors, if applicable; minimum,
maximum and average throughput per
year; specification of the type of any
control device used, including flares;
and detection and measurement
instruments used. For offshore
petroleum and natural gas production
facilities, the number of connected
wells, and whether they are producing
oil, gas, or both is proposed to be
reported. For compressors specifically,
we proposed that the total number of
compressors and average operating
hours per year be reported.
A full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and W.
PO 00000
Frm 00090
Fmt 4701
Sfmt 4702
6. Selection of Records That Must Be
Retained
The reporting facility shall retain
relevant information associated with the
monitoring and reporting of fugitive
emissions to us, as follows; throughput
of the facility when the fugitive
emissions direct measurement was
conducted, date(s) of measurement,
detection and measurement instruments
used, if any, results of the leak detection
survey, and inputs and outputs to
calculations or simulation software runs
where the proposed monitoring method
requires engineering estimation.
A full list of records to be retained is
included inproposed 40 CFR part 98,
subparts A and W.
X. Petrochemical Production
1. Definition of the Source Category
The petrochemical industry consists
of numerous processes that use fossil
fuel or petroleum refinery products as
feedstocks. For this proposed GHG
reporting rule, the reporting of processrelated emissions in the petrochemical
industry is limited to the production of
acrylonitrile, carbon black, ethylene,
ethylene dichloride, ethylene oxide, and
methanol. The petrochemicals source
category includes production of all
forms of carbon black (e.g., furnace
black, thermal black, acetylene black,
and lamp black) because these processes
use petrochemical feedstocks; bone
black is not considered to be a form of
carbon black because it is not produced
from petrochemical feedstocks. The rule
focuses on these six processes because
production of GHGs from these
processes has been recognized by the
IPCC to be significant compared to other
petrochemical processes. Facilities
producing other types of petrochemicals
are not subject to proposed 40 CFR part
98, subpart X of this reporting rule but
may be subject to 40 CFR part 98,
subpart C, General Stationary Fuel
Combustion Sources, or other subparts.
There are 88 facilities operating
petrochemical processes in the U.S., and
9 of these operate either two or three
types of petrochemical processes (e.g.,
ethylene and ethylene oxide). We
estimate petrochemical production
accounts for approximately 55 million
metric tons CO2e.
Total GHG emissions relevant to the
petrochemical industry primarily
include process-based emissions and
emissions from combustion sources.
Process-based emissions may be
released to the atmosphere from process
vents, equipment leaks, aerobic
biological treatment systems, and in
some cases, combustion source vents.
CH4 may also be a process-based
E:\FR\FM\10APP2.SGM
10APP2
16537
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
emission from processes where CH4 is a
feedstock (e.g., when methanol is
produced from synthesis gas that is
derived from reforming natural gas,
some CH4 passes through the process
without being converted and is emitted).
Emissions from the burning of process
off-gas to supply energy to the process
are also process-based emissions
because the organic compounds being
burned are derived from the feedstock
chemical. These emissions are included
with other process-based emissions if
the mass balance monitoring method
(described in Section V.X.3 of this
preamble) is used to estimate processbased emissions, but they are included
with combustion source emissions if
CEMS are used to measure emissions
from all stacks. Combustion source
emissions include CO2, CH4, and N2O
emissions from combustion of either
supplemental fuel alone (under the
mass balance option) or combustion of
both supplemental fuels and process offgas (under the CEMS option). This
difference in approach for emissions
from the combustion of off-gas is
necessary to avoid either double
counting or not counting these
emissions, particularly if off-gas and
supplemental fuel are mixed in a fuel
gas system.
CH4 emissions from onsite wastewater
treatment systems (if anaerobic) are
another possible source of GHG
emissions from the petrochemical
industry, but these emissions are
expected to be small because anaerobic
wastewater treatment is not common at
petrochemical facilities. CH4 emissions
from onsite wastewater treatment
systems would be estimated and
reported according to the proposed
procedures in proposed 40 CFR part 98,
subpart II.
The ratio of process-based emissions
to supplemental fuel combustion
emissions varies among the various
petrochemical processes. For example,
process-based emissions dominate for
acrylonitrile, ethylene, and ethylene
oxide processes. Both process-based and
supplemental fuel combustion
emissions are important for carbon
black and methanol processes.
Emissions from supplemental fuel
combustion predominate for ethylene
dichloride processes. Equipment leak
and wastewater emissions are both
estimated to be less than 1 percent of
the total emissions from petrochemical
production.
For further discussion see the
Petrochemical Production TSD (EPAHQ-OAR–2008–0508–024).
2. Selection of Reporting Threshold
We propose that every facility which
includes within its boundaries
methanol, acrylonitrile, ethylene,
ethylene oxide, ethylene dichloride, or
carbon black production be subject to
the requirements of this proposed rule.
In developing the proposed threshold
for petrochemical facilities, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Table X–1 of
this preamble illustrates the emissions
and number of facilities that would be
covered under the four threshold
options.
TABLE X–1. THRESHOLD ANALYSIS FOR PETROCHEMICAL PRODUCTION
Threshold level metric tons CO2e/yr
Total National
Emissions,
metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
54,830,000
54,830,000
54,830,000
54,830,000
The emissions presented in Table X–
1 of this preamble are the total
emissions associated solely with the
production of methanol, acrylonitrile,
ethylene, ethylene oxide, ethylene
dichloride, or carbon black, not the total
emissions from petrochemical facilities.
An estimate of the total emissions was
difficult to develop because many of
these facilities contain multiple source
categories. For example, some
petrochemical operations occur at
petroleum refineries. Other
petrochemical manufacturing facilities
produce chemicals such as ammonia or
hydrogen that are also subject to
reporting. In addition, numerous
chemical manufacturing facilities
produce other chemicals in addition to
one or more of the petrochemicals; these
facilities may have combustion sources
associated with these other chemical
manufacturing processes that are
separate from the combustion sources
for petrochemical processes.
Based on this analysis, 87 of the 88
petrochemical facilities have estimated
VerDate Nov<24>2008
17:34 Apr 09, 2009
Jkt 217001
Total number
of
facilities
Emissions covered
Metric tons
CO2e/yr
88
88
88
88
PO 00000
Frm 00091
Fmt 4701
Sfmt 4702
Percent
54,830,000
54,820,000
54,820,000
54,440,000
combustion and process-based GHG
emissions that exceed the 25,000 metric
tons CO2e/yr threshold, and 1 facility
has estimated GHG emissions less than
10,000 metric tons CO2e/yr. The facility
with estimated GHG emissions less than
10,000 metric tons CO2e/yr is a carbon
black facility. Considering that the
threshold analysis did not include all
types of emissions occurring at
petrochemical facilities, and the large
percentage of facilities that were above
the various thresholds even when these
emissions were excluded, EPA proposes
that all facilities producing at least one
of the petrochemicals report. This
would simplify the rule and likely
achieve the same result as having a
25,000 metric tons CO2e threshold.
For a full discussion of the threshold
analysis, please refer to the
Petrochemical Production TSD (EPA–
HQ–OAR–2008–0508–024). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
Facilities covered
100
99.98
99.98
99.7
Number of
facilities
Percent
88
87
87
84
100
98.9
98.9
95.5
3. Selection of Proposed Monitoring
Methods
We reviewed existing domestic and
international GHG monitoring
guidelines and protocols including the
2006 IPCC Guidelines and DOE 1605(b).
Protocols included methods for both
CO2 and CH4. From this review, we
developed the following three options
that share a number of features with the
three Tiers presented by IPCC:
Option 1. Apply default emission
factors based on the type of process and
site-specific activity data (e.g., measured
or estimated annual production rate).
This option is the same as the IPCC Tier
1 approach.
Option 2. Perform a carbon balance to
estimate CO2 emissions derived from
carbon in feedstocks. Inputs to the
carbon balance would be the flow and
carbon content of each feedstock, and
outputs would be the flow and carbon
content of each product/byproduct.
Organic liquid wastes that are collected
for shipment offsite would also be
considered an output in the carbon
E:\FR\FM\10APP2.SGM
10APP2
16538
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
balance. The difference between carbon
inputs and outputs is assumed to be CO2
emissions. This includes all
unconverted CH4 feedstock that is
emitted. In addition, all CO2 that is
recovered for sale or other use is
considered an emission for the purposes
of reporting for petrochemical
processes. However, the volume of CO2
would be accounted for separately using
the procedures in proposed 40 CFR part
98, subpart PP.
This option would require continuous
monitoring of liquid and gaseous flows
using flow meters, measurement of solid
feedstock and product flows using
scales or other weighing devices, and
determination of the carbon content of
each feedstock and product/byproduct
at least once per week. Supplemental
fuel is not considered to be a feedstock
because these fuels do not mix with
process fluids (except in the furnace of
a carbon black process) and would be
calculated consistent with the
monitoring methods in proposed 40
CFR part 98, subpart C.
In addition to using the carbon
balance to estimate process-based CO2
emissions, this option would require the
petrochemical facility owner to estimate
CO2, CH4, and N2O emissions from the
combustion of supplemental fuels using
the monitoring methods in proposed 40
CFR part 98, subpart C, and to estimate
CH4 emissions from onsite wastewater
treatment using the monitoring methods
in proposed 40 CFR part 98, subpart II.
Option 3. Direct and continuous
measurement of CO2 emissions from
each stack (process vent or combustion
source) using a CEMS for CO2
concentration and a stack gas
volumetric flow rate monitor.
This option also would require the
petrochemical facility owner to use
engineering analyses to estimate flow
and carbon content of gases discharged
to flares using the same procedures
described in Section V.Y.3 of this
preamble for petroleum refineries. Just
as at petroleum refineries, flares at
petrochemical facilities are used to
control a variety of emissions releases.
In addition, the flow and composition of
gas flared can change significantly.
Therefore, the Agency is proposing the
same methodology for petrochemical
flares as for flares at petroleum
refineries. Please refer to the petroleum
refineries section (Section V.Y.3 of this
preamble) for a discussion of the
rationale for these procedures.
We request comment on this approach
as well as on descriptions of differences
in operating conditions for flares at
petrochemical facilities and refineries
that would warrant specification of
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
different methodologies for estimating
emissions.
In addition to measuring CO2
emissions from process vents and
estimating CO2 emissions from flares,
this option would require the
petrochemical facility owner to
calculate CH4 and N2O emissions from
combustion sources using the
monitoring methods in proposed 40
CFR part 98, subpart C, and to calculate
CH4 emissions from onsite wastewater
treatment systems using the monitoring
methods in proposed 40 CFR part 98,
subpart II.
Proposed Options. Under this
proposed rule, if you operate and
maintain an existing CEMS that
measures total CO2 from process vents
and combustion sources, you would be
required to follow requirements of
proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from your
facility. In such a circumstance, you
also would be required to estimate CO2,
CH4 and N2O emissions from flares.
If you do not operate and maintain an
existing CEMS that measures total CO2
from process vents and combustion
sources for your facility, the proposed
rule permits the use of either Options 2
or 3 since they account for processbased emissions, combustion source
emissions, and wastewater treatment
system emissions. Process-based CO2
emissions are estimated using
procedures in proposed 40 CFR part 98,
subpart X; combustion emissions (CO2,
CH4, and N2O) and wastewater
emissions (CH4) are calculated using
methods in proposed 40 CFR part 98,
subparts C and II, respectively. As
discussed earlier, emissions from
combustion of process off-gas are
calculated with other process-based
emissions (only CO2 emissions) under
Option 2, but they are estimated using
methods for combustion sources under
Option 3 (CO2, CH4, and N2O
emissions). Option 2 offers greater
flexibility and a lower cost of
compliance than Option 3. However it
also has a higher measurement
uncertainty.
Option 3 is expected to have the
lowest measurement uncertainty.
However, using CEMS to monitor all
emissions at petrochemical facilities
would be relatively costly. For
emissions estimates produced using
Option 2, the uncertainty in these
estimates is expected to be relatively
low for most petrochemical processes.
For ethylene dichloride and ethylene
processes, the uncertainty of the carbon
balance approach may be higher since it
is influenced by the measurements of
inputs and outputs at the facility and
the percentage of carbon in the final
PO 00000
Frm 00092
Fmt 4701
Sfmt 4702
product. Uncertainty may be high where
the percentage of carbon in the product
is close to 100 percent (since subtracting
one large number for process output
from another large number for process
input results in relatively large
uncertainty in the difference, even if the
uncertainty in the two large numbers is
low). For the petrochemical processes,
we have decided that Option 2 is
reasonable for purposes of this proposed
rulemaking. However, direct
measurement may provide improved
emissions estimates.
Option 1 was not proposed because
the use of default values and lack of
direct measurement results in a high
level of uncertainty. These default
approaches would not provide sitespecific estimates of emissions that
would reflect differences in feedstocks,
operating conditions, catalyst
selectivity, thermal/energy efficiencies,
and other differences among plants. The
use of default values is more
appropriate for sector wide or national
total estimates from aggregated activity
data than for determining emissions
from a specific facility.
We request comment on how to
improve the emission estimates
developed using the carbon balance
approach (Option 2), including whether
the uncertainty in the estimated
emissions can be reduced (and if so, by
how much), the advantages,
disadvantages, types and frequency of
other measurements that could be
required, costs of alternatives, how the
uncertainty of alternatives is estimated,
and the QA procedures that should be
followed to assure accurate
measurement. For further discussion of
our assumptions on the uncertainty of
emissions estimates see the
Petrochemical Production TSD (EPA–
HQ–OAR–2008–0508–024).
Additional Issues and Requests for
Comments. EPA is interested in public
comment on four additional issues.
Fugitive emissions from
petrochemical production facilities have
been of environmental interest primarily
because of the VOC emissions. As noted
above, we have concluded that fugitive
CO2 and CH4 emissions contribute very
little to the overall GHG emissions from
the petrochemical production sector,
and non-CH4 hydrocarbon losses
assumed to be CO2 emissions overstate
the emissions only slightly.
Consequently, the Agency is not
proposing that fugitive emissions be
reported.
Second, Option 2 assumes all carbon
entering the process is released as CO2
and does not account for potential CH4
emissions, nor are N2O emissions
estimated in this approach. EPA
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
believes CH4 and N2O emissions are
small.
Third, EPA is aware that a limited
number of petrochemical facilities may
produce petrochemicals as well as one
or more other chemicals that are part of
another source category (e.g.production
of hydrogen for sale and the
petrochemical methanol from synthesis
gas created by steam reforming of CH4).
We consider these ‘‘integrated
processes’’ and request comment on
whether the procedures for the affected
source categories are clear and adequate
for addressing emissions from integrated
facilities.
Fourth, we are proposing several
methods for measuring the volume,
carbon content and composition of
feedstocks and products. There may be
additional peer-reviewed and published
measurement methodologies.
Public comment on each of these four
issues is welcomed. Where applicable,
supporting data and documentation on
how emissions should be included, and
if so, how these emissions can be
estimated, including the advantages,
disadvantages, types and frequency of
measurements that could be required,
costs of alternatives, how the
uncertainty of alternatives is estimated,
and the QA procedures that should be
followed to assure accurate
measurement.
4. Selection of Procedures for Estimating
Missing Data
The missing data procedures in
proposed 40 CFR part 98, subpart C for
combustion units are proposed for
facilities that use CEMS to estimate
emissions from both combustion
sources and process vents. Similarly, if
the mass balance option is used, the
same procedures that apply to missing
data for fuel measurements in proposed
40 CFR part 98, subpart C would also
apply to missing flow and carbon
content measurements of feedstocks and
products. Specifically, the substitute
data value for missing carbon content,
CO2 concentration, or stack gas moisture
content values would be the average of
the quality-assured values of the
parameter immediately before and
immediately after the missing data
period. The substitute data value for
missing feedstock, product, or stack gas
flows would be the best available
estimate based on all available process
data.
5. Selection of Data Reporting
Requirements
Where CEMS are used, the reporting
requirements specified in proposed 40
CFR part 98, subpart C would apply.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Where the carbon balance method is
used, we propose that the following
information be reported: Identification
of the process, annual CO2 emissions for
each type of petrochemical produced
and each process unit, the methods used
to determine flows and carbon contents,
the emissions calculation methodology,
quantity of feedstocks consumed,
quantity of each product and byproduct
produced, carbon contents of each
feedstock and product, information on
the number of actual versus substitute
data points, and the quantity of CO2
captured for use. In addition, owners
and operators would report information
related to all equipment calibrations;
measurements, calculations, and other
data; certifications; and any other QA
procedures used to assess the
uncertainty in emissions estimates.
The data to be reported under the
proposed rule form the basis of the
emissions calculations and are needed
for us to understand the emissions data
and verify reasonableness of the
reported emissions. The Agency
requests comment on the types of QA
procedures that are most commonly
conducted or recommended and the
information that would be most useful
in assessing uncertainty of the
emissions estimates.
6. Selection of Records That Must Be
Retained
Petrochemical production facilities
would be required to keep records of the
information specified in proposed 40
CFR 98.3, as applicable. Under the
carbon balance option, a facility also
would be required to keep records of all
feedstock and product flows and carbon
content determinations. If a
petrochemical production facility
complies with the CEMS option, the
additional records for CEMS listed in
proposed 40 CFR 98.37 would also be
required for all CEMS, including CEMS
on process stacks that are not associated
with combustion sources. These records
document values that are directly used
to calculate the emissions that are
reported and are necessary to enable
verification that the GHG emissions
monitoring and calculations were done
correctly.
Y. Petroleum Refineries
1. Definition of the Source Category
Petroleum refineries are facilities
engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, asphalt (bitumen),
or other products through distillation of
petroleum or through redistillation,
cracking, or reforming of unfinished
petroleum derivatives. There are 150
PO 00000
Frm 00093
Fmt 4701
Sfmt 4702
16539
operating petroleum refineries in the
U.S. and its territories. Emissions from
petroleum refineries account for
approximately 205 million metric tons
CO2e, representing approximately 3
percent of the U.S. nationwide GHG
emissions. Most of these emissions are
CO2 emissions from fossil fuel
combustion. While the U.S. GHG
Inventory does not separately report
onsite fuel consumption at petroleum
refineries, it estimates that
approximately 0.6 million metric tons
CO2e of CH4 are emitted as fugitives per
year from petroleum refineries in the
U.S. Most CO2 emissions at a refinery
are combustion-related, accounting for
approximately 67 percent of CO2
emissions at a refinery.
The combustion of catalyst coke in
catalyst cracking units is also a
significant contributor to the CO2
emissions (approximately 25 percent)
from petroleum refineries. Combustion
of excess or waste fuel gas in flares
contributes approximately 2 percent of
the refinery’s overall CO2 emissions. As
such, the Agency proposes that the
emissions from these sources must be
reported.
Process emissions of CO2 also occur
from the sulfur recovery plant, because
the amine solutions used to remove
hydrogen sulfide (H2S) from the
refinery’s fuel gas adsorb CO2. The
stripped sour gas from the amine
adsorbers is fed to the sulfur recovery
plant; the CO2 contained in this stream
is subsequently released to the
atmosphere. Most refineries have on-site
sulfur recovery plants; however, a few
refineries send their sour gas to
neighboring sulfur recovery or sulfuric
acid production facilities. The quantity
of CO2 contained in the sour gas sent for
off-site sulfur recovery operations is
considered an emission under this
regulation.
There are a variety of GHG emission
sources at the refinery, which include:
Asphalt blowing, delayed coking unit
depressurization and coke cutting, coke
calcining, blowdown systems, process
vents, process equipment leaks, storage
tanks, loading operations, land disposal,
wastewater treatment, and waste
disposal. To fully account for the
refinery’s GHG emissions, we propose
that the emissions from these sources
must also be reported.
Based on the emission sources at
petroleum refineries, GHGs to report
under proposed 40 CFR part 98, subpart
Y are limited to CO2, CH4, and N2O.
Table Y–1 of this preamble summarizes
the GHGs to be reported by emission
source at the refinery.
E:\FR\FM\10APP2.SGM
10APP2
16540
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE Y–1. GHGS TO REPORT UNDER 40 CFR PART 98, SUBPART Y
Subpart of proposed 40 CFR part 98
where emissions reporting methodologies
addressed
Emission source
GHGs to report
Stationary combustion sources ........................................
Coke burn-off emissions from catalytic cracking units,
fluid coking units, catalytic reforming units, and coke
calcining units.
Flares ................................................................................
Hydrogen plant vent .........................................................
Petrochemical processes ..................................................
Sulfur recovery plant, on-site and off-site .........................
On-site wastewater treatment system ..............................
On-site land disposal unit .................................................
Fugitive Emissions ............................................................
Delayed coking units ........................................................
CO2, CH4, and N2O ..................................
CO2, CH4, and N2O ..................................
Subpart C.
Subpart Y.
CO2, CH4, and N2O ..................................
CO2 and CH4 ............................................
CO2 and CH4 ............................................
CO2 ...........................................................
CO2 and CH4 ............................................
CH4 ...........................................................
CO2, CH4, and N2O ..................................
CH4 ...........................................................
Subpart
Subpart
Subpart
Subpart
Subpart
Subpart
Subpart
Subpart
2. Selection of Reporting Threshold
refineries. Table Y–2 of this preamble
illustrates the emissions and number of
Four options were considered as
reporting thresholds for petroleum
Y.
P.
X.
Y.
II.
HH.
Y.
Y.
facilities that would be covered under
the four options.
TABLE Y–2. THRESHOLD ANALYSIS FOR PETROLEUM REFINING
Emissions covered
Option/threshold level
Million metric tons
CO2e/year
1,000 metric tons CO2e ...............................................................................................
10,000 metric tons CO2e .............................................................................................
25,000 metric tons CO2e .............................................................................................
100,000 metric tons CO2e ...........................................................................................
We are proposing that all petroleum
refineries should report. This approach
would ensure full reporting of
emissions, affect an insignificant
number of additional sources compared
to the 25,000 metric tons CO2e
threshold, and would add minimal
additional burden to the reporting
facilities. All U.S. refineries must report
their fuel consumption to the EIA, so
there is limited additional burden to
estimate their GHG emissions.
Furthermore, due to the importance of
the petroleum refining industry to our
nation’s energy needs as well as the
overall U.S. GHG inventory, it is
important to obtain the best information
available for this source category. We
estimate that 4 refineries did not exceed
a reporting threshold of 25,000 metric
tons CO2e in 2006 and invite public
comment on this matter.
For a full discussion of the threshold
analysis, please refer to the Petroleum
Refineries TSD (EPA–HQ–OAR–2008–
0508–025). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
204.75
204.74
204.69
203.75
3. Selection of Proposed Monitoring
Methods
We considered monitoring methods
that are used or recommended for use
from several sources including
international groups, U.S. agencies,
State agencies, and petroleum refinery
trade organizations. For most emission
sources, three general levels of
monitoring options were evaluated: (1)
Use of engineering calculations and/or
default factors; (2) monitoring of process
parameters (such as fuel consumption
quantities and carbon content); and (3)
direct emission measurement using
CEMS for all emissions sources at a
refinery.
Under this proposed rule, if you are
required to use an existing CEMS to
meet the requirements outlined in
proposed 40 CFR part 98, subpart C, you
would be required to use CEMS to
estimate CO2 emissions. Where the
CEMS capture all combustion- and
process-related CO2 emissions you
would be required to follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart C to estimate
CO2 emissions. Also, refer to proposed
PO 00000
Frm 00094
Fmt 4701
Sfmt 4702
Percent
100
99.995
99.97
99.51
Facilities covered
Number
150
149
146
128
Percent
100
99.3
97.3
85.3
40 CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions.
For facilities that do not currently
have CEMS that meet the requirements
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS would
not adequately account for process
emissions, the proposed monitoring
method is Option 2. Option 2 accounts
for process-related CO2 emissions.
Simplified methods for estimating
fugitive CH4 emissions are provided
below. Refer to proposed 40 CFR part
98, subpart C specifically for procedures
to estimate combustion-related CH4 and
N2O emissions.
You would be required to follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of proposed
40 CFR part 98, subpart HH to estimate
emissions from landfills, proposed 40
CFR part 98, subpart II to estimate
emissions from wastewater and
proposed 40 CFR part 98, subpart P to
estimate emissions from hydrogen
production (non-merchant hydrogen
plants only).
Specifically, for fluid catalytic
cracking units and fluid coking units
that already have CEMS in place, we
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
propose to require refineries to report
CO2 emissions using these CEMS. For
the sources that contribute significantly
to the overall GHG emissions from the
refinery, as defined below, we propose
monitoring of process parameters
(Option 2). The Agency requests
comment on the feasibility of allowing
smaller emission sources at the refinery
to employ less certain (Option 1)
methods as a way to reduce the costs
and burden of measurement and
verification under this proposed rule.
Providing this flexibility would result in
lower costs but greater uncertainty
around some portions of a facility’s
emissions estimates.
The selected monitoring methods for
this proposed rule generally follow
those used in other reporting rules as
well as those recommended in the
American Petroleum Institute’s
Compendium of Greenhouse Gas
Emissions Estimation Methodologies for
the Oil and Gas Industry (hereafter
referred to as ‘‘the API Compendium’’).
More detail regarding the selection of
the proposed monitoring options for
specific emission sources follows.
Coke burn-off. The proposed methods
for estimating GHG emissions from coke
burn-off in the catalytic cracking unit,
fluid coking unit, and catalytic
reforming unit generally follow the
methods presented in the API
Compendium for coke burn-off. Fluid
catalytic cracking units and fluid coking
units are large CO2 emission sources,
accounting for over 25 percent of the
GHG emissions from petroleum
refineries. Most of these units are
expected to monitor gas composition for
process control or for compliance with
applicable monitoring provisions under
40 CFR part 60, subparts J and Ja and
under 40 CFR part 63, subpart UUU.
Given the magnitude of the GHG
emissions from catalytic cracking units
and fluid coking units, direct
monitoring for CO2 emissions (i.e.,
continuous monitoring of CO2
concentration and flow rate at the final
exhaust stack) is believed to provide
greater certainty in the emission
estimate. However, compositional
analysis monitoring in the regenerator
or fluid coking burner exhaust vent
prior to the combustion of other fuels
(such as auxiliary fuel fired to a CO
boiler) may be used when direct
monitoring for CO2 emissions is not
already employed. An equation is
provided in the rule for calculating the
vent stream flow rate based on the
compositional analysis data rather than
requiring a continuous flow monitor;
this equation is allowed in other
petroleum refinery rules (40 CFR part
60, subparts J and Ja; 40 CFR part 63,
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
subpart UUU) as an alternative to
continuous flow monitoring.
An engineering approach for
estimating coke burn-off rates and
calculating CO2 emissions using default
carbon content for petroleum coke was
considered. However, as most catalytic
cracking units already must have the
compositional monitors in-place due to
other petroleum refinery rules and
because catalytic cracking unit coke
burn-off is a significant contributor to
the overall GHG emissions from
petroleum refineries, we are not
proposing an engineering calculation for
the catalytic cracking units. However,
comment is requested on the
engineering methods available to
estimate coke burn-off rates, the
uncertainty of the methods, and the
measurements or parameters and
enhanced QA that can be used to verify
the engineering emission estimates and
their certainty.
The amount of coke burned in
catalytic reforming units is estimated to
be about 1 percent of the amount of coke
burned in catalytic cracking units or
fluid coking units; therefore, a
simplified method is provided for
estimating coke burn-off emissions for
catalytic reforming units that do not
monitor gas composition in the coke
burn-off exhaust vent.
Flares. Specific monitoring provisions
are provided for flares. As the
composition of gas flared can change
significantly, we considered proposing
continuous flow and composition
monitors (or heating value monitors) on
all flares. For example, in California,
both the South Coast and Bay Area Air
Quality Management Districts require
these monitors for refineries located in
their districts. However, a significant
fraction of flares is not expected to have
these monitoring systems installed.
Further, since flares are projected to
contribute only about 2 percent of a
typical refinery’s CO2 emissions, it
would be costly to improve the
monitoring systems for flare emission
estimates. The use of the default CO2
emission factor for refinery fuel gas was
also considered. The default emission
factor is expected to be reasonable
during normal refinery operations, but
is highly uncertain during periods of
start-up, shutdown, or malfunction.
Consequently, a hybrid method is
proposed that allows the use of a default
CO2 emission factor for refinery fuel gas
during periods of normal refinery
operations and specific engineering
analysis of GHG emissions during
periods of high flare volumes associated
with start-up, shutdown, or
malfunction. As with stationary
combustion sources, default emission
PO 00000
Frm 00095
Fmt 4701
Sfmt 4702
16541
factors for refinery gas are proposed to
calculate CH4 and N2O emissions from
flares.
Sulfur Recovery Plants. For sulfur
recovery plants at the petroleum
refinery and for instances where sour
gas is sent off-site for sulfur recovery,
direct carbon content measurement in
the sour gas feed to the sulfur recovery
plant is the preferred monitoring
approach. However, a site-specific or
default carbon content method is also
provided. It is anticipated that
monitoring systems would be in place at
most refineries, as monitoring of the
sour gas feed is important in the
operation of the sulfur recovery plant.
The monitoring data for carbon content
and flow rate must be used if they are
available. The alternative default carbon
content method is provided because the
emissions from this source are relatively
small, 1 to 2 percent for a given facility,
and because only small, non-Claus
sulfur recovery plants are not expected
to monitor the flow and composition of
the sour gas. We are proposing that only
CO2 emissions would need to be
reported for the sulfur recovery plant
process-related emissions.
Coke Calcining. For coke calcining
units at the petroleum refinery, direct
CO2 measurement is the preferred
monitoring approach. However, a
carbon balance approach is proposed
similar to the approach included in The
Aluminum Sector Greenhouse Gas
Protocol 83 for units that do not have
CEMS. This is because coke calcining is
a small source of GHG emissions, less
than 1 percent for a given facility. CH4
and N2O emissions are calculated from
the coke calcining CO2 process
emissions using the default emission
factors for petroleum coke combustion
(the same equations as proposed for
calculating CH4 and N2O emissions from
coke burn-off).
Process Vents not Otherwise
Specified. For process vents other than
those discussed elsewhere in this
section of the preamble, either process
knowledge or measurement data can be
used to calculate the GHG emissions.
Due to other regulations affecting
petroleum refineries, only a few, small
process vents are expected to be present
at most refineries. As such, these small
vents do not warrant requiring the use
of CEMS to quantify emissions. Process
vent emissions are expected to be
predominately CO2 or CH4, but N2O
83 International Aluminum Institute. 2006. The
Aluminum Sector Greenhouse Gas Protocol
(Addendum to the WRI/WBCSD Greenhouse Gas
Protocol). pp. 31–32. Available at: https://
www.world-aluminium.org/Downloads/
Publications/Download.
E:\FR\FM\10APP2.SGM
10APP2
16542
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
emissions, if present, are also to be
reported.
Other Sources. Due to the small (less
than 1 percent) contribution of other
emissions sources at the refinery that
make up the total GHG emissions from
the facility, very simple methods are
proposed to estimate these other
emissions sources. Alternative methods
are provided so that facilities can
provide more detailed estimates if
desired. For example, a refinery may
estimate CH4 emissions from individual
tanks using EPA’s TANKS model, if
desired, or apply a default emission
factor to the facility’s overall
throughput. Simple emission factor
approaches are provided for asphalt
blowing, delayed coking unit
depressurization and coke cutting,
blowdown systems, process equipment
leaks, storage tanks, and loading
operations.
For further discussion of this source
category and monitoring of its
emissions, see the Petroleum Refineries
TSD (EPA–HQ–OAR–2008–0508–025).
Combustion Sources. For other sources,
we propose to report the identification
of the source, throughput of the source
(if applicable), the calculation
methodology used, the total GHG
emissions for the source, and the
quantity of CO2 captured for use and the
end use, if known. A list of the specific
GHG emissions reportable for each
emission source is provided in Table Y–
1 of this preamble.
The reporting requirements consist of
actual GHG emission values as well as
values that are directly used to calculate
the emissions and are necessary in order
to verify that the GHG emissions
monitoring and calculations were done
correctly. As there are high
uncertainties associated with many of
the ancillary emission sources at the
refinery, separate reporting of the
emissions for these separate sources is
needed to fully understand the
importance and variability of these
ancillary emission sources. A complete
list of information to report is contained
in proposed 40 CFR 98.256.
4. Selection of Procedures for Estimating
Missing Data
In those cases where you use direct
measurement by a CO2 CEMS, the
missing data procedures would be the
same as the Tier 4 requirements
described for general stationary fuel
combustion sources in proposed 40 CFR
part 98, subpart C. Missing data
procedures are also specified, consistent
with proposed 40 CFR part 98, subpart
C, for heat content, carbon content, fuel
molecular weight, gas and liquid fuel
flow rates, stack gas flow rates, and
compositional analysis data (CO2, CO,
O2, CH4, N2O, and stack gas moisture
content, as applicable). Generally, the
average of the data measurements before
and after the missing data period would
be used to calculate the emissions
during the missing data period.
6. Selection of Records That Must Be
Retained
5. Selection of Data Reporting
Requirements
The reporting requirements for
combustion sources other than those
associated with coke burn-off directly
refer to those in proposed 40 CFR part
98, subpart C, General Stationary Fuel
The recordkeeping requirements in
the general provisions of proposed 40
CFR part 98 apply for petroleum
refineries. Specifically, refineries would
be required to keep all records specified
in proposed 40 CFR part 98, subpart A
and summarized in Section III.E of this
preamble. In addition, records of the
data required to be monitored and
reported under proposed 40 CFR part
98, subpart Y would be retained. If
CEMS are used to quantify the GHG
emissions, you would be required to
keep additional records specified in
proposed 40 CFR part 98, subparts A
and Y. These records consist of values
that are directly used to calculate the
emissions and are necessary to enable
verification that the GHG emissions
monitoring and calculations were done
correctly.
Z. Phosphoric Acid Production
1. Definition of the Source Category
Phosphoric acid is a common
industrial product used to manufacture
phosphate fertilizers. Phosphoric acid is
a product of the reaction between
phosphate rock and, typically, sulfuric
acid (H2SO4). A byproduct called
calcium sulfate (CaSO4), or gypsum, is
formed when calcium from the
phosphate rock reacts with sulfate. Most
companies in the U.S. use a dihydrate
process in which two molecules of
water (H2O) are produced per molecule
of gypsum (CaSO4 · 2 H2O or calcium
sulfate dihydrate).
Additionally, a second reaction
occurs in which the limestone (CaCO3)
present in the phosphate rock reacts
with sulfuric acid (H2SO4) releasing
CO2. The amount of carbon in the
phosphate rock feedstock varies
depending on the region in which it was
mined.
National emissions from phosphoric
acid production facilities were
estimated to be 3.8 million metric tons
CO2e in 2006. These emissions include
both process-related emissions (CO2)
and on-site stationary combustion
emissions (CO2, CH4 and N2O) from 14
phosphoric acid production facilities
across the U.S. Process-related
emissions account for 1.2 million metric
tons CO2e, or 30 percent of the total,
while on-site stationary combustion
emissions account for the remaining 2.7
million metric tons CO2e emissions.
The phosphoric acid production
industry has many production sites that
are integrated with mines; notably, three
facilities import phosphate rock from
Morocco.
For additional background
information on phosphoric acid
production, please refer to the
Phosphoric Acid Production TSD (EPA–
HQ–OAR–2008–0508–026).
2. Selection of Reporting Threshold
In developing the threshold for
phosphoric acid production, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e per year.
Table Z–1 of this preamble illustrates
the emissions and number of facilities
would not be impacted under these
various applicability thresholds.
TABLE Z–1. THRESHOLD ANALYSIS FOR PHOSPHORIC ACID PRODUCTION
Threshold level metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total national
emissions
metric tons
CO2e/yr
Emissions covered
Total number
of facilities
3,838,036
3,838,036
3,838,036
3,838,036
PO 00000
Frm 00096
Metric tons
CO2e/yr
14
14
14
14
Fmt 4701
Sfmt 4702
Facilities covered
Percent
3,838,036
3,838,036
3,838,036
3,838,036
E:\FR\FM\10APP2.SGM
100
100
100
100
10APP2
Number
Percent
14
14
14
14
100
100
100
100
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
There is no proposed threshold for
reporting emissions from phosphoric
acid production. Even at a 100,000
metric tons CO2e threshold, all
emissions would be covered, and all
facilities would be required to report.
Having no threshold would simplify the
rule and avoid any burden for
unnecessary calculations to determine if
a threshold is exceeded. Therefore, we
propose that all phosphoric acid
production facilities report.
For a full discussion of the threshold
analysis, please refer to the Phosphoric
Acid Production TSD (EPA–HQ–OAR–
2008–0508–026). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
The methodology for estimating
process-related emissions from
phosphoric acid production is based on
the U.S. GHG Inventory method
discussed further in the Phosphoric
Acid Production TSD (EPA–HQ–OAR–
2008–0508–026). Most domestic and
international GHG monitoring
guidelines and protocols, such as the
2006 IPCC Guidelines do not provide
estimation methodologies for processrelated emissions from phosphoric acid
production.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS to meet the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
emissions you would be required to
follow the requirements of proposed 40
CFR part 98, subpart C to estimate CO2
emissions. Also, refer to proposed 40
CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions.
If you do not have CEMS that meet
the conditions outlined in proposed 40
CFR part 98, subpart C, we propose that
facilities estimate process-related CO2
emissions by determining the amount of
inorganic carbon input to the process
through measurement of the inorganic
carbon content of the phosphate rock
and multiplying by the amount (mass)
of phosphate rock used to manufacture
phosphoric acid. Refer to proposed 40
CFR part 98, subpart C specifically for
procedures to estimate combustionrelated CH4 and N2O emissions.
In order to assess the composition of
the inorganic carbon input, we assume
that vertically integrated phosphoric
acid production facilities already have
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
the necessary equipment on-site for
conducting chemical analyses of the
inorganic carbon weight fraction of the
phosphate rock and that this analysis is
conducted on a routine basis at
facilities. Facilities importing rock from
Morocco would send rock samples offsite for composition analysis. The
inorganic carbon content would be
determined on a per-batch basis.
Multiplying the inorganic carbon
content by the amount (mass) of
phosphate rock processed and by the
molecular weight ratio of CO2 to
inorganic carbon (44/12) yields the
estimate of CO2 emissions. This
calculated value should be recorded
monthly based on the most recent batch
of phosphate rock received. The
monthly emissions for each phosphoric
acid process line are then summed to
obtain the annual emissions to be
included in the report.
The various approaches to monitoring
GHG emissions are elaborated in the
Phosphoric Acid Production TSD (EPA–
HQ–OAR–2008–0508–026).
4. Selection of Procedures for Estimating
Missing Data
The likelihood for missing data is
low, as businesses closely track their
purchase of production inputs. The
Phosphoric Acid NSPS (40 CFR part 60,
subpart T) requires continuous
monitoring of phosphorus-bearing
material (rock) to process. This
requirement, along with the fact that the
facility would closely monitor
production inputs, results in low
likelihood of missing data. Additionally,
only 3 facilities within the U.S. are not
vertically integrated with mines and
may lack the necessary equipment to
measure the inorganic carbon weight
percent of the rock. Therefore, no
missing data procedures would apply to
CO2 emission estimates from wetprocess phosphoric acid production
facilities because inorganic carbon test
results and monthly production data
should be readily available. Therefore,
100 percent data availability would be
required.
5. Selection of Data Reporting
Requirements
We propose that facilities report total
annual CO2 emissions from each wetprocess phosphoric acid productionline,
as well as any stationary fuel
combustion emissions. In addition, we
propose that facilities report their
annual average phosphate rock
consumption, percent of inorganic
carbon in the phosphate rock consumed,
annual phosphoric acid production and
concentration and annual phosphoric
acid capacity. These data are used to
PO 00000
Frm 00097
Fmt 4701
Sfmt 4702
16543
calculate emissions. They are needed for
us to understand the emissions data and
assess the reasonableness of the
reported emissions. A full list of data to
be reported is included in proposed40
CFR part 98, subparts A and Z.
6. Selection of Records That Must Be
Retained
In addition to the data reported, we
propose that facilities maintain records
of inorganic carbon content chemical
analyses on each batch of phosphate
rock and monthly phosphate rock
consumption (by the origin of the
phosphate rock). These records provide
values that are directly used to calculate
the emissions that are reported and are
necessary to allow determination of
whether the GHG emissions monitoring
and calculations were done correctly.
A full list of records that must be
retained on-site is included in proposed
40 CFR part 98, subparts A and Z.
AA. Pulp and Paper Manufacturing
1. Definition of the Source Category
The pulp and paper source category
consists of over 5,000 facilities engaged
in the manufacture of pulp, paper, and/
or paperboard products primarily from
wood material. However, less than 10
percent of these facilities are expected
to meet the applicability thresholds of
this proposed rule. The approximately
425 facilities that the proposed rule is
expected to cover mainly consist of
facilities that include pulp, paper and
paperboard facilities that operate fossil
fuel-fired boilers in addition to
operating other sources of GHG
emissions (e.g., biomass boilers, lime
kilns, onsite landfills, and onsite
wastewater treatment systems).84
Greenhouse gas emissions from the
pulp and paper source category are
predominantly CO2 with smaller
amounts of CH4 and N2O. The pulp and
paper GHG emissions include biomassderived CO2 emissions from using the
biomass generated on site as a
byproduct (e.g., bark, other wood waste,
spent pulping liquor). For example,
kraft pulp and paper facilities are likely
to generate byproduct biomass fuel
while the majority of the onsite energy
for non-integrated paper facilities and
100 percent recycled paper facilities is
likely to be generated from fossil fuelfired boilers because these facilities do
not generate byproduct biomass fuel.
Table AA–1 of this preamble lists the
GHG emission sources that may be
84 This estimate is based on a survey of pulp and
paper mills conducted by the National Council for
Air and Stream Improvement that operated
stationary combustion units in 2005. See: National
Council of Air and Stream Improvement Special
Report No. 06–07. December 2006.
E:\FR\FM\10APP2.SGM
10APP2
16544
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
found at pulp and paper facilities, the
type of GHG emissions that are required
to be reported, and where the reporting
methodologies are found in proposed 40
CFR part 98.
TABLE AA–1. GHG EMISSION SOURCES AT PULP, PAPER, AND PAPERBOARD FACILITIES
Emissions source
GHG emissions
General Stationary Fuel Combustion ......................................................................
CO2, CH4, N2O,
biomass-CO2.
CO2 ........................
CH4 ........................
CH4 ........................
Makeup Chemicals (CaCO3, Na2CO3) ....................................................................
Onsite industrial landfills .........................................................................................
Wastewater treatment .............................................................................................
The method presented in this section
of the preamble is to account for the use
of make-up chemicals (e.g., sodium
sulfate, calcium carbonate, sodium
carbonate) that are added into the
recovery loop (e.g., with the spent
pulping liquor) at a pulp and paper
facility to replace the small amounts of
sodium and calcium that are lost from
the recovery cycle at kraft and soda
facilities. When carbonates are added,
the carbon in these make-up chemicals,
which can be derived from biomass or
mineral sources, is emitted as CO2 from
recovery furnaces and lime kilns. In
cases where the carbon is mineralbased, emissions of CO2 would
contribute to GHG emissions.
Affected facilities would be required
to report total GHG emissions on a
facility-wide basis for all source
categories for which methods are
presented in proposed 40 CFR part 98.
2. Selection of Reporting Threshold
For the pulp and paper source
category, the Agency proposes a GHG
reporting threshold of 25,000 metric
tons CO2e, which would include the
vast majority of GHG emissions from the
pulp and paper source category.85
As described in proposed 40 CFR part
98, subpart A, biomass-derived CO2
emissions should not be taken into
consideration when determining
whether a facility exceeds the 25,000
metric tons CO2e threshold.
In evaluating potential thresholds for
the pulp and paper source category, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e, and
Subpart of 40 CFR part 98 where
emissions reporting methodologies
addressed
Subpart C.
Subpart AA.
Subpart HH.
Subpart II.
100,000 metric tons CO2e. The threshold
analysis focuses on the most significant
sources of GHG emissions in the pulp
and paper industry, specifically
facilities that make pulp, paper and
paperboard and operate fossil fuel-fired
boilers. Therefore, of the 5,000 facilities
associated with this industry, only 425
were included in the analysis. Table
AA–2 of this preamble illustrates that
the various thresholds do not have a
significant effect on the amount of
emissions that would be covered.
For a full discussion of the threshold
analysis, please refer to the Pulp and
Paper Manufacturing TSD (EPA–HQ–
OAR–2008–0508–027). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
TABLE AA–2. REPORTING THRESHOLDS FOR PULP AND PAPER SECTOR
Total national
emissions
(metric tons
CO2e)
Threshold level metric tons CO2e
1,000 ........................................................................
10,000 ......................................................................
25,000 ......................................................................
100,000 ....................................................................
57,700,000
57,700,000
57,700,000
57,700,000
Total
number of
U.S.
facilities
425
425
425
425
Emissions covered
Metric tons
CO2e/yr
57,700,000
57,700,000
57,700,000
57,527,000
Refer to proposed 40 CFR part 98,
subparts C, HH, and II for monitoring
methods for general stationary fuel
combustion sources, landfills, and
industrial wastewater treatment
occurring on-site at pulp and paper
facilities. This section of the preamble
includes monitoring methods for
calculating and reporting makeup
chemicals at pulp and paper facilities.
Additional details on the proposed
monitoring options are elaborated in the
Pulp and Paper Manufacturing TSD
(EPA–HQ–OAR–2008–0508–027).
The proposed method for monitoring
emissions from carbonate-based makeup chemicals used at chemical pulp
facilities includes calculating the CO2
emissions from the added CaCO3 and
Na2CO3 using emissions factors
provided in the rule. The calculation
assumes that the carbonate based makeup chemicals added (e.g., limestone) are
pure carbonate minerals, and that all of
the carbon is released to the
atmosphere. If you believe that these
assumptions do not represent
85 The American Forest and Paper Association
estimates that the 25,000 metric tons CO2e would
Facilities covered
Percent
100
100
100
99.7
a. Calculation Methods Selected
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00098
Fmt 4701
Sfmt 4702
425
425
425
410
Percent
100
100
100
96
circumstances at your facility, you may
send samples of each carbonate
consumed to an off-site laboratory for a
chemical analysis of the carbonate
weight fraction on a quarterly basis,
consistent with proposed 40 CFR part
98, subpart U. You could also determine
the calcination fraction for each of the
carbonate-based minerals consumed,
using an appropriate test method. Makeup chemical usage would be required to
be determined by direct measurement of
the quantity of chemical added. The
chemical usage should be quantified
separately for each chemical used, and
include approximately 99 percent of GHG
emissions from the pulp and paper source category.
3. Selection of Proposed Monitoring
Methods
Number
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the estimate should be in terms of pure
CaCO3 and/or Na2CO3. We have
proposed direct measurement for
quantifying the amount of makeup
chemicals, consistent with the
estimation of emissions from carbonates
in the rest of proposed 40 CFR part 98.
For the monitoring methods detailed
in proposed 40 CFR part 98, subpart C
for general stationary combustion, it
should be noted that biogenic CO2
emissions from the combustion of
biomass fuels are to be reported
separately. Furthermore, in referring to
proposed 40 CFR part 98, subpart C on
general stationary combustion, we
would expand upon particular details
unique to a pulp and paper facility,
because of the unique uses of biomass
fuels. For the pulp and paper source
category, biomass fuels include, but may
not be limited to: (1) Unadulterated
wood, wood residue, and wood
products (e.g., trees, tree stumps, tree
limbs, bark, lumber, sawdust,
sanderdust, chips, scraps, slabs,
millings, wood shavings, paper pellets,
and corrugated container rejects); (2)
pulp and paper facility wastewater
treatment system sludge; (3) vegetative
agricultural and silvicultural materials,
such as logging residues and bagasse;
and (4) liquid biomass-based fuels such
as biomass-based turpentine and tall oil.
Such fuels could be combusted at a pulp
and paper facility in stationary
combustion units including, but not
limited to, boilers, chemical recovery
furnaces, and lime kilns. Proposed 40
CFR part 98, subpart C provides details
on the separate reporting of the biogenic
CO2 emissions from these biomassbased fuels, and the calculation
methodologies for any fossil fuels
combusted, including when co-fired
with biomass.
Where biomass is co-fired with fossil
fuel, the appropriate methodology as
required in proposed 40 CFR part 98,
subpart C should be used. However, to
minimize the burden on owners and
operators of biomass-fired stationary
combustion equipment, this proposed
rule allows biogenic CO2 emissions to
be calculated using default emission
factors and default HHVs used in the
Tier 1 methodology.
Where available, like in the case of
spent pulping liquor, we would require
direct analysis of the HHV, rather than
allowing the use of a default HHV. This
is due to the variability in the HHV of
spent pulping liquor across the industry
and because a number of facilities
already perform this analysis on a
monthly basis. However, the proposed
rule does not propose the use of default
GHG emissions factors for spent pulping
liquor at kraft pulp facilities. For sulfite
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
and semichemical chemical recovery
combustion units, we propose that
sources conduct a monthly carbon
content analysis of the spent pulping
liquor for use in calculating the biomass
CO2 emissions because no default
emissions factors are known to exist for
these sources.
We are requesting comment on the
appropriateness of today’s proposed
requirements for monthly measurement
of spent pulping liquor HHV (kraft
recovery furnaces) and monthly carbon
content analysis of spent pulping liquor
(sulfite and semichemical chemical
recovery combustion units). We
welcome data and documentation
regarding the use of potential alternative
methods or default emissions factors.
In addition, regarding the monitoring
methods in proposed 40 CFR part 98,
subpart C for general stationary
combustion, the majority of biomass
fuel consumed at pulp and paper mills
is generated onsite, and thus, as
required in proposed 40 CFR part 98,
subpart C, the use of purchasing records
might not be an option for these mills.
As such, we are taking comment on
appropriate details to be reported on
volume or mass of biogenic fuel fed into
stationary combustion units.
b. Other Monitoring Methods
Considered
Lime kilns and calciners used in the
pulp and paper source category are
unique and are defined separately from
lime kilns used in the commercial lime
manufacturing industry because the
source of the carbon in the calcium
carbonate entering the kraft lime kiln is
biogenic. The CO2 emitted from lime
kilns at kraft pulp facilities originates
from two sources: (1) Fossil fuels
burned in the kiln, and (2) conversion
of calcium carbonate (or ‘‘lime mud’’) to
calcium oxide during the chemical
recovery process.
Although CO2 is also liberated from
the CaCO3 burned in the kiln or
calciner, the carbon released from
CaCO3 is biomass carbon that originates
in wood and is included in the biogenic
CO2 emissions factor for the recovery
furnace as discussed previously. The
reporting of the CO2 emissions
associated with the conversion of the
calcium carbonate to lime as biogenic
CO2 is consistent with the reporting
requirements in other accepted
protocols such as DOE 1605(b) and
guidance developed for the
International Council of the Forest and
Paper Association. This approach has
been widely accepted by the domestic
and international community, including
WRI/WBCSD. The IPCC does not
directly state how CO2 emissions from
PO 00000
Frm 00099
Fmt 4701
Sfmt 4702
16545
kraft facility lime kilns should be
addressed. As biogenic process CO2
emissions (i.e., any biogenic CO2
emissions not associated with the
combustion of biomass fuels) are not
being reported in this rule, we are taking
comment on whether an exception
should be made for this unique case,
consistent with other existing protocols
as noted above.
4. Selection of Procedures for Estimating
Missing Data
Refer to proposed 40 CFR part 98,
subparts C, HH, and II for procedures for
estimating missing data for stationary
combustion, landfills, and industrial
wastewater treatment occurring on-site
at pulp and paper facilities.
Proposed 40 CFR part 98, subpart AA
contains missing data procedures for
process emissions. There are no missing
data procedures for measurements of
heat content and carbon content of
spent pulping liquor. A re-test must be
performed if the data from any monthly
measurements are determined to be
invalid. For missing spent pulping
liquor flow rates, the lesser value of
either the maximum fuel flow rate for
the combustion unit, or the maximum
flow rate that the fuel flowmeter can
measure would be used. For the use of
makeup chemicals (carbonates), the
substitute data value shall be the best
available estimate of makeup chemical
consumption, based on available data
(e.g., past accounting records,
production rates).
5. Selection of Data Reporting
Requirements
Refer to proposed 40 CFR part 98,
subparts C, HH, and II for reporting
requirements for stationary combustion,
landfills, and industrial wastewater
treatment occurring on-site at pulp and
paper facilities.
We propose that some additional data
be reported to assist in verification of
estimates, checks for reasonableness,
and other data quality considerations,
including: Annual emission estimates
presented by calendar quarters
(including biogenic CO2), total
consumption of all biomass fuels and
spent pulping liquor by calendar
quarters, and total annual quantities of
makeup chemicals (carbonates) used
and by carbonate.
6. Selection of Records That Must Be
Retained
Refer to proposed 40 CFR part 98,
subparts C, HH, and II for recordkeeping
requirements for stationary combustion,
landfills, and industrial wastewater
treatment occurring on-site at pulp and
paper facilities.
E:\FR\FM\10APP2.SGM
10APP2
16546
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
In addition to the recordkeeping
requirements for general stationary fuel
combustion sources in proposed 40 CFR
part 98, subpart C, we propose that the
following additional records be kept to
assist in QA/QC, including: GHG
emission estimates by calendar quarter
by unit and facility, monthly
consumption total of all biomass fuels
and spent pulping liquor by unit and
facility, monthly analyses of spent
pulping liquor HHV or carbon content,
monthly and annual steam production
for each biomass unit, and monthly
quantities of makeup chemicals
(carbonates) used.
BB. Silicon Carbide Production
1. Definition of the Source Category
Silicon carbide (SiC) is primarily an
industrial abrasive manufactured from
silica sand or quartz and petroleum
coke. Other uses of silicon carbide
include semiconductors, body armor,
and the manufacture of Moissanite, a
diamond substitute. The silicon carbide
source category is limited to the
production of silicon carbide for
abrasive purposes.
CO2 and CH4 are emitted during the
production of silicon carbide. Petroleum
coke is utilized as a carbon source
during silicon carbide production and
approximately 35 percent of the carbon
is retained within the silicon carbide
product; the remaining carbon is
converted to CO2 and CH4.
Silicon carbide process emissions
totaled 109,271 metric tons CO2e in
2006 (less than 0.002 percent of the total
national GHG emissions). Of the total,
process-related CO2 emissions
accounted for 91 percent (91,700 metric
tons CO2e), CH4 emissions accounted for
9 percent (8,526 metric tons CO2e), and
on-site stationary combustion emissions
accounted for less than 1 percent (9,045
metric tons CO2e).
For additional background
information on silicon carbide
production, please refer to the Silicon
Carbide Production TSD (EPA–HQ–
OAR–2008–0508–028).
2. Selection of Reporting Threshold
In developing the reporting threshold
for silicon carbide production, we
considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e. Requiring all
facilities to report (no threshold) was
also considered. Table BB–1 of this
preamble illustrates the emissions and
facilities that would be covered under
these various thresholds.
TABLE BB–1. THRESHOLD ANALYSIS FOR SILICON CARBIDE PRODUCTION
Total
national
emissions
(metric tons
CO2e/yr)
Threshold level metric tons CO2e/yr
1,000 ........................................................................
10,000 ......................................................................
25,000 ......................................................................
100,000 ....................................................................
There is no proposed threshold
reporting level for GHG emissions from
silicon carbide production facilities.
The current estimate of emissions from
the known facility just exceeds the
highest threshold considered. Therefore,
in order to simplify the rule and avoid
the need for the facility to calculate and
report whether the facility exceeds the
threshold value, we propose that all
facilities report in this source category.
Requiring all facilities to report captures
100 percent of emissions, and small
temporary changes to the facility would
not affect reporting requirements.
For a full discussion of the threshold
analysis, please refer to the Silicon
Carbide Production TSD (EPA–HQ–
OAR–2008–0508–028). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Monitoring of process emissions from
silicon carbide production is addressed
in both domestic and international GHG
monitoring guidelines and protocols
(the 2006 IPCC Guidelines and U.S.
GHG Inventory). These methodologies
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total
number of
facilities
109,271
109,271
109,271
109,271
1
1
1
1
Metric tons
CO2e/yr
109,271
109,271
109,271
109,271
can be summarized in two different
options based on measuring either
inputs or output of the production
process. In general, the output or
production-based method is less certain,
as it involves multiplying production
data by emission and correction factors
that are likely default values based on
carbon content (i.e., percentage of
petroleum coke input that is carbon)
assumptions. In contrast, the input
method is more certain as it generally
involves measuring the consumption of
reducing agents and calculating the
carbon contents of those reducing
agents, specifically petroleum coke
inputs.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS that meets the
requirements outlined in proposed 40
CFR part 98, subpart C, then you would
be required to use CEMS to estimate
CO2 emissions. Where the CEMS
capture all combustion- and processrelated CO2 emissions you would be
required to follow the requirements of
proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from the
industrial source. Also, refer to
proposed 40 CFR part 98, subpart C to
PO 00000
Frm 00100
Fmt 4701
Sfmt 4702
Facilities covered
Percent
100
100
100
100
Number
Percent
1
1
1
1
100
100
100
100
estimate combustion-related CH4 and
N2O emissions.
Under this proposed rule, if you do
not have CEMS that meet the conditions
outlined in proposed 40 CFR part 98,
subpart C or where the CEMS would not
adequately account for process
emissions, we propose that facilities use
an input based method to estimate
process-related CO2 emissions by
measuring the facility-level petroleum
coke consumed and applying a facilityspecific emission factor derived from
analysis of the carbon content in the
coke. In addition, we propose that
facilities use default emission factors to
estimate process-related CH4 emissions.
Refer to proposed 40 CFR part 98,
subpart C for procedures to estimate
combustion-related CO2, CH4 and N2O
emissions.
We propose that facilities use an
input-based method to estimate processrelated CO2 emissions by measuring the
facility-level petroleum coke consumed
and applying a facility-specific emission
factor derived from analysis of the
carbon content in the coke. Using the
emission factor, facilities would
calculate CO2 emissions quarterly and
aggregate for an annual estimate. In
order to estimate carbon content, we
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
propose that facilities request reports of
the carbon content of the petroleum
coke directly from the supplier or send
petroleum coke samples out to a
certified laboratory for chemical
analysis on a quarterly basis. Any
changes in the measured values would
be reflected in a revised emission factor.
We assume that data on petroleum
coke consumption is readily available to
facilities. The measurement of
production quantities is common
practice in the industry and is usually
measured through the use of scales or
weigh belts so additional costs to the
industry are not anticipated. The
primary additional burden for facilities
associated with this method is
modifying their petroleum coke supplier
contract to include an analysis of the
carbon content of each delivery of
petroleum coke. Alternatively, a facility
can send the coke to an off-site
laboratory for analysis of the carbon
content by the applicable method
incorporated by reference in proposed
40 CFR 98.7. We consider the additional
burden of determining the carbon
content of the coke raw material
minimal compared to the increases in
accuracy expected from the site specific
emission factors.
We also considered a second method
of estimating process-related CO2
emissions that involves application of
default emission factors based on the
quantity of coke consumed or total
silicon carbide produced. According to
the 2006 IPCC Guidelines, the default
CO2 emission factors for silicon carbide
production are relatively uncertain
because industry scale carbide
production processes differ from the
stoichiometry of theoretical chemical
reactions. Given the relative uncertainty
of defaults, we decided not to propose
existing methodologies that relied on
default emission factors or default
values for carbon content of materials
because default approaches are
inherently inaccurate for site-specific
determinations. The use of default
values is more appropriate for sector
wide or national total estimates from
aggregated activity data than for
determining emissions from specific
facilities.
We propose that facilities estimate
process-related CH4 emissions by using
a default emission factor of 10.2 kg CH4
per metric ton of petroleum coke
consumed during silicon carbide
production. This method coincides with
the IPCC Tier 1 method. Direct
measurement of a CH4 emission factor
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
was considered, but the cost of
performing testing to determine this
factor is too burdensome, considering
that the amount of CH4 emissions
originating from silicon carbide
production is less than 0.5 percent of
the overall GHG emissions from this
source category.
The various approaches to monitoring
GHG emissions are elaborated in the
Silicon Carbide Production TSD (EPA–
HQ–OAR–2008–0508–028).
4. Selection of Procedures for Estimating
Missing Data
It is assumed that a facility would be
readily able to supply data on annual
petroleum coke consumption and its
carbon contents. Therefore, 100 percent
data availability is required.
5. Selection of Data Reporting
Requirements
We propose that facilities report the
combined annual CO2 and CH4
emissions from the silicon carbide
production processes. In addition, we
propose that the following data be
reported to assist in verification of
calculations and estimates, checks for
reasonableness, and other data quality
considerations: Annual silicon carbide
production, annual silicon carbide
production capacity, facility-specific
CO2 emission factor, and annual
operating hours. A full list of data to be
reported is included in proposed 40
CFR part 98, subparts A and BB.
6. Selection of Records That Must Be
Retained
In addition to the data reported, we
propose that facilities maintain records
of quarterly analyses of carbon content
for consumed coke (averaged to an
annual basis), annual consumption of
petroleum coke, and calculations of
emission factors. These records hold
values directly used to calculate
reported emissions and are necessary for
future verification that GHG emissions
monitoring and calculations were done
correctly. A full list of records that must
be maintained onsite is included in
proposed 40 CFR part 98, subparts A
and BB.
CC. Soda Ash Manufacturing
1. Definition of the Source Category
Soda ash (sodium carbonate, Na2CO3)
is a raw material utilized in numerous
industries including glass production,
pulp and paper production, and soap
production. According to the USGS, the
majority of the 11 million metric tons of
PO 00000
Frm 00101
Fmt 4701
Sfmt 4702
16547
soda ash produced is used for glass
production. In the U.S., trona (the raw
material from which most American
soda ash is produced) is mined
exclusively in Wyoming, where five of
the seven U.S. soda ash manufacturing
facilities are located. Total soda ash
production in 2006 was 11 million
metric tons, an amount consistent with
2005 and 500,000 metric tons more than
was produced in 2002. Due to a surplus
of soda ash in the market,
approximately 17 percent of the soda
ash industry’s nameplate capacity was
idled in 2006.
Trona-based production methods are
collectively referred to as ‘‘natural
production’’ methods. ‘‘Natural
production’’ emits CO2 by calcining
trona. Calcining involves placing
crushed trona into a kiln to convert
sodium bicarbonate into crude sodium
carbonate that would later be filtered
into pure soda ash.
National emissions from natural soda
ash manufacturing were estimated to be
3.1 million metric tons CO2e in 2006 or
less than 0.04 percent of total emissions.
These emissions include both processrelated emissions (CO2) and on-site
stationary combustion emissions (CO2,
CH4, N2O) from six production facilities
across the U.S. and Puerto Rico.
Process-related emissions account for
1.6 million metric tons CO2e, or 52
percent of the total, while on-site
stationary combustion emissions
account for the remaining 1.5 million
metric tons CO2e emissions. Soda ash
consumption in the U.S. generated 2.5
million metric tons CO2e in 2006.
Emissions from consumption of soda
ash are not addressed in this proposed
rule as they do not occur at the soda ash
manufacturing source. Emissions from
the use of soda ash would be reported
by the glass manufacturing industry,
which consumes the soda ash.
For additional background
information on soda ash manufacturing,
please refer to the Soda Ash
Manufacturing TSD (EPA–HQ–OAR–
2008–0508–029).
2. Selection of Reporting Threshold
In developing the threshold for soda
ash manufacturing, we considered
emissions-based thresholds of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e per year.
Table CC–1 of this preamble illustrates
the emissions and facilities that would
be covered under these various
thresholds.
E:\FR\FM\10APP2.SGM
10APP2
16548
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE CC–1. THRESHOLD ANALYSIS FOR SODA ASH MANUFACTURING
Total national
emissions
metric tons
CO2e/yr
Threshold level metric tons CO2e/yr
1,000 ........................................................................
10,000 ......................................................................
25,000 ......................................................................
100,000 ....................................................................
Facility-level emissions estimates
based on known plant capacities suggest
that all known facilities exceed the
highest (100,000 metric tons CO2e)
threshold examined. Two facilities were
excluded from this analysis based on
available information (one has not been
operating since 2004 and the second
recycles or utilizes CO2 emissions as
part of the process, resulting in limited
fugitive emissions). Even if sources are
not operating at full capacity, all or most
of them would still be expected to
exceed the 25,000 metric ton threshold.
We propose that all facilities report.
Requiring all facilities to report would
simplify the proposed rule, and ensure
that 100 percent of the emissions from
this industry are reported.
For a full discussion of the threshold
analysis, please refer to the Soda Ash
Manufacturing TSD (EPA–HQ–OAR–
2008–0508–029). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from soda ash manufacturing (e.g., the
2006 IPCC Guidelines, DOE 1605(b)).
These methodologies coalesce around
three different options:
Option 1: Default emission factors
would be applied to the amount of trona
consumed or soda ash produced. This
method would also involve applying an
adjustment factor to the default
emission factor to account for fractional
purity of the trona consumed or soda
ash produced. A default adjustment
factor of 0.9 could be applied if country
specific or plant specific information is
not available. This option is consistent
with IPCC Tier 2 methods and 1605(b)’s
‘‘A’’ rated approach.
Option 2: Develop a site-specific
emission factor (determined by an
annual stack test). This method would
account for the fractional purity of the
trona consumed or soda ash produced.
This approach is consistent with IPCC’s
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total
number of
facilities
3,121,438
3,121,438
3,121,438
3,121,438
5
5
5
5
Emissions covered
Metric tons
CO2e/yr
3,121,438
3,121,438
3,121,438
3,121,438
Tier 2 method and consistent with the
DOE 1605(b) ‘‘A’’ rated approach.
Option 3: Direct measurement of
emissions using CEMS.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS to meet the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
emissions, you would be required to
follow requirements of proposed 40 CFR
part 98, subpart C to estimate CO2
emissions. Also, refer to proposed 40
CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions.
Under this proposed rule, if you do
not have CEMS that meet the conditions
outlined in proposed 40 CFR part 98,
subpart C, or where the CEMS would
not adequately account for process
emissions, we propose that facilities
estimate process-related CO2 emissions
using a modified Option 1. Refer to
proposed 40 CFR part 98, subpart C for
procedures to estimate combustionrelated CO2, CH4 and N2O emissions.
The proposed monitoring method
requires facilities to use default
stoichiometric emission factors (either
0.097 for trona consumed (ratio of ton
of CO2 emitted for each ton of trona) or
0.138 for soda ash produced (ratio of ton
of CO2 emitted for each ton of natural
soda ash produced)) and to measure the
fractional purity of the trona or soda
ash. These factors are then applied to
the estimated quantity of raw material
input or the amount of soda ash output.
Raw material input and output
quantities are assumed to be readily
available to facilities. In order to assess
the fractional purity of trona or soda ash
(as determined by the level of the
inorganic carbon present), we propose
that facilities test samples of trona using
in-house TOC analyzers or test samples
of soda ash for inorganic carbon
expressed as total alkalinity using
applicable test methods. We are
assuming that soda ash facilities are
conducting daily tests of fractional
purity and can develop monthly
PO 00000
Frm 00102
Fmt 4701
Sfmt 4702
Facilities covered
Percent
100
100
100
100
Number
Percent
5
5
5
5
100
100
100
100
averages from daily tests. This
methodology was chosen because it
would be more accurate than methods
using default factors for fractional
purity.
We decided against applying a default
emission factor and a default adjustment
factor of 0.9 to either the total amount
of trona consumed or soda ash
produced. According to IPCC, the
stoichiometric ratio used in the default
emission factor equation is an exact
number and assumes 100 percent purity
of the input or output and the
uncertainty of the default emission
factor is negligible. However, simple
application of default emission and
adjustment factors would not take into
account the actual fractional purities of
either the trona input or soda ash
output.
We also decided against proposing the
second option to determine an annual
site-specific emission factor. The stack
from the calciner (kiln) emits CO2
emissions from both combustion- and
process-related sources. An annual stack
test would not capture the variability in
stationary combustion emissions
associated with consumption of various
types of fuels, so would not significantly
reduce the uncertainty for developing
annual estimates of CO2 emissions.
While not improving emissions
estimates significantly, annual stack
testing would be burdensome to
industry. We have concluded that
measuring fractional purity, as
described in the proposed modified
Option 1 approach, would improve
emissions estimates, with a minimal
cost burden.
The third option we considered, but
did not select as the proposed option,
was continuous direct measurement of
emissions from soda ash manufacturing.
This option is consistent with the 2006
IPCC Guidelines Tier 3 method. Use of
a CO2 CEMS would eliminate the need
for further periodic review because this
method would account for the
variability in GHG emissions due to
changes in the process or operation over
time. While this method does tend to
provide the most accurate CO2
emissions measurements and can
E:\FR\FM\10APP2.SGM
10APP2
16549
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
measure both the combustion- and
process-related CO2 emissions, it is
likely the costliest of all the monitoring
methods. Installation of CEMS would
require significant additional burden to
facilities given that few soda ash
facilities currently have CO2 CEMS.
The various options of monitoring
GHG emissions, as well as the domestic
and international GHG monitoring
guidelines and protocols researched, are
elaborated in the Soda Ash
Manufacturing TSD (EPA–HQ–OAR–
2008–0508–029).
4. Selection of Procedures for Estimating
Missing Data
We propose that no missing data
procedures would apply to estimating
CO2 process emissions because the
calculations are based on production, or
trona consumption, which are closely
tracked production inputs and outputs.
Given that the fractional purity would
have to be tested on a daily basis, if a
value is missing the test should be
repeated. Therefore, 100 percent data
availability would be required.
5. Selection of Data Reporting
Requirements
We propose that reported data include
annual CO2 process emissions from each
soda ash manufacturing line, and the
number of soda ash manufacturing
lines, as well as any stationary fuel
combustion emissions. In addition, we
propose that facilities report the
following data for each soda ash
manufacturing line: Annual soda ash
production, annual soda ash production
capacity, annual trona quantity
consumed, fractional purity (i.e.,
inorganic carbon content) of the trona or
soda ash, and number of operating
hours in the calendar year. These
additional data, most of which are used
as a basis for calculating emissions, are
needed to understand the emissions
data, verify the reasonableness of the
reported emissions, and identify
outliers. A full list of data that would be
reported is included in proposed 40
CFR part 98, subparts A and CC.
6. Selection of Records That Must Be
Retained
We propose that facilities keep
information on monthly production of
soda ash (metric tons), monthly
consumption of trona (metric tons), and
daily fractional purity (i.e., inorganic
carbon content) of the trona or soda ash.
A full list of records that must be
retained onsite is included in the
proposed rule.
DD. Sulfur Hexafluoride (SF6) From
Electrical Equipment
1. Definition of the Source Category
The largest use of SF6, both in the
U.S. and internationally, is as an
electrical insulator and interrupter in
equipment that transmits and
distributes electricity. The gas has been
employed by the electric power industry
in the U.S. since the 1950s because of
its dielectric strength and arc-quenching
characteristics. It is used in gasinsulated substations, circuit breakers,
other switchgear, and gas-insulated
lines. SF6 has replaced flammable
insulating oils in many applications and
allows for more compact substations in
dense urban areas. Currently, there are
no available substitutes for SF6 in this
application. For further information, see
the SF6 from Electrical Equipment TSD
(EPA–HQ–OAR–2008–0508–030).
Fugitive emissions of SF6 can escape
from gas-insulated substations and
switch gear through seals, especially
from older equipment. The gas can also
be released during equipment
manufacturing, installation, servicing,
and disposal.
PFCs are sometimes used as
dielectrics and heat transfer fluids in
power transformers. PFCs are also used
for retrofitting CFC–113 cooled
transformers. One PFC used in this
application is perfluorohexane (C6F14).
In terms of both absolute and carbonweighted emissions, PFC emissions
from electrical equipment are generally
believed to be much smaller than SF6
emissions from electrical equipment;
however, there may be some exceptions
to this pattern, according to the 2006
IPCC Guidelines.
According to the 2008 U.S. Inventory,
total U.S. estimated emissions of SF6
from an estimated 1,364 electric power
system utilities 86 were 12.4 million
metric tons CO2e in 2006. We do not
have an estimate of PFC emissions.
This source category comprises
electric power transmission and
distribution systems that operate gasinsulated substations, circuit breakers,
and other switchgear, or power
transformers containing sulfurhexafluoride (SF6) or PFCs.
2. Selection of Reporting Threshold
We propose to require electric power
systems to report their SF6 and PFC
emissions if the total nameplate
capacity of their SF6-containing
equipment exceeds 17,820 lbs of SF6.
This threshold is equivalent to an
emissions threshold of 25,000 metric
tons CO2e, and was developed using
historical (1999) data from utilities that
participate in EPA’s SF6 Emission
Reduction Partnership for Electric
Power Systems (Partnership).
In addition, we considered emissionbased threshold options of 1,000 metric
tons CO2e; 10,000 metric tons CO2e; and
100,000 metric tons CO2e. Nameplate
capacity thresholds of 713; 7,128; and
71,280 lbs of SF6 for all utilities were
also considered, corresponding to the
emission threshold options of 1,000;
10,000; and 100,000 metric tons CO2e,
respectively. Summaries of the
threshold options (capacity-based and
emissions-based) and the number of
utilities and emissions falling above
each threshold are presented in Tables
DD–1 and DD–2 of this preamble.
TABLE DD–1. OPTIONS FOR CAPACITY-BASED THRESHOLDS FOR ELECTRIC POWER SYSTEMS
Total
national
emissions
MMTCO2e/yr
Nameplate capacity threshold for all
utilities
(lbs SF6)
713 ...........................................................
7,128 ........................................................
17,820 ......................................................
71,280 ......................................................
12.4
12.4
12.4
12.4
86 The estimated total number of electric power
system (EPS) utilities includes all companies
participating in the SF6 Emission Reduction
Partnership for Electric Power Systems and the
number includes non-partner utilities with non-
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total number
of
facilities
Emissions covered
MMTCO2e/yr
1,364
1,364
1,364
1,364
PO 00000
Frm 00103
Fmt 4701
Sfmt 4702
Percent
12.19
10.96
10.32
5.95
zero transmission miles. The estimated total
number of EPS utilities that emit SF6 likely
underestimates the population, as some utilities
may own high-voltage equipment yet not own
transmission miles. However, the estimated number
Facilities covered
Number
98
88
83
48
578
183
141
35
Percent
42
13
10
3
is consistent with the U.S. inventory methodology,
in which only non-partner utilities with non-zero
transmission miles and partner utilities are
assumed to emit SF6.
E:\FR\FM\10APP2.SGM
10APP2
16550
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE DD–2. OPTIONS FOR EMISSIONS-BASED THRESHOLDS FOR ELECTRIC POWER SYSTEMS
Threshold level metric tons CO2e/yr
Total
national
emissions
MMTCO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
12.4
12.4
12.4
12.4
We selected a nameplate capacity
threshold equivalent to the 25,000
metric tons CO2e emissions threshold
level. A capacity-based threshold was
selected because it permits utilities to
quickly determine whether they are
covered. There have been many mergers
and acquisitions in the electric power
industry and nameplate capacity is
generally a known variable as a result of
these transactions.
The proposed threshold is consistent
with the threshold for other source
categories. Based on information from
the Partnership and from the Universal
Database Interface Directory of Electric
Power Producers and Distributors, we
estimate that the nameplate capacity
threshold covers only a small
percentage of total utilities (10 percent
or 141 utilities), while covering the
majority of annual emissions
(approximately 83 percent).
Other Options Considered. We
considered setting a threshold based on
the length of the transmission lines,
defined as the miles of lines carrying
voltages above 34.5 kV, owned by
electric power systems. The
transmission-mile threshold equivalent
to 25,000 metric tons CO2e is 1,186
miles. The fractions of utilities and
emissions covered by this threshold
would be almost identical to those
covered by the nameplate-capacity
threshold.
We decided not to propose the
transmission-mile threshold because the
relationship between emissions and
transmission miles, while strong, is not
as strong as that between emissions and
nameplate capacity. On the one hand,
some utilities have far larger nameplate
capacities and emissions than would be
expected based on their transmission
miles. This is the case for some urban
utilities that have large volumes of SF6
in gas-insulated switchgear. On the
other hand, some utilities have lower
nameplate capacities and emissions
than would be expected based on their
transmission miles, because most of
their transmission lines use lower
voltages than average and therefore
typically use less SF6 than average as
well.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total
number of
facilities
MMTCO2e/yr
1,364
1,364
1,364
1,364
3. Selection of Proposed Monitoring
Methods
In developing the proposed approach,
we reviewed the 2006 IPCC Guidelines,
the SF6 Emissions Reduction
Partnership for Electric Power Systems,
the U.S. GHG Inventory, DOE 1605(b),
EPA’s Climate Leaders Program, and
TCR. In the IPCC Guidelines, Tiers 1
and 2 are based on default SF6 and PFC
emission factors, but Tier 3 is based on
using utility-specific information to
estimate emissions of both SF6 and PFC
using a mass-balance analysis.
The proposed monitoring methods for
calculating SF6 and PFC emissions from
electric power systems are similar to the
methodologies described in EPA’s SF6
Emission Reduction Partnership for
Electric Power Systems (Partnership)
Inventory Reporting Protocol and Form
and the 2006 IPCC Guidelines Tier 3
methods for emissions from electrical
equipment. In general, these protocols
and guidance all support using a massbalance approach as the most accurate
alternative to estimate emissions.
We propose that you report all SF6
and PFC emissions, including those
from equipment installation, equipment
use, and equipment decommissioning
and disposal. This requirement would
apply only to systems where the total
nameplate capacity of their SF6containing equipment exceeds 17,820
lbs of SF6. The Tier 3 approach is being
proposed because it is the most accurate
and it is feasible for all systems to
conduct the mass balance analysis for
SF6 and PFC using readily available
information.
The mass-balance approach works by
tracking and systematically accounting
for all facility uses of SF6 and PFC
during the reporting year. The quantities
of SF6 and PFC that cannot be
accounted for are assumed to have been
PO 00000
Frm 00104
Fmt 4701
Sfmt 4702
Percent
12.20
10.87
10.11
5.84
Additional information supporting
the selection of the threshold can be
found in the SF6 from Electrical
Equipment TSD (EPA–HQ–OAR–2008–
0508–030). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
Facilities covered
Number
98
88
82
47
564
158
111
27
Percent
41
12
8
2
emitted to the atmosphere. The
emissions of SF6 and PFC would be
estimated and reported separately.
The following equation describes the
proposed utility-level mass-balance
approach:
User Emissions = Decrease in SF6
Inventory + Acquisitions of
SF6¥Disbursements of SF6¥Net
Increase in Total Nameplate Capacity of
Equipment
Where:
Decrease in SF6 Inventory is SF6 stored in
containers (but not in equipment) at the
beginning of the year minus SF6 stored in
containers (but not in equipment) at the end
of the year.
Acquisitions of SF6 is SF6 purchased from
chemical producers or distributors in bulk +
SF6 purchased from equipment
manufacturers or distributors with or inside
of equipment + SF6 returned to site after offsite recycling.
Disbursements of SF 6 is SF6 in bulk and
contained in equipment that is sold to other
entities + SF6 returned to suppliers + SF6 sent
off-site for recycling + SF6 sent to destruction
facilities.
Net Increase in Total Nameplate Capacity
of Equipment is the Nameplate capacity of
new equipment minus Nameplate capacity of
retiring equipment. (Note that Nameplate
capacity refers to the full and proper charge
of equipment rather than to the actual charge,
which may reflect leakage.)
The same method is being proposed
to estimate emissions of PFCs from
power transformers.
Other Options Considered. We also
considered the IPCC Tier 1 and the IPCC
Tier 2 methods for calculating and
reporting SF6 and PFC emissions, but
did not choose them for several reasons.
Although the IPCC Tier 1 method is
simpler, the default emission factors
have large uncertainty due to variability
associated with handling and
management practices, age of
equipment, mix of equipment, and other
similar factors. Utilities participating in
EPA’s Partnership have reduced their
emission factors to less than Tier 1
default values. Less than 10 percent of
U.S. utilities participate in this program;
however, these utilities represent close
to 40 percent of the U.S. grid, so the
IPCC Tier 1 emission factors are not
E:\FR\FM\10APP2.SGM
10APP2
16551
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
accurate for a large percentage of the
U.S. source category.
IPCC Tier 2 methods use countryspecific emission factors, but the Partner
utilities have demonstrated by
calculating their own utility-level
emission rates that large variability
exists in utility-level emission rates
across the nation (i.e., emission rates
range from less than one percent of a
utility’s SF6 inventory to greater than 35
percent). As a result, we are not
proposing the IPCC Tier 2 method.
These data would be submitted
because they are the minimum data that
are needed to understand and reproduce
the emission calculations that are the
basis of the reported emissions.
Transmission miles would be included
in the reported data so that the
reasonableness of the reported
emissions could be quickly checked
using default emission factors.
4. Selection of Procedures for Estimating
Missing Data
We propose that electric power
systems be required to keep records
documenting (1) their adherence to the
QA/QC requirements specified in the
proposed rule, and (2) the data that
would be included in their emission
reports, as specified above. The QA/QC
requirements records include check-out
sheets and weigh-in procedures for
cylinders, residual gas amounts in
cylinders sent back to suppliers,
invoices for gas and equipment
purchases or sales, and records of
equipment nameplate capacity. The
records that are being proposed are the
minimum needed to reproduce and
confirm emission calculations.
It is expected that utilities should
have 100 percent of the data needed to
perform the mass balance calculations
for both SF6 and PFCs. Partner utilities
missing inputs to the mass-balance
approach have estimated emissions
using other methods, such as assuming
that all purchased SF6 is emitted.
However, this method over-estimates
emissions, and we do not recommend
this method of estimation in the absence
of more complete data. The use of the
mass-balance approach requires correct
records for all inputs.
6. Selection of Records That Must Be
Retained
5. Selection of Data Reporting
Requirements
EE. Titanium Dioxide Production
We propose annual reporting for
facilities in the electric power systems
industry. Each facility would report all
SF6 and PFC emissions, including those
from equipment installation, equipment
use, and equipment decommissioning
and disposal. However, the emissions
would not need to be broken down and
reported separately for installation, use
or disposal. Along with their emissions,
utilities would be required to submit the
following supplemental data, nameplate
capacity (existing as of the beginning of
the year, new during the year, and
retired during the year), transmission
miles, SF6 and PFC sales and purchases,
SF6 and PFC sent off-site for destruction
or to be recycled, SF6 and PFC returned
from offsite after recycling, SF6 and PFC
stored in containers at the beginning
and end of the year, SF6 and PFC with
or inside new equipment purchased in
the year, SF6 and PFC with or inside
equipment sold to other entities and SF6
and PFC returned to suppliers.
Titanium dioxide is a metal oxide
commonly used as a white pigment in
paint manufacturing, paper, plastics,
rubber, ceramics, fabrics, floor covering,
printing ink, and other applications.
The majority of TiO2 production is for
the manufacturing of white paint.
National production of TiO2 in 2006
was approximately 1,400,000 metric
tons.
Titanium dioxide is produced through
two processes: The chloride process and
the sulfate process. According to USGS,
most facilities in the U.S. employ the
chloride process. Total U.S. production
of titanium dioxide pigment through the
chloride process was approximately 1.4
metric tons in 2006, a 7 percent increase
compared to 2005. The chloride process
emits process-related CO2 through the
use of petroleum coke and chlorine as
raw materials, while the sulfate process
does not emit any significant processrelated GHGs.
1. Definition of the Source Category
The chloride process is based on two
chemical reactions. Petroleum coke (C)
is oxidized as the reducing agent in the
first reaction in the presence of chlorine
and crystallized iron titanium oxide
(FeTiO3) to form and emit CO2. A
special grade of petroleum coke, known
as calcined petroleum coke, is a highly
electrically conductive carbon (fixed
carbon content >98 percent) and is used
in several manufacturing processes
including titanium dioxide (in the
chloride process), aluminum, graphite,
steel, and other carbon consuming
industries. For the purposes of this
rulemaking effort EPA is assuming the
carbon content factor for calcined
petroleum coke is 100 percent or a
multiplier of 1. Therefore, no sitespecific factor needs to be determined.
The titanium tetrachloride (TiCl4)
produced through this first reaction is
oxidized with oxygen at about 1,000 °C,
and calcinated in a second reaction to
remove residual chlorine and any
hydrochloric acid that may have formed
in the reaction producing titanium
dioxide (TiO2).
National emissions from titanium
dioxide production were estimated to be
3.6 million metric tons CO2e in 2006.
These emissions include process-related
(CO2) and on-site stationary combustion
emissions (CO2, CH4, and N2O) from
eight production facilities. Processrelated emissions from titanium dioxide
production were 1.87 million metric
tons CO2e or 47 percent of the total,
while on-site combustion emissions
account for the remaining 1.8 million
metric tons CO2e emissions in 2006.
For additional background
information on titanium dioxide
production, please refer to the Titanium
Dioxide Production TSD (EPA–HQ–
OAR–2008–0508–031).
2. Selection of Reporting Threshold
In developing the threshold for
titanium dioxide production, we
considered an emissions-based
threshold of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric
tons CO2e, and 100,000 metric tons
CO2e. Table EE–1 of this preamble
illustrates the emissions and facilities
that would be covered under these
various thresholds.
TABLE EE–1. THRESHOLD ANALYSIS FOR TITANIUM DIOXIDE PRODUCTION
Total national
emissions
Threshold level metric tons CO2e/yr
1,000 ........................................................................
10,000 ......................................................................
25,000 ......................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Total
number of
facilities
3,685,777
3,685,777
3,685,777
Frm 00105
Fmt 4701
8
8
8
Sfmt 4702
Emissions covered
Metric tons
CO2e/yr
3,685,777
3,685,777
3,685,777
E:\FR\FM\10APP2.SGM
Facilities covered
Percent
100
100
100
10APP2
Number
Percent
8
8
8
100
100
100
16552
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE EE–1. THRESHOLD ANALYSIS FOR TITANIUM DIOXIDE PRODUCTION—Continued
Total national
emissions
Threshold level metric tons CO2e/yr
100,000 ....................................................................
At the threshold levels of 1,000 metric
tons CO2e, 10,000 metric tons CO2e, and
25,000 metric tons CO2e, all facilities
exceed the threshold, therefore covering
100 percent of total emissions. At the
100,000 metric tons CO2e level, one
facility would not exceed the threshold
and 98 percent of emissions would be
covered. In order to simplify the rule,
and avoid the need for the source to
calculate and report whether the facility
exceeds threshold value, we are
proposing that all titanium dioxide
production facilities report. Including
all facilities simplifies the rule and
ensures 100 percent coverage without
significantly increasing the number of
affected facilities expected to report
relative to the 25,000 metric ton
threshold.
For a full discussion of the threshold
analysis, please refer to the Titanium
Dioxide Production TSD (EPA–HQ–
OAR–2008–0508–031). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating process-related emissions
from titanium dioxide production (e.g.,
the 2006 IPCC Guidelines, U.S. GHG
Inventory, Australian Government’s
National Greenhouse and Energy
Reporting System). These methods
coalesce around two different options.
Option 1. CO2 emissions are estimated
by applying a default emission factor to
annual facility level titanium dioxide
production.
Option 2. CO2 emissions are estimated
based on the facility-specific quantity of
reducing agents or calcined petroleum
coke consumed.
Option 3. Direct measurement of
emissions using CEMS.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS to meet the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Where the CEMS capture all
combustion- and process-related CO2
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total
number of
facilities
3,685,777
8
Emissions covered
Metric tons
CO2e/yr
PO 00000
Frm 00106
Fmt 4701
Sfmt 4702
Percent
3,628,054
emissions you would be required to
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of proposed 40 CFR part
98, subpart C to estimate CO2 emissions.
Also, refer to proposed 40 CFR part 98,
subpart C to estimate combustionrelated CH4 and N2O emissions.
Under this proposed rule, if you do
not have CEMS that meet the conditions
outlined in proposed 40 CFR part 98,
subpart C, we propose that facilities use
the second option discussed above to
estimate process-related CO2 emissions.
Refer to proposed 40 CFR part 98,
subpart C specifically for procedures to
estimate combustion-related CO2, CH4
and N2O emissions.
Under this approach the total amount
of calcined petroleum coke consumed
would be assumed to be directly
converted into CO2 emissions. The
amount of calcined petroleum coke can
be obtained from facility records, as that
data would be readily available. The
carbon oxidation factor for the calcined
petroleum coke is assumed to be 100
percent, because any amount that is not
oxidized is an insignificant amount. For
the purposes of this rulemaking effort
EPA is assuming the carbon oxidation
factor for calcined petroleum coke, is
equal to 100/100 or 1. Therefore, no sitespecific factor needs to be determined.
We decided not to propose the option
to use continuous direct measurement
because it would not lead to
significantly reduced uncertainty in the
emissions estimate over the proposed
option. Furthermore, the cost impact of
requiring the installation of CEMS is
high in comparison to the relatively low
amount of emissions that would be
quantified from the titanium production
sector.
We decided not to propose the option
to apply default emission factors to
titanium dioxide production to quantify
process-related emissions. Although
default emissions factors have been
developed for quantifying processrelated emissions from titanium dioxide
production, the use of these default
values is more appropriate for sector
wide or national total estimates than for
determining emissions from a specific
plant. Estimates based on site-specific
Facilities covered
98
Number
Percent
7
88
consumption of reducing agents are
more appropriate for reflecting
differences in process design and
operation. According to the 2006 IPCC
Guidelines, the uncertainty associated
with the proposed approach is much
lower given that facilities closely track
consumption of the calcined petroleum
coke (accurate within 2 percent),
whereas the uncertainty associated with
the default emission factor is
approximately 15 percent.
The various approaches to monitoring
GHG emissions are elaborated in the
Titanium Dioxide Production TSD
(EPA–HQ–OAR–2008–0508–031).
4. Selection of Procedures for Estimating
Missing Data
It is assumed that a facility would be
able to supply data on annual calcined
petroleum coke consumption data.
Therefore, 100 percent data availability
is required for all parameters.
5. Selection of Data Reporting
Requirements
We propose that facilities submit
process-related CO2 emissions on an
annual basis, as well as any stationary
fuel combustion emissions. In addition
we propose that facilities report the
following additional data used as the
basis of the calculations to assist in
verification of estimates, checks for
reasonableness, and other data quality
considerations. The data includes:
annual production of titanium dioxide,
annual amount of calcined petroleum
coke consumed, and number of
operating hours in the calendar year.
Facilities are not required to submit
carbon oxidation factor for calcined
petroleum coke; this value is assumed to
be 100 percent, as any amount that is
not oxidized is assumed to be an
insignificant amount. A full list of data
to be reported is included in proposed
40 CFR part 98, subparts A and EE.
6. Selection of Records That Must Be
Retained
In addition to the data reported, we
propose that facilities maintain records
of monthly production of titanium
dioxide and monthly amounts of
calcined petroleum coke consumed.
These records hold values that are
directly used to calculate the emissions
E:\FR\FM\10APP2.SGM
10APP2
16553
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
that are reported and are necessary to
allow determination of whether GHG
emissions monitoring and calculations
were done correctly. They also are
needed to understand the emissions
data and verify the reasonableness of the
reported emissions and identify
potential outliers.
A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and EE.
FF. Underground Coal Mines
1. Definition of the Source Category
Coal mining can produce significant
amounts of CH4 from the following areas
and activities: Active underground coal
mines, surface coal mines, post-coal
mining activities and abandoned
underground coal mines.
An active underground coal mine is a
mine at which coal is produced by
tunneling into the earth to a subsurface
coal seam, which is then mined with
equipment such as cutting machines,
extracted and transported to the surface.
In underground mines, CH4 is released
from the coal and surrounding rock
strata due to mining activities, and can
create an explosive hazard. Ventilation
systems dilute in-mine concentrations
to within safe limits, and exhaust CH4
to the atmosphere.
Mines that produce large amounts of
CH4 also rely on degasification (or
‘‘drainage’’) systems to remove CH4 from
the coal seam in advance of, during, or
after mining, producing highconcentration CH4 gas.
CH4 from degasification and
ventilation systems can be liberated to
the atmosphere or destroyed. Destroyed
CH4 includes, but is not limited to, CH4
combusted by flaring, CH4 destroyed by
thermal oxidation, CH4 combusted for
use in onsite energy or heat production
technologies, CH4 that is conveyed
through pipelines (including natural gas
pipelines) for offsite combustion, and
CH4 that is collected for any other onsite
or offsite use as a fuel.
At surface mines, CH4 in the coal
seams is directly exposed to the
atmosphere.
Post coal mining activities release
emissions as coal continues to emit CH4
as it is stored in piles, processed, and
transported.
At abandoned (closed) underground
coal mines, CH4 from the coal seam and
mined-out area may vent to the
atmosphere through fissures in rock
strata or through incompletely sealed
boreholes. It is possible to recover and
use the CH4 stored in abandoned coal
mines.
Total U.S. CH4 emissions from active
mining operations in 2006 were
estimated to be 58.5 million metric tons
CO2e from these sources. Of this, active
underground mines accounted for 61
percent of emissions, or 35.9 million
metric tons CO2e, surface mines
accounted for 24 percent of emissions,
or 14.0 million metric tons CO2e, and
post-mining emissions accounted for 15
percent, or 8.6 million metric tons CO2e.
CH4 emissions from abandoned (closed)
underground coal mines were estimated
to contribute another 5.4 million metric
tons CO2e. On-site stationary fuel
combustion emissions at coal mining
operations accounted for an estimated
9.0 million metric tons CO2e emissions
in 2006. Proposed requirements for
stationary fuel combustion emissions
are set forth in proposed 40 CFR part 98,
subpart C.
We propose to require reporting of
emissions from ventilation and
degasification systems at active
underground mines in this rule. This
includes the fugitive CH4 from these
systems and also CO2 emissions from
destruction of coal mine gas CH4, where
the gas is not a fuel input for energy
generation or use. Due to difficulties
associated with obtaining accurate
measurements from surface mines, postmining activities, and abandoned
(closed) mines, and in some cases,
difficulties in identifying owners of
these sources, we propose to exclude
fugitive CH4 emissions from these
sources from this rule. These sources
could still surpass the threshold for
stationary fuel combustion activities
and therefore be required to report
stationary fuel combustion-related
emissions.
Although fugitive CO2 may be emitted
from coal seams, it is not typically a
significant source of emissions from
U.S. coal seams compared to CH4.
Furthermore, methodologies are not
widely available to measure these
emissions, and therefore they are not
proposed for inclusion in this rule.
For additional background
information on coal mining, please refer
to the Underground Coal Mines TSD
(EPA–HQ–OAR–2008–0508–032).
2. Selection of Reporting Threshold
In developing the threshold for active
underground coal mines, we considered
emissions-based thresholds of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and
100,000 metric tons CO2e for total onsite
emissions from stationary fuel
combustion, ventilation, and
degasification. We also considered
requiring all coal mines for which CH4
emissions from the ventilation system
are sampled quarterly by the MSHA to
report under this proposal. Table FF–1
of this preamble illustrates the
emissions and facilities that would be
covered under these various thresholds.
TABLE FF–1. THRESHOLD ANALYSIS FOR COAL MINING AT ACTIVE UNDERGROUND COAL MINES
Threshold level metric tons CO2e/yr
Total national
emissions
(metric tons
CO2e)
MSHA reporting .......................................
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
39,520,000
39,520,000
39,520,000
39,520,000
39,520,000
We propose that all active
underground coal mines for which CH4
from the ventilation system is sampled
quarterly by MSHA (or on a more
frequent basis), are required to report
under this rule. MSHA conducts
quarterly testing of CH4 concentration
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
Metric tons
CO2e/yr
612
612
612
612
612
PO 00000
Frm 00107
Fmt 4701
Sfmt 4702
Percent
33,945,956
33,945,446
33,926,526
33,536,385
31,054,856
and flow at mines emitting more than
100,000 cf CH4 per day. We selected this
threshold because subjecting
underground mine operators to a new
emissions-based threshold is
unnecessarily burdensome, as many of
these mines are already subject to
Facilities covered
Facilities
86
86
86
85
79
Percent
128
125
122
100
53
MSHA regulations. The MSHA
threshold for reporting of 100,000 cf
CH4 per day covers approximately 94
percent of the CH4 emitted from
underground coal mine ventilation
systems and about 86 percent of total
emissions from underground mining
E:\FR\FM\10APP2.SGM
10APP2
21
20
20
16
9
16554
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(including stationary fuel combustion
emissions at mine sites, as shown in
Table FF–1 of this preamble).
For additional background
information on the thresholds for coal
mining, please refer to the Underground
Coal Mines TSD (EPA–HQ–OAR–2008–
0508–032). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG monitoring guidelines and
protocols include methodologies for
estimating CH4 emissions from coal
mining (e.g., the 2006 IPCC Guidelines,
U.S. GHG Inventory, DOE 1605(b), and
Australia’s National Greenhouse Gas
and Energy Reporting System). These
methodologies coalesce into three
different approaches.
Option 1. Engineering approaches,
whereby default emission factors would
be applied to total annual coal
production (for ventilation systems), or
emission factors associated with the
system type (for degasification systems)
to estimate fugitive emissions.
Option 2. Periodic sampling of CH4.
Quarterly or more frequent samples
could be taken in order to develop a
site-specific emission factor.
Option 3. Use of CEMS.
Proposed Option for Liberated
Ventilation CH4. We propose Option 2,
quarterly sampling of ventilation air for
monitoring ventilation CH4 liberated
from coal mines.
Under this option, coal mine
operators are required to either (a)
independently collect quarterly samples
of CH4 released from the ventilation
system(s), using MSHA procedures,
have these samples analyzed for CH4
composition, and report the results to
us, or (b) to obtain the results from the
quarterly testing that MSHA already
conducts, and report those to EPA.
MSHA inspectors currently perform
quarterly mine safety inspections on
mines emitting 100,000 cf CH4 or more
per day, and as part of these
inspections, the inspectors test CH4
emissions rates and ventilation shaft
flow, using MSHA-approved sampling
procedures and devices. The sample
bottles are sent to the MSHA lab for
analysis and the results are provided
back to the MSHA district offices for
inclusion in the inspection report.
Currently, the results of these quarterly
measurements are generally not
provided back to the mine.
We would like to take comment on
whether relying on MSHA sampling
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
procedures,87 which were developed to
ensure adherence to safety standards, is
appropriate and sufficiently accurate for
a GHG emissions reporting program.
Further, we are interested in viewpoints
on whether quarterly sampling is
sufficient to account for potential
fluctuations in emissions over smaller
time increments (e.g., daily) from the
mine. For more information on the
MSHA sampling procedures, please
refer to the Underground Coal Mines
TSD (EPA–HQ–OAR–2008–0508–032).
For all ventilation systems with CH4
destruction, CH4 destruction would be
monitored through direct measurement
of CH4 flow to combustion devices with
continuous flow monitoring systems.
The resulting CO2 emissions would be
calculated from these monitored values.
If CH4 from ventilation systems is
destroyed, such a system would have
sufficient continuous monitoring
devices associated with it that such
required monitoring would not propose
any additional burden.
We considered requiring mines to
monitor ventilation CH4 concentrations
by daily sampling, in place of quarterly
sampling, for this rule. Many mines
sample CH4 daily from ventilation
systems using handheld CH4 analyzers.
The primary advantages of this option
are that many mines already take these
measurements and this would therefore
not impose an additional monitoring
burden, and that daily measurements of
CH4 concentration and ventilation shaft
flowrates could allow for more accurate
annual estimates than quarterly
measurements. The primary
disadvantages of this option relative to
the other options that were considered
are that it is not as accurate as
continuous emissions measurements,
and that, if required, it would impose a
cost burden for those mines that do not
already have a daily sampling and
monitoring program in place.
We also decided against requiring
mines with CEMS installed at
ventilation systems to use the
continuous monitoring devices to
monitor ventilation system CH4
emissions. Mines without CEMS would
follow the quarterly option proposed
above. In many underground mines,
CEMS devices are already in operation.
In such cases, this option may involve
only placing such devices at or near the
mine vent outflows where the air
samples are taken by MSHA inspectors.
The primary advantage of continuous
monitoring is that it could increase the
accuracy of annual CH4 emissions
calculations because it takes into
87 NIOSH, Handbook for Methane Control in
Mining, CDC Information Circular 9486, June 2006.
PO 00000
Frm 00108
Fmt 4701
Sfmt 4702
consideration any variability in
emissions from mining operations that
may not be represented in the quarterly
sampling. Moreover, since such devices
are already used within the mine to
assess safety conditions, mine operator
personnel are familiar with their
operation. The disadvantage in
requiring CEMS installation would be
the larger costs associated with
purchasing and maintaining these
devices. We seek comment on the
accuracy and cost of monitoring
ventilation emissions with CEMS.
Finally, we decided not to propose
Option 1, which applies default
emission factors to coal production. We
decided against the use of the default
CH4 emission factors because their
application is more appropriate for GHG
estimates from aggregated process
information on a sector-wide or national
basis than for determining GHG
emissions from specific mines.
Proposed Option for Degasification.
We propose that all coal mine operators
subject to this rule that deploy
degasification systems in underground
mines install continuous monitors for
CH4 content and flowrates on all
degasification wells or degasification
vent holes, and that all CH4 liberated
and CH4 destroyed from these systems
be reported (Option 3). For all systems
with CH4 destruction, CH4 destruction
would be monitored through direct
measurement of CH4 flow to combustion
devices with continuous monitoring
systems. The resulting CO2 emissions
would be calculated from these
monitored values. Option 3 is consistent
with current practices for CH4 that is
destroyed, where the produced gas
volume is presumably already being
measured with continuous monitors.
For gas that is simply vented to the
atmosphere from degasification wells,
this requirement would ensure that this
gas is accurately measured.
We considered, but are not proposing,
Option 1, which would estimate CH4
emissions based on the type of
degasification system employed. For
example, in developing the U.S. GHG
Inventory, we currently assume for
selected mines that degasification
emissions account for 40 percent of total
CH4 liberated from the mine. This
method is very simplistic and least
costly, but there is relatively larger
uncertainty associated with the
emissions estimated. Considering that
emissions from many degasification
wells are currently monitored, and the
need to characterize the quantity of
these vented emissions more accurately,
we do not believe this option is
appropriate.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
We also considered, but are not
proposing, Option 2, which would
require mine operators to conduct
periodic sampling of gob gas vent holes
and any other degasification boreholes,
rather than installing continuous
monitoring. While such an approach
would involve lower capital costs than
CEMS, greater labor costs would be
involved with traveling to each (often
remote) well site to take samples.
Moreover, this method would not
accurately reflect fluctuations in gas
quantity and CH4 concentration. Premining degasification and gob wells are
generally characterized by large
variations in emissions over time, as
emissions can decline rapidly in each
individual well, while new wells/vents
come on line as mining advances.
The various approaches to monitoring
GHG emissions are elaborated in the
Underground Coal Mines TSD (EPA–
HQ–OAR–2008–0508–032).
4. Selection of Procedures for Estimating
Missing Data
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation) a substitute data value for the
missing parameter shall be used in the
calculations.
For each missing value of CH4
concentration, flow rate, temperature,
and pressure for ventilation and
degassification systems, the substitute
data value shall be the arithmetic
average of the quality-assured values of
that parameter immediately preceding
and immediately following the missing
data incident. 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.
5. Selection of Data Reporting
Requirements
We propose that coal mines report, for
all ventilation shafts and degasification
systems (e.g., all boreholes), the
following parameters: CH4 liberated
from the shaft or borehole, the quantity
of CH4 destroyed (if applicable), and net
CH4 emissions on an annual basis. In
addition to reporting emissions, all
input data needed to calculate liberation
and emissions are to be reported, as well
as mine days of operation (for the
ventilation and degasification systems).
A full list of data to be reported is
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
includedproposed 40 CFR part 98,
subparts A and FF.
6. Selection of Records That Must Be
Retained
Reporters are to retain all data listed
in Section V.FF.5 of this preamble. A
full list of records to be retained onsite
is included in proposed 40 CFR part 98,
subparts A and FF.
GG. Zinc Production
1. Definition of the Source Category
Zinc is a metal used as corrosionprotection coatings on steel (galvanized
metal), as die castings, as an alloying
metal with copper to make brass, and as
chemical compounds in rubber,
ceramics, paints, and agriculture. For
this proposed rule, we are defining the
zinc production source category to
consist of zinc smelters using
pyrometallurgical processes and
secondary zinc recycling facilities. Zinc
smelters can process zinc sulfide ore
concentrates (primary zinc smelters) or
zinc-bearing recycled and scrap
materials (secondary zinc smelters). A
secondary zinc recycling facility
recovers zinc from zinc-bearing recycled
and scrap materials to produce crude
zinc oxide for use as a feed material to
zinc smelters. Many of these secondary
zinc recycling facilities have been built
specifically to process dust collected
from electric arc furnace operations at
steel mini-mills across the country.
There are no primary zinc smelters in
the U.S. that use pyrometallurgical
processes. The one operating U.S.
pyrometallurgical zinc smelter
processes crude zinc oxide and calcine
produced from recycled zinc materials.
These feed materials are first processed
through a sintering machine. The sinter
is mixed with metallurgical coke and
fed directly into the top of an
electrothermic furnace. Metallic zinc
vapor is drawn from the furnaces into a
vacuum condenser, which is then
tapped to produce molten zinc metal.
The molten metal is then transferred
directly to a zinc refinery or cast into
zinc slabs.
Secondary zinc recycling facilities
operating in the U.S. use either of two
thermal processes to recover zinc from
recycled electric arc furnace dust and
other scrap materials. For the Waelz kiln
process, the feed material is charged to
an inclined rotary kiln together with
petroleum coke, metallurgical coke, or
anthracite coal. The zinc oxides in the
gases from the kiln are then collected in
a baghouse or electrostatic precipitator.
PO 00000
Frm 00109
Fmt 4701
Sfmt 4702
16555
The second recovery process used for
electric arc furnace dust uses a watercooled, flash-smelting furnace to form
vaporized zinc that is subsequently
captured in a vacuum condenser. The
crude zinc oxide produced at secondary
zinc recycling facilities is shipped to a
zinc smelter for further processing.
Zinc production results in both
combustion and process-related GHG
emissions. The major sources of GHG
emissions from a zinc production
facility are the process-related emissions
from the operation of electrothermic
furnaces at zinc smelters and Waelz
kilns at secondary zinc recycling
facilities. In an electrothermic furnace,
reduction of zinc oxide using carbon
provided by the charging of coke to the
furnace produces CO2. In the Waelz
kiln, the zinc feed materials are heated
to approximately 1200 °C in the
presence of carbon producing zinc
vapor and carbon monoxide (CO). When
combined with the surplus of air in the
kiln, the zinc vapors are oxidized to
form crude zinc oxide, and the CO
oxidized to form process-related CO2
emissions.
Total nationwide GHG emissions from
zinc production facilities operating in
the U.S. were estimated to be
approximately 851,708 metric tons CO2e
for the year 2006. This total GHG
emissions estimate includes both
process-related emissions (CO2 and CH4)
and the additional combustion
emissions (CO2, CH4, and N2O). Processrelated GHG emissions were
approximately 528,777 metric tons CO2e
emissions (62 percent of the total
emissions). The remaining 38 percent or
322,931 metric tons CO2e are from
onsite stationary combustion.
Additional background information
about GHG emissions from the zinc
production source category is available
in the Zinc Production TSD (EPA–HQ–
OAR–2008–0508–033).
2. Selection of Reporting Threshold
Zinc smelters and secondary zinc
recycling facilities in the U.S. vary in
types and sizes of the metallurgical
processes used and mix of zinccontaining feedstocks processed to
produce zinc products. In developing
the threshold for zinc production
facilities, we considered using annual
GHG emissions-based threshold levels
of 1,000, 10,000, 25,000 and 100,000
metric tons CO2e. Table GG–1 of this
preamble illustrates the emissions and
facilities that would be covered under
these various thresholds.
E:\FR\FM\10APP2.SGM
10APP2
16556
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE GG–1. THRESHOLD ANALYSIS FOR ZINC PRODUCTION FACILITIES
Total
nationwide
emissions
metric tons
CO2e/yr
Threshold level
metric tons CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
851,708
851,708
851,708
851,708
We have concluded, based on
emissions estimates using production
capacity, that the one primary zinc
facility exceeds all thresholds
considered (Table GG–1 of this
preamble). For the eight secondary zinc
production facilities, just half are over a
25,000 metric tons CO2e threshold. We
decided it is appropriate to propose a
threshold of 25,000 metric tons CO2e for
reporting emissions from zinc
production facilities that is consistent
with the threshold level being proposed
for other source categories. This
threshold level would avoid placing a
reporting burden on a zinc production
facility with inherently low GHG
emissions because of the type of
metallurgical processes used and type of
zinc product produced while still
requiring the reporting of GHG
emissions from the zinc production
facilities releasing most of the GHG
emissions in the source category. More
discussion of the threshold selection
analysis is available in the Zinc
Production TSD (EPA–HQ–OAR–2008–
0508–033). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
EPA reviewed existing domestic and
international GHG monitoring
guidelines and protocols including the
2006 IPCC Guidelines, U.S. GHG
Inventory, the EU Emissions Trading
System, the Canadian Mandatory GHG
Reporting Program, and the Australian
National GHG Reporting Program. These
methods coalesce around the following
four options for estimating processrelated GHG emissions from zinc
production facilities. Zinc smelters
using hydrometallurgical processes (e.g.,
electrolysis) would not be subject to the
estimating and reporting requirements
in proposed 40 CFR part 98, subpart GG
for zinc production because the
processes used at these smelters do not
release process-related GHG emissions.
However, combustion GHG emissions
from the process equipment at these
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
National
number of
facilities
Metric tons
CO2e/yr
9
9
9
9
PO 00000
Frm 00110
Fmt 4701
Sfmt 4702
Percent
851,708
843,154
801,893
712,181
smelters burning natural gas or other
carbon-based fuels could be subject to
the estimating and reporting
requirements for general stationary fuel
combustion units in proposed 40 CFR
part 98, subpart C, depending on the
level of total GHG emissions from the
facility with respect to the reporting
thresholds specified in proposed 40 CFR
part 98, subpart A.
Option 1. Apply a default emission
factor for the process-related emissions
to the facility zinc production rate. This
is a simplified emission calculation
method using only default emission
factors to estimate CO2 emissions. The
method requires multiplying the
amount of zinc produced by the
appropriate default emission factors
from the 2006 IPCC Guidelines.
Option 2. Perform a carbon balance of
all inputs and outputs using monthly
measurements of the carbon content of
specific process inputs and measure the
mass rate of these inputs. This method
is the same as the IPCC Tier 3 approach
and the higher order methods in the
Canadian and Australian reporting
programs. Implementation of this
method requires owners and operators
of affected zinc smelters to determine
the carbon contents of materials added
to the electrothermic furnace or Waelz
kiln by analysis of representative
samples collected of the material or
from information provided by the
material suppliers. In addition, the
quantities of these materials consumed
during production are measured and
recorded. To obtain the process-related
CO2 emission estimate, the material
carbon content would be multiplied by
the corresponding mass of material
consumed and a factor for conversion of
carbon to CO2. This method assumes
that all of the carbon is converted
during the reduction process. The
facility owner or operator would
determine the average carbon content of
the material for each calendar month
using information provided by the
material supplier or by collecting a
composite sample of material and
sending it to an independent laboratory
for chemical analysis.
Facilities covered
100
99
94
84
Facilities
Percent
9
8
5
4
100
89
56
44
Option 3. Use CO2 emissions data
from a stack test performed using U.S.
EPA reference test methods to develop
a site-specific process emissions factor
which is then applied to quantity
measurement data of feed material or
product for the specified reporting
period. This monitoring method is
applicable to furnace or Waelz kiln
configurations for which the GHG
emissions are contained within a stack
or vent. Using site-specific emissions
factors based on short-term stack testing
is appropriate for those facilities where
process inputs (e.g., feed materials,
carbonaceous reducing agents) and
process operating parameters remain
relatively consistent over time.
Option 4. Use direct emissions
measurement of CO2 emissions. For
furnace and kiln configurations in
which the process off-gases are
contained within a stack or vent, direct
measurement of the CO2 emissions can
be made by either continuously
measuring the off-gas stream CO2
concentration and flow rate using a
CEMS, or periodically measuring the
off-gas stream CO2 concentration and
flow rate using standard stack testing
methods. Using a CEMS, the recorded
emissions measurement data would be
reported annually. An annual emissions
test could be used to develop a sitespecific process emissions factor which
would then be applied to quantity
measurement data of feed material or
product for the specified reporting
period.
Proposed Option. Under this
proposed rule, if you are required to use
an existing CEMS to meet the
requirements outlined in proposed 40
CFR part 98, subpart C, you would be
required to use CEMS to estimate CO2
emissions. Provided that the CEMS
capture all combustion- and processrelated CO2 emissions, you would be
required to follow the requirements of
proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from the
industrial source. You would also refer
to proposed 40 CFR part 98, subpart C
to estimate combustion-related CH4 and
N2O emissions.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
If you do not have CEMS that meet
the conditions outlined in proposed 40
CFR part 98, subpart C, or where the
CEMS would not adequately account for
process emissions, we propose that you
follow Option 2, a carbon balance. You
would still need to refer to proposed 40
CFR part 98, subpart C to estimate
combustion-related CH4 and N2O
emissions. Given the operating
variations between the individual U.S.
zinc production facilities (including
differences in equipment configurations,
mix of zinc feedstocks charged, and
types of carbon materials used) we are
proposing Option 2 to estimate CO2
emissions from an electrothermic
furnace or Waelz kiln at zinc production
facilities because of the lower
uncertainties indicated by the IPCC
Guidelines for these types of emissions
estimates, as compared to applying
exclusively a default emissions factor
based approach to these units on a
nationwide basis.
We decided not to propose the use of
default CO2 emission factors (Option 1)
because their application is more
appropriate for GHG estimates from
aggregated process information on a
sector-wide or nationwide basis than for
determining GHG emissions from
specific facilities. According to the 2006
IPCC Guidelines, the uncertainty
associated with default emission factors
could be as high as 50 percent, while
the uncertainty associated with facility
specific estimates of process inputs and
carbon contents would be within 5 to 10
percent. We considered the additional
burden of the material measurements
required for the carbon calculations
small in relation to the increased
accuracy expected from using this sitespecific information to calculate the
process-related CO2 emissions.
We also decided against proposing
Option 3 because of the potential for
significant variations at zinc production
facilities in the characteristics and
quantities of the furnace or Waelz kiln
inputs (e.g., zinc scrap materials,
carbonaceous reducing agents) and
process operating parameters. A method
using periodic, short-term stack testing
would not be practical or appropriate
for those zinc production facilities
where the furnace or Waelz kiln inputs
and operating parameters do not remain
relatively consistent over the reporting
period.
Further details about the selection of
the monitoring methods for GHG
emissions are available in the Zinc
Production TSD (EPA–HQ–OAR–2008–
0508–033).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
4. Selection of Procedures for Estimating
Missing Data
For electrothermic furnaces or Waelz
kilns for which the owner or operator
calculates process GHG emissions using
site-specific carbonaceous input
material data, the proposed rule requires
the use of substitute data whenever a
quality-assured value of a parameter
that is used to calculate GHG emissions
is unavailable, or ‘‘missing.’’ If the
carbon content analysis of carbon inputs
is missing or lost the substitute data
value would be the average of the
quality-assured values of the parameter
immediately before and immediately
after the missing data period. In those
cases when an owner or operator uses
direct measurement by a CO2 CEMS, the
missing data procedures would be the
same as the Tier 4 requirements
described for general stationary fuel
combustion sources in proposed 40 CFR
part 98, subpart C.
5. Selection of Data Reporting
Requirements
The proposed rule would require
annual reporting of the total annual CO2
process-related emissions from the
electrothermic furnaces and Waelz kilns
at zinc production facilities, as well as
any stationary fuel combustion
emissions. In addition we propose that
additional information which forms the
basis of the emissions estimates also be
reported so that we can understand and
verify the reported emissions. This
additional information includes the
total number of Waelz kilns and
electrothermic furnaces operated at the
facility, the facility zinc product
production capacity, and the number of
facility operating hours in calendar year,
carbon inputs by type, and carbon
contents of inputs by type.
A complete list of data to be reported
is included in proposed 40 CFR part 98,
subparts A and GG.
6. Selection of Records That Must Be
Retained
Maintaining records of the
information used to determine the
reported GHG emissions is necessary to
enable us to verify that the GHG
emissions monitoring and calculations
were done correctly. We propose that all
affected facilities maintain records of
monthly facility production quantities
for each zinc product, number of facility
operating hours each month, and the
annual facility production quantity for
each zinc product (in tons). If you use
the carbon input procedure, you would
record for each carbon-containing input
material consumed or used (other than
fuel) the monthly material quantity,
PO 00000
Frm 00111
Fmt 4701
Sfmt 4702
16557
monthly average carbon content
determined for material, and records of
the supplier provided information or
analyses used for the determination. If
you use the CEMS procedure, you
would maintain the CEMS measurement
records.
A complete list of records to be
retained is included in proposed 40 CFR
part 98, subparts A and GG.
HH. Landfills
1. Definition of the Source Category
After being placed in a landfill, waste
is initially decomposed by aerobic
bacteria, and then by anaerobic bacteria,
which break down organic matter into
substances such as cellulose, amino
acids, and sugars. These substances are
further broken down through
fermentation into gases and short-chain
organic compounds that form the
substrates for the growth of
methanogenic bacteria, which convert
the fermentation products into
stabilized organic materials and biogas.
CH4 generation from a given landfill
is a function of several factors,
including the total amount of waste
disposed in the landfill, the
characteristics of the waste, and the
climatic conditions. The amount of CH4
emitted is the amount of CH4 generated
minus the amount of CH4 that is
destroyed and minus the amount of CH4
oxidized by aerobic microorganisms in
the landfill cover material prior to being
released into the atmosphere.
Waste decaying in landfills also
produces CO2; however, this CO2 is not
counted in GHG totals as it is not
considered an anthropogenic emission.
Likewise, CO2 resulting from the
combustion of landfill CH4 is not
accounted as an anthropogenic emission
under international accounting
guidance.
According to the 2008 U.S. Inventory,
MSW landfills emitted 111.2 million
metric tons CO2e of CH4 in 2006.
Generation of CH4 at these landfills was
246.8 million metric tons CO2e;
however, 65.3 million metric tons CO2e
were recovered and used (destroyed) in
energy projects, 59.8 million metric tons
CO2e were destroyed by flaring, and
12.4 million metric tons CO2e were
oxidized in cover soils. The majority of
the CH4 emissions from on-site
industrial landfills occur at pulp and
paper facilities and food processing
facilities. In 2006, these landfills
emitted 14.6 million metric tons CO2e
CH4: 7.3 million metric tons CO2e from
pulp and paper facilities, and 7.2
million metric tons CO2e from food
processing facilities.
E:\FR\FM\10APP2.SGM
10APP2
16558
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
We propose to require reporting from
open and closed,88 MSW landfills
meeting or exceeding the thresholds
described below. We also propose to
require reporting of industrial landfills
(e.g., landfills at food processing, pulp
and paper, and ethanol production
facilities) meeting or exceeding the
applicable thresholds in the relevant
subparts. Hazardous waste landfills and
construction and demolition landfills
are not included in the landfills source
category as they are not considered
significant sources of GHG emissions.
The definition of landfills in this rule
does not include land application units.
Several refineries have land application
units (also known as land treatment
units) in which oily waste is tilled into
the soil. We are seeking comment on the
exclusion of land application units from
this rule.
For additional background
information on landfills, please refer to
the Landfills TSD (EPA–HQ–OAR–
2008–0508–034).
2. Selection of Reporting Threshold
In developing the threshold for
landfills, we considered thresholds of
1,000, 10,000, 25,000, and 100,000
metric tons CO2e of CH4 generation at a
landfill minus soil oxidation
(‘‘generation threshold’’) or of CH4
emissions from a landfill, minus
oxidation, after any destruction of
landfill gas at a combustion device
(‘‘emissions threshold’’).
Table HH–1 of this preamble
illustrates the emissions and facilities
that would be covered under these
various thresholds for MSW landfills.
For landfills located at industrial
facilities,89 please refer to the threshold
analyses for those sectors (e.g., food
processing, ethanol, pulp and paper).
TABLE HH–1. THRESHOLD ANALYSIS FOR MSW LANDFILLS (OPEN AND CLOSED)
The proposed threshold for reporting
emissions from MSW landfills is a
generation threshold of 25,000 metric
tons CO2e (i.e., CH4 generated at the
landfill, minus oxidation in landfill
cover soils). This threshold is consistent
with thresholds for other source
categories and covers over 70 percent of
emissions from the source category. It
strikes a balance between the goal of
covering the majority of the emissions
while avoiding a reporting burden for
small MSW landfills and, especially,
small, closed MSW landfills.
For a full discussion of the threshold
analysis, please refer to the Landfills
TSD (EPA–HQ–OAR–2008–0508–034).
For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
This section of the preamble describes
the proposed methods for estimating
CH4 generation and emissions from
landfills and for determining the
quantity of landfill CH4 destroyed.
Many domestic and international
GHG monitoring guidelines and
88 For the purposes of this rule, an open landfill
is one that has accepted waste during the reporting
year.
89 As explained in sections III and IV of this
preamble, many facilities reporting to the proposed
15:41 Apr 09, 2009
Jkt 217001
Total national
facilities
111,100,000
111,100,000
111,100,000
111,100,000
111,100,000
111,100,000
111,100,000
111,100,000
1,000 metric tons CO2e (generation) ...................
1,000 metric tons CO2e (emissions) ....................
10,000 metric tons CO2e (generation) .................
10,000 metric tons CO2e (emissions) ..................
25,000 metric tons CO2e (generation) .................
25,000 metric tons CO2e (emissions) ..................
100,000 metric tons CO2e (generation) ...............
100,000 metric tons CO2e (emissions) ................
VerDate Nov<24>2008
Emissions covered
Total national
emissions
(metric tons
CO2e)
Threshold level
7800
7800
7800
7800
7800
7800
7800
7800
Metric tons
CO2e /year
110,800,000
110,800,000
104,400,000
102,800,000
91,100,000
82,400,000
65,600,000
39,300,000
Facilities covered
Percent
99.7
99.7
94
93
82
74
59
35
Number
6,830
6,827
3,484
3,060
2,551
1,926
1,038
441
Percent
88
88
45
39
33
25
13
6
protocols include methodologies for
estimating emissions from landfills (e.g.,
2006 IPCC Guidelines, U.S. GHG
Inventory, CCAR, EPA Climate Leaders,
EU Emissions Trading System, TCR,
EPA’s Landfill Methane Outreach
Program, DOE 1605(b), Australia’s
National Mandatory GHG Reporting
Program (draft), NSPS/NESHAP, WRI/
WBCSD GHG Protocol, and National
Council of Air and Stream
Improvement). In general, these
methodologies include three methods
for monitoring emissions: The modeling
method, the engineering method, and
the direct measurement method.
Option 1. Modeling Method. The
IPCC First Order Decay Model 90 in the
2006 IPCC Guidelines produces
emissions estimates that reflect the
degradation rate of wastes in a landfill.
This method uses waste disposal
quantities, degradable organic carbon,
dissimilated degradable organic carbon,
a decay rate, time lag before CH4
generation, fraction of CH4 in landfill
gas, and an oxidation factor.
Option 2. Engineering Method. Direct
measurement of collected landfill gas to
determine CH4 generation from landfills
depends on two measurable parameters:
The rate of gas flow to the destruction
device; and the CH4 content of the gas.
These are quantified by directly
measuring the flow rate and CH4
concentration of the gas stream to the
destruction device(s).
Option 3. Direct Measurement. Direct
measurement methods for calculating
CH4 emissions from landfills include
flux chambers and optical remote
sensing.
Proposed Option. As part of this
proposed rule, stationary fuel
combustion emissions unrelated to the
flaring of recovered landfill CH4, and
emissions from the use of auxiliary fuel
to maintain effective operation of the
flare (e.g., for pilot gas, or fuel used to
supplement the heating value of the
landfill gas occurring at the landfill),
would be estimated and reported
according to the proposed procedures in
proposed 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources), which are discussed in
Section V.C of this preamble.
In order to estimate CH4 emissions
from the landfill we propose a
combination of Option 1 and Option 2.
Modeling method. In the proposed
rule, all landfills would be required to
rule will have more than one source category. In
order to determine applicability, facilities must add
the emissions from all source categories for which
there are methods proposed in the proposed rule.
90 The IPCC First Order Decay Model is available
at https://www.ipcc-nggip.iges.or.jp/public/2006gl/
vol5.html.
PO 00000
Frm 00112
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
calculate CH4 generation and emissions
using the IPCC First Order Decay Model.
The IPCC First Order Decay Model has
two calculation options: A bulk waste
option and a waste material-specific
option. The proposed rule would
require the use of the material-specific
option for all industrial landfills, and
for MSW landfills when materialspecific waste quantity data are
available, as this option is expected to
provide more accurate emission
estimates. However, the accuracy
improvement is limited and at MSW
landfills, material-specific waste
quantity data are expected to be sparse,
so use of the waste material-specific
approach would not be mandated for all
MSW landfills. Where landfills do not
have waste material-specific data, the
bulk waste option would be used.
We propose that the landfills use sitespecific data to determine waste
disposal quantities (by type of waste
material disposed when materialspecific waste quantity data are
available) and use appropriate EPA and
IPCC default values for all other factors
used in the emissions calculation. To
accurately estimate emissions using this
method, waste disposal data are needed
for the 50 year period prior to the year
of the emissions estimate. Annual waste
disposal data are estimated using
receipts for disposal where available,
and where unavailable, estimates based
on national waste disposal rates and
population served by the landfill.
Engineering method. For landfills
with gas collection systems, it is also
possible to estimate CH4 generation and
emissions using gas flow and
composition metering along with an
estimate of the landfill gas collection
efficiency. We propose to require
landfills that have gas collection
systems to calculate their CH4
generation (adjusted for oxidation) and
emissions using both the IPCC First
Order Decay Model (as described
above), and the measured CH4 collection
rates and estimated gas collection
efficiency. This proposal provides a
means by which all landfills would
report emissions and generation
consistently using the same (IPCC First
Order Decay Model) methodology,
while also providing reporting of sitespecific emissions and generation
estimates based on gas collection data.
We propose that landfills with gas
collection systems continuously
measure the CH4 flow and concentration
at the flare or energy device. This
monitoring option is more accurate than
a monthly sample given variability in
gas flow and concentration over time,
and many landfills with gas collection
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
systems already have such equipment in
place.
We are seeking comment on monthly
sampling of landfill gas CH4 flow and
concentration as an alternative to a
continuous composition analyzer. For
the monthly sampling alternative, a
continuous gas flowmeter would still be
required.
To estimate CH4 emissions remaining
in the landfill gas combustion exhaust
of a destruction device, apply the DE of
the equipment to the quantity of CH4
collected as measured by the monitoring
systems described above.
Calculating generation and emissions.
CH4 generation (adjusted for oxidation)
is calculated by applying an oxidation
factor to generated CH4. For landfills
without gas collection systems, the
calculated value for CH4 generation
(adjusted for oxidation) is equal to CH4
emissions. For landfills with collection
systems, CH4 generation is also
calculated using both the IPCC First
Order Decay model method and the gas
collection data measurement method
with a collection efficiency as explained
above. CH4 emissions are calculated by
deducting destroyed CH4 and applying
an oxidation factor to the fraction of
generated CH4 that is not destroyed.
Direct Measurement Method. We also
considered direct measurement at
landfills as an option. The direct
measurement methods available (e.g.,
flux chambers and optical remote
sensing) are currently being used for
research purposes, but are complex and
costly, their application to landfills is
still under investigation, and they may
not produce accurate results if the
measuring system has incomplete
coverage.
We are considering developing a tool
to assist reporters in calculating
generation and emissions from this
source category. We have reviewed tools
for calculating emissions and emissions
reductions from these sources,
including IPCC’s Waste Model, and
National Council of Air and Stream
Improvement’s GHG Calculation Tools
for Pulp and Paper Mills, and EPA’s
LandGEM, and are seeking comment on
the advantages and disadvantages of
using these tools as a model for tool
development and on the utility of
providing such a tool.
4. Selection of Procedures for Estimating
Missing Data
Missing data procedures for landfills
are proposed based on the monitoring
methodology. In the case where a
monitoring system is used, the
substitute value would be calculated as
the average of the values immediately
proceeding and succeeding the missing
PO 00000
Frm 00113
Fmt 4701
Sfmt 4702
16559
data period. For prolonged periods of
missing data when a monitoring system
is used, or for other non-monitored data,
the substitute data would be determined
from the average value for the missing
parameter from the previous year, or
from equations specified in the rule (for
waste disposal quantities). The
proposed rule would require a complete
record of all parameters determined
from company records that are used in
the GHG emissions calculations (e.g.,
disposal data, gas recovery data).
For purposes of the emissions
calculation, we considered not
deducting CH4 destruction that was not
recorded. However, not including CH4
recovery could greatly overestimate a
facility’s emissions. On the other hand,
allowing extended periods of missing
data provides a disincentive to repairing
the monitoring system.
5. Selection of Data Reporting
Requirements
We propose that landfills over the
threshold report CH4 generation, CH4
oxidation, CH4 destruction (if
applicable), and net CH4 emissions on
an annual basis, as calculated above
using both the First Order Decay Model
and, if applicable, gas flow data for
landfills with gas collection systems. In
addition to reporting emissions, input
data needed to calculate CH4 generation
and emissions would be required to be
reported. These data form the basis of
the GHG emission calculations and are
needed for EPA to understand the
emissions data and verify the
reasonableness of the reported data. A
full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and HH.
6. Selection of Records That Must Be
Retained
Records to be retained include
information on waste disposal
quantities, waste composition if
available, and biogas measurements.
These records are needed to allow
verification that the GHG emission
monitoring and calculations were done
correctly. A full list of records to be
retained onsite is included in proposed
40 CFR part 98, subparts A and HH.
II. Wastewater Treatment
1. Definition of the Source Category
An industrial wastewater treatment
system is a system located at an
industrial facility which includes the
collection of processes that treat or
remove pollutants and contaminants,
such as soluble organic matter,
suspended solids, pathogenic
organisms, and chemicals from waters
E:\FR\FM\10APP2.SGM
10APP2
16560
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
released from industrial processes.
Industrial wastewater treatment systems
may include a variety of processes,
ranging from primary treatment for
solids removal to secondary biological
treatment (e.g., activated sludge,
lagoons) for organics reduction to
tertiary treatment for nutrient removal,
disinfection, and more discrete
filtration. In some systems, the biogas
(primarily CH4) generated by anaerobic
digestion of organic matter is captured
and destroyed by flaring and/or energy
recovery. The components and
configuration of an industrial
wastewater treatment system are
determined by the type of pollutants
and contaminants targeted for removal
or treatment. Industrial wastewater
systems that rely on microbial activity
to degrade organic compounds under
anaerobic conditions are sources of CH4.
CH4 emissions from wastewater
treatment systems are primarily a
function of how much organic content
is present in the wastewater system and
how the wastewater is treated.
Industries that have the potential to
produce significant CH4B emissions
from wastewater treatment—those with
high volumes of wastewater generated
and a high organic wastewater load—
include pulp and paper manufacturing,
food processing, ethanol production,
and petroleum refining.
Wastewater treatment also produces
CO2; however, with the exception of
CO2 from oil/water separators at
petroleum refineries, this CO2 is not
counted in GHG totals as it is not
considered an anthropogenic emission.
Likewise, CO2 resulting from the
combustion of digester CH4 is not
accounted as an anthropogenic emission
under international accounting
guidance.
In 2006, CH4B emissions from
industrial wastewater treatment were
estimated to be 7.9 million metric tons
CO2e.
The only wastewater treatment
process emissions to be reported in this
rule are those from onsite wastewater
treatment located at industrial facilities,
such as at pulp and paper, food
processing, ethanol production,
petrochemical, and petroleum refining
facilities. POTWs are not included in
this proposal because, as described in
the Wastewater Treatment TSD (EPA–
HQ–OAR–2008–0508–035), emissions
from POTWs do not exceed the
thresholds considered under this rule.
2. Selection of Reporting Threshold
A separate threshold is not proposed
for emissions from industrial
wastewater treatment system as these
emissions occur in a number of facilities
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
across a range of industries (e.g., pulp
and paper, food processing, ethanol
production, petrochemical, and
petroleum refining). As described in
Sections III and IV of this preamble, a
facility may have more than one source
category and emissions from all source
categories for which there are methods
(e.g., emissions from industrial
wastewater treatment systems) must be
included in the facility’s applicability
determination. Please see the preamble
sections for the relevant sectors for more
information on the applicability
determination for your facility.
Despite the fact that we are not
proposing a separate threshold for
industrial wastewater systems, there is
analysis in the Wastewater Treatment
TSD on the types of industrial facilities
that would meet thresholds at the 1,000,
10,000, 25,000 and 100,000 million
metric tons CO2e level based on
emissions from wastewater alone. There
is also a separate threshold analysis on
POTWs.
For a full discussion of those
threshold analyses, please refer to
Wastewater Treatment TSD (EPA–HQ–
OAR–2008–0508–035). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
For this proposal, we reviewed
several protocols and programs for
monitoring and/or estimating GHG
emissions including the 2006 IPCC
Guidelines, the U.S. GHG Inventory,
CARB Mandatory GHG Emissions
Reporting System, CCAR, National
Council of Air and Stream
Improvement, DOE 1605(b), EPA
Climate Leaders, TCR, UNFCCC Clean
Development Mechanism, the EU
Emissions Trading System, and the New
Mexico Mandatory GHG Reporting
Program. These methodologies are all
primarily based on the IPCC Guidelines.
Based on this review, we considered
the following options.
Option 1. Modeling Method. This
method involves the use of certain sitespecific measured activity data and
emission factors. The IPCC method, for
example, uses wastewater flow, COD,
and wastewater treatment system type
to calculate CH4 emissions from
wastewater treatment.
Option 2. Direct Measurement. This
method allows for site-specific
measurements, but the methods
available (e.g., flux chambers and open
path methods) are currently being used
only for research purposes, are complex
and costly, and might not be accurate if
PO 00000
Frm 00114
Fmt 4701
Sfmt 4702
the measuring system has incomplete
coverage.
Proposed Methods. We propose that
facilities use activity data, such as
measured COD concentration, and
operational characteristics (e.g., type of
system), and the IPCC Tier 1 method to
calculate CH4 generation. To determine
CH4 destruction, we propose direct
measurement of CH4 flow to combustion
devices. The proposed monitoring
method uses a separate equation to
estimate CO2 from oil/water separators
at petroleum refineries, based on
California’s AB32 mandatory reporting
rule. This approach allows the use of
default factors, such as a system
emission factor, for certain elements of
the calculation, and the use of sitespecific data where possible.
CH4 emissions from industrial
wastewater treatment system
components other than digesters. To
estimate the amount of CH4 emissions
from industrial wastewater treatment,
plant-specific values of COD would be
determined by weekly sampling. The
maximum amount of CH4 that could
potentially be produced by the
wastewater under ideal conditions is
calculated by multiplying the COD by
the maximum CH4 producing capacity
of the wastewater, per the 2006 IPCC
Guidelines. This value is then
multiplied by a system-specific CH4
conversion factor reflecting the
capability of a system to produce the
maximum achievable CH4 based on the
organic matter present in the
wastewater.
CH4 Generation from Anaerobic
Digesters. If the wastewater treatment
system includes an anaerobic digester,
we propose that the CH4 generation of
the digester be measured continuously.
Direct measurement to determine CH4
generation from digesters depends on
two measurable parameters: The rate of
gas flow to the combustion device and
the CH4 content of the gas. These are
quantified by direct measurement of the
gas stream to the destruction device(s).
The gas stream is measured by
continuous metering of both flow and
gas concentration. This continuous
monitoring option is more accurate than
a monthly sample given variability in
gas flow and concentration over time,
and many digesters already have such
equipment in place.
We are also seeking comment on
monthly sampling of digester gas CH4
content as an alternative to a continuous
composition analyzer. For the monthly
CH4 content sampling alternative, a
continuous gas flow meter would still
be required.
CH4 Destruction. To estimate CH4
destroyed at a digester, you would apply
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the DE of the combustion equipment
(lesser of manufacturer’s specified DE
and 0.99) to the value of CH4 generated
from anaerobic digestion estimated
above.
CO2 emissions from oil/water
separators at petroleum refineries. To
calculate CO2 emissions from
degradation of petroleum or impurities
at oil/water separators at petroleum
refineries, the volume of wastewater
treated would be measured weekly and
multiplied by the non-methane volatile
organic carbon emission factor for the
type of separator used, and an emission
factor for CO2 (mass of CO2/mass of nonmethane volatile organic carbon).
Total emissions. Total emissions from
wastewater treatment are the sum of the
CH4 emissions (including undestroyed
CH4 from digesters), and CO2 emissions.
Other Options Considered. Direct
measurement is another option we
considered but are not proposing in this
rule. This method allows for sitespecific measurements, but it is costly
and might not be accurate if the
measuring system has incomplete
coverage. To be accurate, a direct
measurement system would need to be
complete both spatially (in that all
emissions pathways are covered, not
just individual pathways as is the case
with anaerobic digesters, at which gas is
commonly directly metered) and
temporally (as emissions can vary
greatly due to changes in influent and
conditions at the facility).
We are considering developing a tool
to assist reporters in calculating
emissions from this source category.
EPA has reviewed tools for calculating
emissions from these sources, such as
National Council of Air and Stream
Improvement’s GHG Calculation Tools
for Pulp and Paper Mills, and is seeking
comment on the advantages and
disadvantages of using these tools as a
model for tool development, and the
utility of providing such a tool.
For additional information on the
proposed method, please see the 2006
IPCC Guidelines,91 the 2008 U.S.
Inventory,92 and the Wastewater
Treatment TSD (EPA–HQ–OAR–2008–
0508–035).
4. Selection of Procedures for Estimating
Missing Data
On the occasion that a facility lacks
data needed to determine the emissions
91 2006 IPCC Guidelines. Chapter 6: Wastewater
Treatment and Discharge. (Volume 5 Waste.)
Available at https://www.ipcc-nggip.iges.or.jp/
public/2006gl/pdf/5_Volume5/
V5_6_Ch6_Wastewater.pdf.
92 2008 U.S. Inventory. Chapter 8: Waste.
Available at https://www.epa.gov/climatechange/
emissions/usinventoryreport.html.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
from wastewater treatment over a period
of time, we propose that the facility
apply an average facility-level value for
the missing parameter from
measurements of the parameter
preceding and following the missing
data incident, as specified in the
proposed rule. The proposed rule would
require a complete record of all
parameters determined from company
records that are used in the GHG
emissions calculations (e.g., production
data, biogas combustion data).
For purposes of the emissions
calculations, we considered not
deducting CH4 destruction that was not
recorded. However, not including CH4
destruction could greatly overestimate a
facility’s actual CH4 emissions.
5. Selection of Data Reporting
Requirements
EPA proposes that industrial
wastewater treatment plants over the
threshold report annually both CH4 and
CO2 emissions from wastewater
treatment system components other
than digesters, and CH4 generation and
destruction at digesters. In addition to
reporting emissions, generation, and
destruction, input data used to calculate
emissions from the wastewater
treatment process would be required to
be reported. These data form the basis
of the GHG emission calculations and
are needed for EPA to understand the
emissions data and verify the
reasonableness of the reported data.
A full list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and II.
6. Selection of Records That Must Be
Retained
Records to be retained include
information on influent flow rate, COD
concentration, wastewater treatment
system types, and digester biogas
measurements. These records are
needed to allow verification that the
GHG emission monitoring and
calculations were done correctly. A full
list of records to be retained onsite is
included in proposed 40 CFR part 98,
subparts A and II.
JJ. Manure Management
1. Definition of the Source Category
A manure management system is a
system that stabilizes or stores livestock
manure, or does both. Anaerobic
manure management systems include
liquid/slurry handling in uncovered
anaerobic lagoons, ponds, tanks, pits, or
digesters. At some digesters, material
other than manure is treated along with
the manure. Manure management
systems in which treatment is primarily
PO 00000
Frm 00115
Fmt 4701
Sfmt 4702
16561
aerobic include daily spread, solid
storage, drylot, and manure composting.
For the purposes of this rule, a manure
management facility consists of
uncovered anaerobic lagoons, liquid/
slurry systems, pits, digesters, and
drylots (including systems that combine
drylot with solid storage) onsite manure
composting, other poultry manure
systems, and cattle and swine deep
bedding systems. The manure
management system does not include
other onsite units and processes at a
livestock operation unrelated to the
stabilization and/or storage of manure.
When livestock manure are stored or
treated, the anaerobic decomposition of
materials in the manure management
system produces CH4, while N2O is
produced as part of the nitrogen cycle
through the nitrification and
denitrification of the organic nitrogen in
livestock manure and urine. The
amount and type of emissions produced
are related to the specific types of
manure management systems used at
the farm and are driven by retention
time, temperature, and treatment
conditions.
Manure management also produces
CO2; however, this CO2 is not counted
in GHG totals as it is not considered an
anthropogenic emission. Likewise, CO2
resulting from the combustion of
digester CH4 is not accounted as an
anthropogenic emission under
international accounting guidance.
According to the 2008 U.S. Inventory,
CH4 emissions from manure
management systems totaled 41.4
million metric tons CO2e, and N2O
emissions were 14.3 million metric tons
CO2e in 2006; manure management
systems account for 8 percent of total
anthropogenic CH4 emissions and 3
percent of N2O emissions in the U.S.
Manure management systems which
include one or more of the following
components are to report emissions
under this rule: Manure handling in
uncovered anaerobic lagoons, liquid/
slurry systems, pits, digesters, and
drylots, including systems that combine
drylot with solid storage. Emissions to
be reported include those from the
systems listed above, and also emissions
from any high rise houses for caged
laying hens, broiler and turkey
production on litter, deep bedding
systems for cattle and swine, and
manure composting occuring onsite as
part of the manure management system.
This source category does not include
systems which consist of only
components classified as daily spread,
solid storage, pasture/range/paddock, or
manure composting. For detailed
descriptions of system types, please
E:\FR\FM\10APP2.SGM
10APP2
16562
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
refer to the Manure Management TSD
(EPA–HQ–OAR–2008–0508–036).
A facility that is subject to the
proposed rule only because of emissions
from manure management would also
report CO2, CH4, and N2O emissions
from the combustion of supplemental
fuel in flares using the methods in
proposed 40 CFR part 98, subpart C, but
would not be required to report any
other combustion emissions.
2. Selection of Reporting Threshold
In developing the threshold for
manure management, we considered
thresholds of 1,000, 10,000, 25,000, and
100,000 metric tons CO2e of CH4
generation and N2O emissions at a
manure management system
(‘‘generation threshold’’), and CH4 and
N2O emissions at manure management
systems (‘‘emissions threshold’’). The
‘‘generation threshold’’ is the amount of
CH4 and N2O that would be emitted
from the facility if no CH4 destruction
takes place. This includes all CH4
generation from all manure management
system types, including digesters, and
N2O emissions. The ‘‘emissions
threshold’’ includes the CH4 and N2O
that is emitted to the atmosphere from
these facilities. In the emissions
threshold, CH4 that is destroyed at
digesters is taken into account and
deducted from the total CH4 generation
calculated.
To estimate the number of farms at
each threshold, EPA first developed a
number of model farms to represent the
manure management systems that are
most common on large farms and have
the greatest potential to exceed the GHG
thresholds. Next, we used EPA’s GHG
inventory methodology for manure
management, to estimate the numbers of
livestock that would need to be present
to exceed the threshold for each model
farm type. Finally, we combined the
numbers of livestock required on each
model farm to meet the thresholds with
U.S. Department of Agriculture (USDA)
data on farm sizes to determine how
many farms in the United States have
the livestock populations required to
meet the GHG thresholds for each model
farm.
Table JJ–1 of this preamble presents
the estimated head of livestock that
would meet the thresholds evaluated for
the highest GHG-emitting common
manure management systems for beef
(steers and heifers at a feedlot), dairy
(cows at an uncovered anaerobic lagoon,
heifers on dry lot without solids
separation), swine (farrow to finish at an
uncovered anaerobic lagoon), and
poultry (layers and pullets at an
uncovered anaerobic lagoon).
Other types of farms and manure
management systems could require
significantly higher head counts to meet
the thresholds considered: Meeting the
25,000 tCO2e threshold could require
978,000 head for beef on pasture, 13,000
head for some dairy liquid slurry
systems, 171,000 head of farrow to
finish swine using a deep pit for
manure, and 47,028,300 broilers on
litter. For more information on
estimated head of livestock that would
meet these thresholds for other manure
management system types, please see
the Manure Management TSD (EPA–
HQ–OAR–2008–0508–036).
TABLE JJ–1. ESTIMATED HEAD OF LIVESTOCK TO MEET THRESHOLDS
Threshold Levels (metric tons CO2e)
1,000
10,000
25,000
100,000
Total number of head to meet threshold
Beef ..................................................................................................................................
Dairy .................................................................................................................................
Swine ...............................................................................................................................
Poultry ..............................................................................................................................
Although data are available at the
national level on the number of farms of
certain sizes, most of the population
sizes needed to meet these thresholds
occur in the largest farm size categories,
in which data are not sufficiently
disaggregated to determine how many
farms of such sizes exist. For example,
the largest dairy farm size category for
which data is available is ‘‘1,000 head
or more.’’ The number of dairy farms
with populations large enough to meet
thresholds for 10,000 metric tons CO2e
(2,000 animals) and above therefore had
to be estimated using expert judgment.
It is estimated that at the proposed
threshold, fewer than 50 manure
management systems at beef, dairy, and
swine operations would be required to
report. Table JJ does not determine
applicability alone, but rather serves as
a ‘‘screening’’ guide in determining the
approximate facility size that meets the
applicability requirements. We are also
seeking comment on the advantages and
disadvantages of using additional
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
3,500
200
3,000
39,500
screening tools such as a look-up table
or computerized calculator to help
owners or operators determine if they
meet the reporting threshold. A table
could be developed that indicated
whether a facility had a sufficient
number of animals to warrant further
screening. If the initial screening
through use of the table indicated that
the facility may meet the reporting
threshold a simple computerized
calculator (e.g., web-based model)
utilizing site-specifica data such as the
type of manure management system and
the average number of head, along with
some other default data provided in
look-up tables could be used to
determine if a facility met the reporting
threshold. Screening devices, if utilized,
could assist owners or operators in
determining if they are near the
threshold for reporting and therefore
potentially avoid costs incurred from
monthly manure analysis proposed in
the calculation method of the rule. More
information and estimates based on
PO 00000
Frm 00116
Fmt 4701
Sfmt 4702
35,500
2,000
29,000
358,000
89,000
5,000
73,000
895,000
356,000
20,000
291,500
3,580,000
existing farm size data are presented in
the Manure Management TSD (EPA–
HQ–OAR–2008–0508–036).
The proposed threshold for reporting
emissions from manure management
systems is the emission threshold of
25,000 metric tons CO2e. More
specifically, the CH4 and N2O emissions
from manure management are summed
to determine if a manure management
system meets or exceeds the threshold.
Facilities exceeding the threshold
would report both of these GHG
emissions. This threshold includes the
largest emitters of GHG from this source
category, while avoiding reporting from
many small farms with less significant
emissions. For a full discussion of the
threshold analysis, please refer to
Manure Management TSD (EPA–HQ–
OAR–2008–0508–036). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
We are seeking comment on the
option of using a generation threshold
instead of the proposed emissions
threshold. In the generation threshold
option, the CH4 generation (including
CH4 generated and later combusted) and
the N2O emissions from manure
management are summed to determine
if a manure management system meets
or exceeds the threshold. Facilities
exceeding the threshold would report
both GHG generation and emissions. We
estimated that this option would cover
several farms with digesters that would
not be covered in the emissions
threshold option.
3. Selection of Proposed Monitoring
Methods
Many domestic and international
GHG programs provide monitoring
guidelines and protocols for estimating
emissions from manure management
(e.g., the 2006 IPCC Guidelines, the U.S.
GHG Inventory, DOE 1605(b), CARB
Mandatory GHG Emissions Reporting
System, CCAR, EPA Climate Leaders,
TCR, UNFCCC Clean Development
Mechanism, EPA AgSTAR, and Chicago
Climate Exchange). These
methodologies are all based on the IPCC
Guidelines.
Based on the review of these methods,
we considered the following options.
Option 1. Modeling Method. This
method involves the use of certain sitespecific measured activity data and
emission factors. The IPCC method, for
example, uses volatile solids, nitrogen
excretion, climate data, and manure
management system type to calculate
CH4 and N2O emissions from manure
management systems.
Option 2. Direct Measurement. This
method allows for site-specific
measurements, but the methods
available (e.g., flux chambers and open
path methods) are currently being used
only for research purposes, are complex
and costly, and might not be accurate if
the measuring system has incomplete
coverage.
Proposed option. We propose that
facilities use activity data, such as the
number of head of livestock, operational
characteristics (e.g., physical and
chemical characteristics of the manure,
including measured volatile solids and
nitrogen values, type of management
system(s)), and climate data, with the
IPCC method to calculate CH4 and N2O
emissions, and measured values for gas
destruction.
CH4 emitted at manure management
system types other than digesters. We
propose that CH4 emissions at manure
management system components other
than digesters be calculated using the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
IPCC methodology and measured
volatile solids values.
We propose that the amount of
volatile solids excreted be calculated
using (1) calculation of manure quantity
entering the system using livestock
population data and default values for
average animal mass and manure
generation, and (2) monthly sampling
and testing of excreted manure for total
volatile solids content.
We are seeking comment on the
option of using facility-specific
livestock population and mass, and
default values for volatile solids rate to
estimate total volatile solids, instead of
measured values. We are also seeking
comment on whether a different
sampling and testing frequency, such as
quarterly, would be more appropriate
than monthly.
The maximum amount of CH4 that
could potentially be produced by the
manure under ideal conditions would
be calculated by multiplying the volatile
solids by the maximum CH4-producing
capacity of the manure (B0), a default
value included in the GHG Inventory. A
system-specific CH4 conversion factor
would then be applied to determine the
amount of CH4 produced by the specific
system type.
CH4 Generation at Digesters. If the
manure management system includes a
digester, we propose that the CH4
generation of the digester be measured
continuously. Direct measurement to
determine CH4 generation from digesters
depends on two measurable parameters:
The rate of gas flow to the combustion
device, and the CH4 content of the gas.
These would be quantified by direct
measurement of the total gas stream. We
propose that the gas stream be measured
by continuous metering of both flow
and gas concentration. This continuous
monitoring option is more accurate than
a monthly sample given variability in
gas flow and concentration over time,
and many digesters already have such
equipment in place.
We are also seeking comment on
monthly sampling of digester gas CH4
content as an alternative to a continuous
composition analyzer. For the monthly
CH4 content sampling alternative, a
continuous gas flow meter would still
be required.
CH4 Destruction at Digesters. To
estimate CH4 destruction at a digester,
you would apply the DE of the
destruction equipment (lesser of
manufacturer’s specified DE and 0.99)
and the ratio of operating hours to
reporting hours to the value of CH4
generated from anaerobic digestion
estimated above.
CH4 Leakage at Digesters. To estimate
CH4 leakage from digesters, we propose
PO 00000
Frm 00117
Fmt 4701
Sfmt 4702
16563
that a default value for collection
efficiency is applied to the measured
quantity of CH4 flow to a destruction
device. We are seeking comment on the
proposed method and on the proposed
default collection efficiency values for
estimating leakage from digesters.
CH4 Emissions from Digesters. We
propose that emissions from digesters be
calculated as the sum of CH4 that is not
destroyed at the destruction device, and
CH4 that leaks from the digester.
N2O Emissions. We propose that N2O
emissions be calculated using the IPCC
methodology and measured nitrogen (N)
values.
We propose that the amount of
nitrogen entering the manure
management system be measured
through (1) calculation of manure
quantity entering the system using
livestock population data and default
values for average animal mass and
manure generation, and (2) monthly
sampling and testing of excreted manure
for total nitrogen content.
We are seeking comment on the
option of using facility-specific
livestock population and mass, and
default values for nitrogen excretion rate
to estimate total N, instead of measured
values.
Each manure management system
type has an associated default N2O
emission factor which would be applied
to the amount of nitrogen managed by
the system.
GHG Emissions. Reporters would be
required to complete the following to
calculate the emissions for reporting.
Estimate and report GHG emissions
by adding the CH4 emissions from
manure management systems other than
digesters, the N2O emissions from
manure management systems, and, for
manure management systems which
include digesters, the CH4 emissions
(monitored CH4 generation at the
digester minus CH4 destruction at the
digester) from the anaerobic digester.
Direct measurement is another option
we considered but are not proposing in
this rule. A direct measurement system
must be complete both spatially (in that
all emissions pathways are covered) and
temporally (as emissions can vary
greatly due to changes in population,
diet, and conditions at the facility) and
would hence be difficult and expensive
to implement accurately.
We are considering developing a tool
to assist reporters in calculating
emissions from this source category.
There are several existing tools for
calculating emissions and emissions
reductions from manure management
systems, including EPA’s FarmWare and
CCAR’s Livestock Project Reporting
Protocol. We are seeking comment on
E:\FR\FM\10APP2.SGM
10APP2
16564
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the advantages and disadvantages of
using such tools as a model for tool
development and on the utility of
providing such a tool.
The various approaches to monitoring
GHG emissions, as well as specific cost
information, are elaborated in the
Manure Management TSD (EPA–HQ–
OAR–2008–0508–036).
4. Selection of Procedures for Estimating
Missing Data
On the occasion that a facility lacks
sufficient data to determine the
emissions from manure management
over a period of time, we propose that
the facility apply an average facilitylevel value for the missing parameter
from measurements of the parameter
preceding and following the missing
data incident, as specified in the
proposed rule. The proposed rule would
require a complete record of all
parameters determined from company
records that are used in the GHG
emissions calculations (e.g., historical
livestock population data, biogas
destruction data).
For emissions calculation purposes,
EPA considered not deducting CH4
recovery and destruction that was not
recorded, but not including CH4
destruction could greatly overestimate
an entity’s actual CH4 emissions.
5. Selection of Data Reporting
Requirements
EPA proposes that facilities report
CH4 and N2O emissions, along with the
input data to calculate these values.
These data form the basis of the GHG
emission calculations and are needed
for EPA to understand the emissions
data and verify the reasonableness of the
reported data. A full list of data to be
reported is included in proposed 40
CFR part 98, subparts A and JJ.
6. Selection of Records That Must Be
Retained
Records to be retained include
information on animal population,
manure management system types,
animal waste characteristics, and
digester biogas measurements. These
records are needed to allow verification
that the GHG emission monitoring and
calculations were done correctly. A full
list of records to be retained onsite is
included in proposed 40 CFR part 98,
subparts A and JJ.
KK. Suppliers of Coal
1. Definition of the Source Category
Proposed 40 CFR part 98, subpart KK
would require reporting by facilities or
companies that introduce or supply coal
into the economy (e.g., coal mines, coal
importers, and waste coal reclaimers).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
These facilities or companies (in the
case of coal importers and exporters)
would report on the CO2 emissions that
would result from complete combustion
or oxidation of the quantities of coal
supplied. For completeness, this source
category also includes coal exporters.
Facilities that use coal for energy
purposes should refer to proposed 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
Facilities that use coal for non-energy
uses (e.g., as a reducing agent in metal
production such as ferroalloys, zinc,
etc.) should refer to the relevant
subparts of the proposed rule.
Underground coal mine operators who
are included in this subpart should also
refer to proposed 40 CFR part 98,
subpart FF (Underground Coal Mines)
in order to account for any combustion
and fugitive emissions separately, as
described in Sections III and IV of this
preamble. A description of the
requirements related to the conversion
of coal to liquid fuel is covered in
Section V.LL of this preamble.
Coal is a combustible black or
brownish-black sedimentary rock
composed mostly of carbon and
hydrocarbons. It is the most abundant
fossil fuel produced in the U.S. Over 90
percent of the coal used in the U.S. is
used to generate electricity. Coal is also
used as a basic energy source in many
industries, including cement and paper.
In 2006, the combustion of coal for
useful heat and work resulted in
emissions of 2,065.3 million metric tons
CO2, or 29 percent of total U.S. GHG
emissions.
The supply chain for delivering coal
to consumers is relatively
straightforward. It includes coal mines
or importers, in some cases coal
washing or preparation onsite or at
dedicated offsite plants, and transport
(usually by rail) to consumers. The U.S.
typically produces nearly all of its
domestic coal needs; in 2007, domestic
coal production accounted for 97
percent of domestic coal consumption.
A relatively small share of coal
consumed in the U.S. (3 percent in
2007) is imported from other countries,
and a small share of U.S. production is
exported for use abroad (5 percent in
2007).
In determining the most appropriate
point in the supply chain of coal for
reporting potential CO2 emissions, we
considered the following criteria: An
administratively manageable number of
reporting facilities; complete coverage of
coal supply as a group of facilities or in
combination with facilities reporting
under other subparts of the proposed
rule; minimal irreconcilable double-
PO 00000
Frm 00118
Fmt 4701
Sfmt 4702
counting of coal supply; and feasibility
of monitoring or calculation methods.
We are proposing to include all active
coal mines, coal importers, coal
exporters, and reclaimers of waste coal
as reporters under this subpart.
We are proposing to require all
owners or operators of active
underground and surface coal mines to
report under proposed 40 CFR part 98,
subpart KK. There were 1,365 active
coal mines (both underground and
surface mines) operating in the U.S. in
2007, according to the MSHA.
Currently, coal mines routinely monitor
coal quantity and coal quality data for
use in coal sale contracts as well as for
reporting requirements to various State
and Federal agencies.
We are proposing that importers of
coal into the U.S. report under proposed
40 CFR part 98, subpart KK. Reporting
for coal importers is proposed at the
company level, as opposed to the
facility level, because the importers of
record are typically companies, and
these companies currently track and
report imports. Most of the 36 million
tons of coal that were imported to the
U.S. in 2007 were used for power
generation. A small number of electric
utility companies were responsible for
the large majority of coal imports in
2006.93 In many cases, the importing
companies also own and operate
electricity generating or industrial
facilities that would be included as
covered facilities under other subparts
of the proposed rule. Because these
entities already collect much of this
information, EPA believes that the
reporting requirements for importers
would impose a minimal additional
burden.
We are proposing that exporters of
coal report under proposed 40 CFR part
98, subpart KK. In 2007, 59.2 million
tons of coal produced (mined) in the
U.S. were exported. Coal exporters may
include coal mining companies who
directly sell their coal to entities outside
the U.S., or other retailers who export
the coal (typically via barge from one of
several U.S. ports). Coal exports are
included in proposed 40 CFR part 98,
subpart KK so that the total supply of
coal (and associated GHG emissions)
into the U.S. economy is balanced
against the coal that leaves the country.
Typically, coal exporters characterize
the quantity (tons) and heat value of the
coal. Thus, this reporting requirement
would impose a minimal additional
burden on coal exporters.
93 In 2006, the eight largest coal-importing power
generating companies accounted for 87 percent of
total imported coal by electric utilities (FERC Form
423 and EIA 906). Approximately 80 percent of coal
imports were used in the electricity sector in 2006.
E:\FR\FM\10APP2.SGM
10APP2
16565
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
We are proposing that reclaimers of
waste coal report under proposed 40
CFR part 98, subpart KK. In some parts
of the U.S., waste coal that was mined
decades ago and placed in waste piles
is now being actively recovered and
sold to end users. Because this coal is
technically not being ‘‘mined’’ but is
nonetheless entering the U.S. economy
for the first time, facilities that reclaim
or recover such waste coal from waste
coal piles and sell or deliver it to endusers are being included for reporting
under proposed 40 CFR part 98, subpart
KK as waste coal reclaimers. Because
these facilities would need to collect
data on the quantity and quality (e.g.,
heat value) of their product, this
reporting requirement should impose a
minimal additional burden on coal
reclaimers.
We considered but are not proposing
that facilities that convert coking coal
into industrial coke and importers of
coke report under proposed 40 CFR part
98, subpart KK. U.S. coke imports in
2007 constituted only 2.5 million tons
(about 0.2 percent of total U.S. coal
production) and can therefore be
considered negligible. Most
domestically consumed coal-based coke
(87 percent) is derived from
domestically-mined coal or imported
coal, and therefore the inclusion of coal
mines and coal importers in this subpart
already provide for coverage of carbon
contained in the coke (and the potential
CO2 emissions from oxidizing or
combusting the coke). Only 14 percent
of coal-based coke consumed
domestically is imported directly as
coke. Furthermore, coke production is
an energy- and emissions-intensive
process, and these facilities are likely to
be above thresholds for the general
stationary fuel combustion sources
(proposed 40 CFR part 98, subpart C)
and industrial process categories such
as iron and steel, and ferro-alloys.
Therefore, GHG emissions associated
with the combustion or oxidation of
coke imports and domestically
produced coke would already be
included in the actual GHG emissions
reported under those subparts.
We considered but are not proposing
that coal preparation plants located
offsite from coal mines report the
potential CO2 emissions associated with
their processed coal. Some of these
facilities may be included as reporting
facilities under proposed 40 CFR part
98, subpart C for direct emissions from
combustion. An unknown but likely
very small share of coal production
annually requires additional preparation
or washing at an offsite preparation
plant. Typically, only the smaller mines
do not do their preparation onsite. We
are not requiring offsite coal preparation
plants to report under this subpart
because the potential CO2 emissions
from coal supplied by these facilities is
already accounted for by reported data
from coal mines, coal importers, and
waste coal reclaimers.
Instead of requiring coal mines to
report as coal suppliers, we also
considered, but are not proposing, that
rail operators report the quantity of coal
they transport. We have determined that
requiring reporting on coal transport
would add complexity without
increasing the accuracy of information
on potential CO2 emissions associated
with the supply of coal to the U.S.
economy. It is our understanding that,
unlike coal mines or coal importers,
coal transporters do not routinely
collect information about the carbon
content or heating value of the coal they
are transporting, so such reporting
requirements would add to the reporting
burden. Furthermore, in the case of
mine mouth power plants for which the
coal does not travel via rail, rail
transporters would miss this coal
production entirely.
We request comment on the inclusion
of active underground and surface coal
mines, coal importers, coal exporters,
and waste coal reclaimers, and the
exclusion of offsite preparation plants,
coke importers and coke manufacturing
facilities, and coal rail transporters from
reporting requirements under proposed
40 CFR part 98, subpart KK. For
additional background information on
suppliers of coal, please refer to the
Suppliers of Coal TSD (EPA–HQ–OAR–
2008–0508–037).
2. Selection of Reporting Threshold
In considering a threshold for coal
suppliers, we considered the
application of the following emissionsbased thresholds for each affected
company or facility under proposed 40
CFR part 98, subpart KK (e.g., coal mine,
coal importer, coal exporter, or waste
coal reclaimer): 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e
per year. For coal suppliers, these
thresholds would be applied to the CO2
emissions that would result from
complete combustion or oxidation of the
coal produced or supplied into the U.S.
economy, rather than the actual GHG
emissions for the individual facilities or
companies. To provide general
information on how the thresholds
would affect the coal industry, we used
a weighted average carbon content of
1,130 lbs/short ton.94 These thresholds
translate into annual coal production for
a single mine of 532 short tons, 5,321
short tons, 13,303 short tons, and 53,211
short tons, respectively.
Coal Mines. Table KK–1 of this
preamble illustrates the coal mine
emissions and facilities that would be
covered under these various thresholds.
TABLE KK–1. THRESHOLD ANALYSIS FOR COAL MINES
Emissions covered
Total 2007
national
emissions
(million metric
tons CO2e/yr) 1
Threshold level
metric tons CO2e/yr
Total 2007
number of
facilities in the
U.S.
Million metric
tons CO2e/yr 2
2,153
2,153
2,153
2,153
1,365
1,365
1,365
1,365
2,146
2,146
2,144
2,130
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
Facilities covered
Percent
99.7
99.7
99.6
98.9
Number of
facilities 3
1,346
1,237
1,117
867
Percent of
facilities
99
91
82
64
Source: EIA Table FE4 and 2007 MSHA database.
Notes:
(1) 2007 National Emissions (metric tons CO2e) = 2007 Production × U.S. Weighted Average CO2 content (4,143 lbs/short ton)/(2205 lbs/metric ton).
(2) Emissions covered (metric tons CO2e) = sum of coal CO2 emissions for all facilities with metric tons CO2e production greater than the
threshold.
94 Carbon content is found using the weighted
average of CO2 (lbs/MMbtu) from EIA Table FE4
along with the heat content (MMbtu/ton) and
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
production (tons) from the 2007 MSHA database.
The molecular mass ratio of carbon to CO2 (12/44)
PO 00000
Frm 00119
Fmt 4701
Sfmt 4702
is then used to find carbon content from the derived
CO2 (4,143 lbs/short ton).
E:\FR\FM\10APP2.SGM
10APP2
16566
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(3) Facilities covered = total number of facilities with metric tons CO2e production greater than the threshold.
For this rule, we propose to include
all active underground and surface coal
mines, with no threshold. Of the
approximately 1,365 active coal mines
operating in 2007, the 25,000 metric
tons CO2e threshold (corresponding to
1,140.8 million tons of coal production)
would include the largest 1,117 coal
mines and 99.6 percent of U.S. coal
production. All active U.S. coal mines
already report annual (and quarterly)
coal production (based on aggregated
daily production data) to MSHA. The
additional reporting required under this
proposal is the carbon content of the
coal, which can be calculated using the
coal’s higher heating value (HHV) also
referred to as the gross calorific value
(GCV). All active U.S. coal mines
already conduct daily proximate
analysis to record the HHV for coal sales
contracts. An alternative for coal mines
with annual production lower than
100,000 short tons is offered in the
proposed rule to estimate CO2 emissions
using HHV and default values, making
this a very minimal additional reporting
burden. Thus, we have determined that
including all mines as reporters under
proposed 40 CFR part 98, subpart KK
would not significantly increase the
burden on small coal mines. We are
seeking comments on this conclusion.
Coal Importers. As noted above, the
majority of imported coal is imported by
power plants for steam generation of
electricity, with the remainder imported
by other sizeable industrial facilities.
We propose that all coal importers
report, with no threshold. Because most
of the imported coal is brought into the
U.S. by companies owning facilities that
would already be required to report
GHG data to EPA under other subparts
of the proposed 40 CFR part 98, EPA
believes that there would be a minimal
incremental burden associated the
inclusion of all importing companies.
We are seeking comments on this
conclusion.
Coal Exporters. Under proposed 40
CFR part 98, subpart KK, we are
proposing that all coal exporting
companies report, with no threshold.
Coal exporters already collect
information about the quantity and
quality (e.g., heating value) of coal to be
exported. Reporting to us under
proposed 40 CFR part 98, subpart KK
would therefore impose only minimal
additional burden on these companies.
Waste coal reclaimers. Under
proposed 40 CFR part 98, subpart KK,
we are proposing all waste coal
reclaimers report, with no threshold.
Parties that recover this waste coal for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
sale to consumers already collect
information about the quantity and
quality (e.g., heating value) of coal to be
sold. Reporting to us under proposed 40
CFR part 98, subpart KK would
therefore impose only minimal
additional burden on these facilities.
For a full discussion of the threshold
analysis, please refer to the Suppliers of
Coal TSD (EPA–HQ–OAR–2008–0508–
037). For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
We are proposing the reporting of the
amount of coal produced or supplied to
the economy annually, as well as the
CO2 emissions that would result from
complete oxidation or combustion of
this quantity of coal.
The only GHG required to be reported
under this subpart is CO2. Combustion
of coal may also lead to trace quantities
of CH4 and N2O emissions.95 Because
the quantity of CH4 and N2O emissions
are highly variable and dependent on
technology and operating conditions in
which the coal is being consumed
(unlike CO2), we are not proposing that
coal suppliers report on these emission.
We seek comment on whether or not
EPA should use the national inventory
estimates of CH4 and N2O emissions
from coal combustion, and apportion
them to individual coal suppliers based
on the quantity of their products.
We are proposing that coal mines,
coal importers, coal exporters, and
reclaimers of waste coal use a massbalance method to calculate CO2
emissions. The mass balance approach
is based on readily available
information: The quantity of coal (tons),
and the carbon content of the coal (as
determined by the mine, importer,
exporter, or waste reclaimer, according
to the methodology described below).
The formula is simple and can be
automated. The mass-balance approach
is used extensively in national GHG
inventories, and in existing reporting
guidelines for facilities, companies, and
states, such as the WRI/WBCSD GHG
Protocol.
We propose that coal suppliers be
required to report both the total weight
of coal produced or supplied annually
(tons per year), as well as either the
carbon content (carbon mass fraction) or
coal HHV, which can be a proxy for
95 CO , CH , and N O emissions from coal
2
4
2
combustion 2065.3, 0.8, and 10.23 million metric
tons CO2e, respectively.
PO 00000
Frm 00120
Fmt 4701
Sfmt 4702
carbon content. In practice, coal
suppliers routinely and frequently
monitor both the weight and energy
content of coal for contractual purposes
(e.g., daily measurements of tonnage
and analyses of the BTU, sulfur, and ash
content of coal) as well as for reporting
requirements to various State and
Federal agencies. We propose that all
coal suppliers report these routinelycollected data, and use them as a basis
for estimating the CO2 emissions
associated with the coal.
For the purpose of this calculation,
we propose that larger coal mines (i.e.,
coal mines that produce over 100,000
short tons of coal per year) use minespecific, carbon content values.
Generally, the carbon content of coal
can be determined through one of two
procedures. The most accurate method
is to determine the coal’s carbon content
(carbon mass fraction) directly through
ultimate analysis of the coal’s chemical
constituents. An alternative method is
to measure the coal’s energy content
(HHV, which is often expressed in units
of MMBTU per unit weight) and use it
as an indicator of the coal’s carbon
content. This is done by establishing a
statistically significant correlation
between the coal’s heating value and the
carbon content of the coal, and using
this correlation to estimate the carbon
content (carbon mass fraction) of a given
batch of coal with known heating value.
For instance, a linear relationship
between coal heating value and coal
carbon content can be established. This
alternative approach is convenient
because heat value measurements of
coal are taken routinely and frequently
by coal mines, coal importers, coal
exporters, and coal retailers.
For the purpose of proposed 40 CFR
part 98, subpart KK, EPA proposes that
coal mines that produce over 100,000
short tons of coal per year have two
options for reporting the carbon content
of their coal: (1) Daily measurements of
coal carbon content through ultimate
analyses (daily sampling and analyses,
reported as annual weighted average), or
(2) a combination of daily
measurements of coal HHV through
proximate analyses and monthly
measurements of carbon content
through ultimate analyses, using an
established, statistically significant
correlation to estimate the daily
weighted average coal carbon content
(mass fraction), as described in the rule.
We propose that a minimum of one year
of data be used to establish such a minespecific statistically significant
correlation between the coal carbon
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
content (as measured by ultimate
analyses) and coal heating value (as
measured by proximate analyses). We
request comment on this approach,
including the minimum number of data
points necessary to establish a
statistically significant mine-specific
relationship between coal carbon
content and coal HHV, and how often
and under what circumstances should
the statistical relationship be
reestablished. According to MSHA data,
706 mines produced over 100,000 short
tons of coal during 2007 (52 percent of
all mines), accounting for 98 percent of
total production. We propose that a
more stringent method for calculating
carbon content be applied to these larger
mines in order to reduce the uncertainty
of the CO2 data collected.
EPA proposes that coal mines with
annual coal production less 100,000
short tons use either one of the above
approaches for estimating carbon
content, or use a third alternative. This
alternative involves estimating the
coal’s carbon content based only on
daily measurements of coal HHV
through proximate analyses and a
default CO2 emissions factor provided
as described in proposed 40 CFR part
98, subpart KK. EPA has concluded that
this alternative is reasonable because it
would reduce the sampling and
analyses cost burden on these entities,
yet would provide sufficient accuracy
given their relatively small contribution
to total U.S. coal supply. We request
comments on this approach.
EPA proposes that all coal importers,
coal exporters, and reclaimers of waste
coal use any of three above approaches
for estimating carbon content based on
measurements per shipment in place of
daily measurements if preferred. We
seek comment on this measurement
approach.
We propose that the ASTM Method
D5373 should be used as the standard
for all ultimate analyses.
We considered, but are not
recommending, an option to allow all
coal mines to use default coal carbon
content values instead of site-specific
values or measurements. Existing
information available on the variability
of carbon content for coal from USGS,
the U.S. GHG Inventory, EIA’s GHG
Inventory, and the IPCC indicate that
default values introduce considerable
uncertainty into the emissions
calculation. Given the large share of
total GHG emissions represented by use
of coal in the U.S. economy, we view
the direct measurement or estimation of
site-specific carbon content values as
necessary. We seek comment on an
appropriate approach for reporters—
such as importers—who estimate a
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
weighted annual average GCV according
to specified methodology that is not
listed with a corresponding default coal
carbon content value in table KK–1 of
this rule. Further information on various
approaches to monitoring GHG
emissions is elaborated in the Suppliers
of Coal TSD (EPA–HQ–OAR–2008–
0508–037).
4. Selection of Procedures for Estimating
Missing Data
We have determined that some of the
information to be reported by coal
mines, coal importers, coal exporters,
and waste coal reclaimers is routinely
collected as part of standard operating
practices (e.g., coal tonnage). For these
cases, we expect no missing data would
occur.
Typically, coal is weighed using
automated systems on the conveyor belt
or at the loadout facility. In general, the
weighing and sampling of coal at coal
mines are conducted at about the same
time to ensure consistency between
quantity and quality of coal. In this rule,
EPA proposes that the most current
version of NIST Handbook 44 published
by Weights and Measures Division,
National Institute of Standards and
Technology be used as the standard
practice for coal weighing. In cases
where coal supply data are not
available, reporters may estimate the
missing quantity of coal supplied, using
documentation for the quantity of coal
received by end-users or other
recipients. For any periods during
which mine scales are not operational or
records are unavailable, estimates of
coal production at the mine may be
estimated using an average of values of
production immediately preceding and
following the missing data period, or
other standard industry practices, such
as estimating the volume of coal
transported by rail cars and coal density
to estimate total coal weight in tons. For
additional background information on
coal weighing, please refer to the
Suppliers of Coal TSD (EPA–HQ–OAR–
2008–0508–037).
In cases where carbon content or HHV
measurements are missing, reporters
may estimate the missing value based
on an weighted average value for the
previous seven days.
5. Selection of Data Reporting
Requirements
We propose that coal mines, coal
importers, coal exporters, and waste
coal reclaimers each report to us
annually on the CO2 emissions that
would result from complete combustion
or oxidation of coal produced during the
previous calendar year.
PO 00000
Frm 00121
Fmt 4701
Sfmt 4702
16567
Information from coal mines should
be reported at the facility level, and
should include mine name, mine MSHA
identification number, name of
operating company, coal production
coal rank or classification (e.g.,
anthracite, bituminous, sub-bituminous,
or lignite), facility-specific measured
values of coal carbon content or HHV
that are used to calculate CO2 emissions,
and the estimated CO2 emissions (metric
tons CO2/yr).
Coal importers, coal exporters, and
waste coal reclaimers should report
company name and technical contact
information (name, e-mail, phone).
Coal importers should report at the
corporate level. Coal importers already
measure coal quantity for each shipment
entering the U.S. Importers generally
conduct proximate analyses on each
shipment to assure that coal quality
meets the coal specification under
contract. Some importers may also
conduct ultimate analysis. Coal
importers should report the quantity of
coal imported, coal rank or
classification (e.g., anthracite,
bituminous, sub-bituminous, or lignite),
country of origin, origin-specific
measured values of coal carbon content
and HHV that are used to calculate CO2
emissions, and estimated CO2
emissions.
Coal exporters should report, at the
corporate level, the quantity of coal
exported, coal rank or classification
(e.g.anthracite, bituminous, subbituminous, or lignite), name and
MSHA identification number of mine of
origin, country of destination, minespecific measured values of coal carbon
content or HHV that are used to
calculate CO2 emissions, and estimated
CO2 emissions (metric tons CO2/yr).
Waste coal reclaimers should report,
at the facility level, the quantity of coal
recovered or reclaimed (tons/yr), coal
rank or classification (e.g., anthracite,
bituminous, sub-bituminous, or lignite),
name of mine of origin, state of origin,
mine-specific measured values of coal
carbon content or HHV that are used to
calculate CO2 emissions, and estimated
CO2 emissions.
A full list of data to be reported is
contained in the rule. These data to be
reported form the basis of calculating
potential CO2 emissions associated with
the total supply of coal into the U.S.
economy. Therefore, these data are
necessary for us to understand the
emissions data and to verify the
reasonableness of the reported
emissions.
We considered, but are not proposing
an option in which we would obtain
facility-specific data for coal production
through access to existing Federal
E:\FR\FM\10APP2.SGM
10APP2
16568
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Government reporting databases, such
as those maintained by MSHA. We have
determined that comparability and
consistency in reporting processes
across all facilities included in the
entire rule is vital, particularly with
respect to timing of submission,
reporting formats, QA/QC, database
management, missing data procedures,
transparency and access to information,
and recordkeeping. In addition, EPA’s
methodological approach requires
information that is not currently
reported to Federal agencies, such as
facility-specific information on coal
quality (e.g., coal carbon content or
heating value).
6. Selection of Records That Must Be
Retained
A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and KK. EPA
proposes that the following records
specific to suppliers of coal be kept
onsite: Daily production of coal, annual
weighted average of coal carbon content
values (if measured), annual weighted
average of coal HHV, calibration records
of any instruments used onsite (e.g., if
coal analyses are done onsite), and
calibration records of scales or other
equipment used to weigh coal.
These records consist of data that are
directly used to calculate the potential
CO2 emissions reported. We have
concluded that these records are
necessary to enable verification that the
GHG emissions monitoring and
calculation were done correctly.
LL. Suppliers of Coal-Based Liquid Fuels
1. Definition of the Source Category
We are proposing to include facilities
that produce coal-based liquids as well
as importers and exporters of coal-based
liquids in this source category. Owners
and operators of coal-to-liquids
facilities, or ‘‘producers’’, importers,
and exporters would report on the CO2
emissions that would result from
complete combustion or oxidation of the
quantities of coal-based liquids supplied
to or exported from the U.S. economy.
Producers would report at the facility
level; importers and exporters would
report at the corporate level.
The carbon in coal-based liquids
would already be captured in the
reporting from domestic coal suppliers
and importers, but we believe that it is
important for climate policy
development to have additional
information on a unique and potentially
growing source of liquid fuels. As
discussed in Sections III and IV of this
preamble, emissions resulting from the
combustion and other uses of coal-based
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
liquids, as well as emissions generated
in the production of coal-based liquids,
are addressed in other sections of the
preamble, particularly Section V.C of
this preamble (General Stationary Fuel
Combustion Sources), Section V.D
(Electricity Generation), and Section
V.FF (Underground Coal Mines).
The output fuels from coal-to-liquids
processes are compositionally similar to
standard petroleum-based products e.g.,
gasoline, diesel fuel, jet fuel, light gases
etc. The most common processes for
converting coal to liquids are direct and
indirect liquefaction. In the direct
process, coal is processed directly to
liquid. In the indirect process, coal is
first gasified, and then liquefied.
Once manufactured, the supply chain
for coal-based liquids to consumers is
basically the same as it is for refined
petroleum products. Liquid fuels are
moved from the manufacturing facility
to a terminal, at which point they may
be blended or mixed with other
products, before entering the
downstream distribution chain.
Imported coal-based liquids would enter
the U.S. in the same way that refined
and semi-refined petroleum products
enter the country. In determining the
most appropriate point in the supply
chain of coal-based liquids, we followed
the decision-making process applied to
suppliers of petroleum products
discussed in Section V.MM of this
preamble, and selected coal-to-liquids
facilities (analogous to refineries), and
importers and exporters. For further
information, see the Coal to Liquids
TSD (EPA–HQ–OAR–2008–0508–038).
We request comment on the approach of
establishing a separate source category
and subpart for suppliers of coal-based
liquids, and the selection of coal-toliquids facilities and corporate
importers and exporters of coal-based
liquids. We also request comment on
whether or not importers of liquid-based
fuels are likely to have the necessary
information with which to distinguish
coal-based liquids from conventional
petroleum-based liquids.
2. Selection of Reporting Threshold
In developing the threshold for
suppliers of coal-based liquids, EPA
considered the emissions-based
threshold of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e
per year, but was limited by the fact that
there are very few existing facilities.
According to DOE, there is one facility
operating in the world, one U.S. facility
in the engineering phase, and thirteen
PO 00000
Frm 00122
Fmt 4701
Sfmt 4702
facilities proposed in the U.S.96 Given
that conversion of coal to liquids is a
highly energy intensive process that is
viable only on a large scale, we propose
that any coal-to-liquids facility
operating in the U.S. would be required
to report.
We also propose that all importers
and exporters of coal-based liquids
report under this rule. While the
number of existing importers and
exporters is very small in comparison to
importers and exporters of petroleum
products, importers of coal-based
liquids would be required to track fuel
quantities as part of routine business
operations, and report to DOE and other
Federal agencies.
For further information, see the Coal
to Liquids TSD (EPA–HQ–OAR–2008–
0508–038). For specific information on
costs, including unamortized first year
capital expenditures, please refer to
section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring
Methods
We are proposing that producers,
importers, and exporters of coal-based
liquids calculate potential CO2
emissions associated with coal-based
liquids on the basis of a mass balance
approach. Under this approach, CO2
emissions would be determined by
applying a carbon content value to the
quantity of each coal-based liquid
supplied. The formulae are simple and
can be automated. For carbon content,
reporters can either use the default CO2
emission factors for standard petroleumbased fuels in proposed 40 CFR part 98,
subpart MM or develop their own
factors.97 Reporters that choose to
substitute their own batch- or facilityspecific values for density and carbon
share of individual coal-based liquids,
and develop their own CO2 emission
factors, must do so according to the
proposed ASTM standards and
procedures discussed in proposed 40
CFR part 98, subpart MM. While carbon
content of coal-based liquids may differ
from petroleum products, we believe the
default emission factors for petroleum
products in proposed 40 CFR part 98,
subpart MM can be used for estimating
emissions from coal-based liquids. We
request comment on this approach, the
appropriateness of the proposed default
CO2 emission factors, and ways to
improve these default values. We also
96 Coal Conversion—Pathway to Alternate Fuels.
C. Lowell Miller. 2007 EIA Energy Outlook
Modeling and Data Conference. Washington, DC,
March 28, 2007.
97 For a discussion of the benefits and
disadvantages of default carbon factors versus direct
measurement see Section V.MM.3 of this preamble.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
request comment on the appropriateness
of the proposed sampling and analysis
standards and methods for developing
batch- or facility-specific CO2 emission
factors, especially the methods for
determining carbon share.
4. Selection of Procedures for Estimating
Missing Data
We have determined that the
information to be reported by suppliers
of coal-based liquids is routinely
collected by facilities and entities as
part of standard operating practices, and
therefore 100 percent data availability
would be required. Typically, coalbased liquids would be metered directly
at multiple stages. In cases where
metered data are not available, reporters
may estimate the missing volumes based
on contracted maximum daily quantities
and known conditions of receipt and
delivery during the period when data
are missing.
5. Selection of Data Reporting
Requirements
We propose that producers, importers,
and exporters report CO2 emissions
directly to EPA on an annual basis.
Suppliers would report potential CO2
emissions disaggregated by fuel types.
We considered but did not propose an
option in which we would obtain
facility-specific data for coal-based
liquids through access to existing
Federal government reporting databases,
such as those maintained by EIA. EPA
believes that comparability and
consistency in reporting processes
across all facilities included in the
entire rule are vital, particularly with
respect to timing of submission,
reporting formats, QA/QC, database
management, missing data procedures,
transparency and access to information,
and recordkeeping.
6. Selection of Records That Must Be
Retained
A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and LL.
MM. Suppliers of Petroleum Products
1. Definition of the Source Category
We are proposing that refineries as
well as importers and exporters of
petroleum products be included in this
source category. Owners or operators of
petroleum refineries, or ‘‘refiners,’’ and
importers that introduce petroleum
products into the U.S. economy would
be required to report on the CO2
emissions associated with the complete
combustion or oxidation of their
petroleum products. Additionally, both
refiners and importers would be
required to report on biomass
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
components of their petroleum products
as well as NGLs they supply to the
economy, and refiners would be
required to report on certain types of
feedstock entering their facility. Refiners
would report at the facility level, and
importers would report at the corporate
level. Exporters of petroleum products
are also included in this source category
in order for us to appropriately account
for petroleum products that are
produced but not consumed in the U.S.
and therefore do not result in direct CO2
emissions in the U.S. Exporters would
report on the petroleum products and
NGLs they export, including the
biomass components of the petroleum
products, at the corporate level.
End users of petroleum products are
addressed in other sections of this
preamble, such as Section V.C (General
Stationary Fuel Combustion Sources),
and direct, onsite emissions at
petroleum refineries are covered in
Section V.Y of this preamble.
The total estimated GHG emissions
resulting from the combustion of
petroleum products in the U.S. in 2006
was 2,417 million metric tons CO2e,
according to the 2008 U.S. GHG
Inventory. It is estimated that 75 percent
of the combustion-related CO2
emissions from petroleum use in the
U.S. comes from the transportation
sector. The next largest sector is
industrial use (15 percent), and the
commercial, residential, and electricity
generation sectors make up the
remainder.
Petroleum products are ultimately
consumed in one of two ways: Either
through combustion for energy use, or
through a non-energy use such as
petrochemical feedstocks or lubricants.
Combustion of petroleum products
produces CO2 and lesser amounts of
CH4 and N2O, which are in almost all
cases emitted directly into the
atmosphere. Some non-energy uses of
fuels, such as lubricants, also result in
oxidation of carbon and CO2 emissions.
This process may occur immediately
upon first use or, in the case of
biological deterioration, over time.
Carbon in other petroleum products,
such as asphalts and durable plastics,
may remain un-oxidized for long
periods unless burned as fuel or
incinerated as waste.
The following list, while not
comprehensive, illustrates the types of
products that EPA considers to fall
under the category of petroleum
products:
• Motor vehicle and nonroad gasoline
and diesel fuels.
• Jet fuel and kerosene.
• Aviation gasoline.
• Propane and other LPGs.
PO 00000
Frm 00123
Fmt 4701
Sfmt 4702
16569
• Home heating oil.
• Residual fuel oil.
• Petrochemical feedstocks.
• Asphalt.
• Petroleum coke.
• Lubricants and waxes.
Reporting Parties. When considering
the extent of the definition of this
source category and who should be
required to report under this rule, our
approach was first to identify all parties
within the petroleum product supply
chain. We considered parties that
function primarily in upstream
petroleum production, such as oil
drillers and well owners, as well as
petroleum refiners and importers of
refined and semi-refined products. We
also considered parties located even
further downstream, such as terminal
operators, oxygenate blenders of
transportation fuel, blenders of
blendstock, transmix processors, and
retail gas station owners. In addition, we
considered pipeline owners and
operators.
As discussed earlier in this preamble,
one of our objectives when determining
which entities would fall within a
source category was to identify logical
data reporting points or groups of
facilities that were relatively small in
number but that could provide a
comprehensive set of data for the
particular source category. Of all the
parties that make up the petroleum
products supply chain, we have
concluded that petroleum refiners 98
and importers and exporters of semirefined and refined petroleum products
are the most appropriate parties to
report to EPA under this source category
and that the data they can report would
be comprehensive.
There are approximately 150
operating petroleum refineries in the
U.S. and its territories. Our thresholds
analysis in Section V.MM.2 of this
preamble, however, only reflects data on
the 140 refineries that reported
atmospheric distillation capacity to EIA
(at DOE) in 2006. Petroleum products
from these refineries account for
approximately 90 percent of U.S.
consumption. Given the coverage
provided by a relatively small number
of facilities, we propose that all refiners
be subject to the reporting requirements
for petroleum product suppliers and
that they report to EPA on a facility-byfacility basis. For refiners that trade
semi-refined and refined petroleum
products between facilities, leading to a
98 A petroleum refinery is any facility engaged in
producing gasoline, kerosene, distillate fuel oils,
residual fuel oils, lubricants, asphalt (bitumen) or
other products through distillation of petroleum or
through redistillation, cracking, or reforming of
unfinished petroleum derivatives.
E:\FR\FM\10APP2.SGM
10APP2
16570
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
possible risk of double-counting in
coverage, we are proposing a straightforward accounting method in Section
V.MM.5 of this preamble to address this
possibility.
To account for refined and semirefined petroleum products that are not
produced at U.S. refineries, we are
proposing to include importers under
this source category. Importers currently
report to EPA on petroleum products
designated for transportation or nonroad mobile end-uses. This rule would
include all importers regardless of enduse designations. The number of
importing companies varies from year to
year, but it is typically on the order of
100 to 200.
We are also proposing to include
under this source category exporters of
refined and semi-refined petroleum
products in order to have information
on petroleum products that are
produced but not consumed in the U.S.
The rationale to include reporting from
exporters is to be able to account for
petroleum products that are consumed
in other countries and that do not
contribute to direct CO2 emissions in
the U.S.
Many refiners are also importers and
exporters of petroleum products. EPA is
proposing that such refiners separately
report data on the petroleum products
that they produce on a facility-byfacility basis and report at a corporate
level the petroleum products they
import or export. The rationale for this
separate reporting is that we are
generally proposing coverage at the
facility level where feasible (e.g.,
refineries) and proposing corporate
reporting only where facility-level
coverage may not be feasible (e.g.,
importers and exporters). In addition,
the separation simplifies reporting in
cases where a company that owns or
operates multiple refineries may have a
consolidated arrangement for imports of
refined and semi-refined products
destined for its refineries and for other
consumers, or for exports.
We considered but are not proposing
to include parties that are involved in
upstream petroleum production. We
believe the number of domestic oil
drillers and well owners is prohibitively
large and represents only a portion of
the amount of crude petroleum that is
processed into finished products to be
used in the U.S.
We are not proposing to include retail
gas station owners and oxygenate
blenders to report to EPA as suppliers
of petroleum products. Retail gas station
owners and oxygenate blenders mostly
handle transportation fuel and fuel used
in small engines. Because we are
interested in GHG emissions from all
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
petroleum products combusted or
consumed in the U.S. and can obtain
information on such products on a more
aggregated basis directly from refiners
and importers, we are proposing to
exclude retail gas station owners and
oxygenate blenders from reporting
under this rule.
We are not proposing to include
operators of terminals or pipelines,
blenders of blendstocks, or transmix
processors in this source category
because we believe that refiners and
importers can provide comprehensive
information on petroleum products
supplied in the U.S. with a lower risk
of double-counting petroleum products.
A given quantity of refined or semirefined petroleum product may pass
between multiple terminals and
blending facilities, so asking terminal or
pipeline operators, blenders of
blendstock, or transmix processors to
report information on incoming and
outgoing products would likely result in
unreliable data for estimating GHG
emissions from petroleum products.99
Liquid fossil fuel products can be
derived from feedstocks other than
petroleum crude, such as coal and
natural gas. Suppliers of coal-based
products are covered under Section
V.LL of this preamble, Suppliers of
Coal-Based Liquid Fuels. Primary
suppliers of natural gas-based products
are covered in Section V.NN of this
preamble, Suppliers of Natural Gas and
Natural Gas Liquids. We are proposing
to require all reporters in this source
category to report data on the NGLs they
supply to or export from the economy
because these products may not
currently be captured under Section
V.NN of this preamble, Suppliers of
Natural Gas and NGLs. The natural-gas
related reporting requirements are
discussed in Section V.MM.5 of this
preamble.
This section of the preamble is
focused on suppliers of petroleum
products, so EPA is not proposing to
include primary 100 suppliers of
renewable fuels, such as fuel derived
from biomass like grains, animal fats
and oils, or waste, under this source
category. However, as described in
Section IV.B of this preamble (Reporting
by fuel and industrial gas suppliers), we
note that we are not proposing to
require suppliers of biomass-based fuels
to report on their products anywhere
under this rule, except as discussed
99 See Section V.MM.3 of this preamble regarding
a method for accounting for trade between
refineries.
100 Refiners, exporters, and importers of
petroleum products could, in some cases, be
suppliers of renewable fuels but their supply of
renewable fuels is not the focus of this subpart.
PO 00000
Frm 00124
Fmt 4701
Sfmt 4702
below for petroleum suppliers, due to a
longstanding accounting convention
adopted by the IPCC, the UNFCCC, the
U.S. GHG Inventory, and many other
State and regional GHG reporting
programs where emissions of CO2 from
the combustion of renewable fuels are
distinguished from emissions of CO2
from combustion of petroleum or other
fossil-based products. Under such
convention, potential emissions from
the combustion of biomass-based fuels
are accounted for at the time of
feedstock harvest, collection, or
disposal, not at the point of fuel
combustion. Nonetheless, we seek
comment on this approach.
Certain petroleum products can be coprocessed or blended with renewable
fuels. We are proposing a method in
Section V.MM.5 of this preamble
whereby petroleum product suppliers
report data that allows EPA to
distinguish between the biomass and
fossil fuel-based carbon in their
products.
2. Selection of Reporting Threshold
In assessing the appropriateness of
applying a threshold to refiners (at the
facility level) and importers (at the
corporate level), we calculated the
volume of finished gasoline that would
contain enough carbon that, when
combusted or oxidized, would produce
1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e. We took the
volume of finished gasoline as an
example of how much of a refined or
semi-refined product would result in a
given level of CO2 emissions. These data
are summarized in Table MM–1 of this
preamble.
TABLE MM–1. THRESHOLD ANALYSIS
FOR FINISHED GASOLINE
Threshold level metric tons
CO2/yr
1,000 .....................................
10,000 ...................................
25,000 ...................................
100,000 .................................
Total volume
of gasoline
bbls/yr
2,564
25,641
64,103
256,410
Based on the calculations in Table
MM–1 of this preamble and data on the
annual volume of petroleum products
that refiners and importers are currently
reporting to the EIA, EPA estimated the
number of refineries and importers that
would meet each of the four selected
threshold levels. The results of this
analysis are summarized below.
E:\FR\FM\10APP2.SGM
10APP2
16571
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Refineries. Data on the typical
production levels for refineries 101
demonstrate that each of the thresholds
considered would cover all domestic
refineries (see Table MM–2 of this
preamble). This conclusion is based on
the result that all refineries would
exceed the thresholds for gasoline alone,
and therefore would also exceed the
thresholds for all products combined.
For this reason, we are proposing to
cover all petroleum refineries.
TABLE MM–2. THRESHOLD ANALYSIS FOR REFINERIES
Total national
emissions 1 2 metric tons CO2/yr
Threshold level metric tons
CO2e/yr
1,000 ............................................
10,000 ..........................................
25,000 ..........................................
100,000 ........................................
Total number
of facilities 3
2,447,738,368
2,447,738,368
2,447,738,368
2,447,738,368
140
140
140
140
Emissions covered
Metric tons CO2/yr
Facilities covered
Percent
2,447,738,368
2,447,738,368
2,447,738,368
2,447,738,368
Number
100
100
100
100
Percent
140
140
140
140
100
100
100
100
1 These
constitute total emissions from all petroleum products ex refinery gate. The total includes only CO2 emissions.
CO2 emissions for all refineries are based on applying product-specific default carbon contents to production of each product.
number represents the total number of refineries that reported atmospheric distillation capacity to EIA in 2006.
2 Estimated
3 This
Small Refiners. In recent EPA fuel
rulemakings, we have provided
temporary exemptions from our
regulations for small refiners, defined as
producers of transportation fuel from
crude oil that employed an average of
1,500 people or fewer over a given oneyear period and with a corporateaverage crude oil capacity of 155,000
barrels per calendar day or less. Such
small refiner exemptions were provided
to allow small refiners extra time to
meet standards or comply with new
regulations. This exemption was based
on an assumption that to require small
refiners to comply with new regulations
on the same schedule as larger refiners
would put them at a disadvantage if
required to seek the same capital and
administrative resources being sought
by their larger competitors. Because of
the nature of this reporting rule,
however, we are not proposing any
temporary exemptions for small
refiners. We do not believe complying
with this rule will require additional
resources that might put small refiners
at an unfair disadvantage. All refiners
would already be reporting data to EPA,
regardless of size, because all refineries
meet the proposed reporting threshold
in proposed 40 CFR part 98, subpart Y
for direct onsite emissions.
Importers. Data on importers of
petroleum products in 2006, the most
recent year available, show that 78
percent of the importing companies
exceeded the 25,000 metric tons CO2e/
yr reporting threshold and that some
importing companies did not meet the
1,000 metric tons CO2e/yr threshold (see
Table MM–3 of this preamble). While 22
percent of importers supplied less than
the amount of products that, when
combusted or oxidized, would have
resulted in 25,000 metric tons CO2/yr,
data on the amount and types of
petroleum products is information that
all importers maintain as part of their
normal business operations. Therefore
we believe the burden of reporting the
required information listed in Section
V.MM.5 of this preamble is minimal
since no additional monitoring
equipment has to be installed to comply
with this rule. In addition, the quantity
of products imported by a company may
vary greatly from year to year.
Furthermore, our proposed definition
for petroleum products for importers
and exporters in Subpart A excludes
asphalt and road oil, lubricants, waxes,
plastics, and plastic products. For these
reasons, we are proposing that all
importers of petroleum products be
required to report to EPA, and we seek
comment on our proposed definition of
petroleum products as it applies to
importers.
TABLE MM–3. THRESHOLD ANALYSIS FOR IMPORTERS
Total national
emissions 1
metric tons
CO2/yr
Threshold level metric tons CO2e/yr
<1000 ...................................................................
1,000 ....................................................................
10,000 ..................................................................
25,000 ..................................................................
100,000 ................................................................
1 These
Emissions covered
Total number
of importers
393,294,390
393,294,390
393,294,390
393,294,390
393,294,390
224
224
224
224
224
Metric tons
CO2/yr
393,294,390
393,291,916
393,171,144
392,895,841
389,628,252
Percent
100
>99.9
>99.9
99.9
99
Companies covered
Number
224
219
193
175
120
Percent
100
98
86
78
54
constitute total emissions from all product imports. Analysis is based on EIA’s Company Reports for 2006.
Exporters. Due to the limited
availability of export data, EPA did not
conduct a threshold analysis for
petroleum products exporters. However,
based on the type of information that
exporters must maintain as part of their
normal business operations, we believe
that the incremental burden of reporting
this information to EPA would be
minimal. Considering this information
and the importance of being able to
account for petroleum products
produced but not combusted or
oxidized in the U.S., EPA is proposing
that all exporters report on their
exported petroleum products.
Furthermore, our proposed definition
for petroleum products for importers
101 To simplify our reporting threshold analysis,
EPA omitted roughly 10 refineries that meet our
definition of a petroleum supplier but did not
report any atmospheric distillation capacity to EIA.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00125
Fmt 4701
Sfmt 4702
and exporters in Subpart A excludes
asphalt and road oil, lubricants, waxes,
plastics, and plastic products. We seek
comment on this proposal.
De Minimis Exports and Imports. We
are seeking comment on whether or not
to establish a de minimis level, either in
terms of total product volume or
potential CO2 emissions, to eliminate
E:\FR\FM\10APP2.SGM
10APP2
16572
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
any reporting burden for parties that
may import or export a small amount of
petroleum products on an annual basis.
We also note that in the proposed rule
some importers and exporters may not
be required to report their onsite
combustion, process, and/or fugitive
emissions under other sections of the
proposed rule because their combined
emissions do not meet the applicable
thresholds.
For a full discussion of the threshold
analysis, please refer to the Suppliers of
Petroleum Products TSD (EPA–HQ–
OAR–2008–0508–039). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Rather than directly measuring
emissions from the combustion or
consumption of their products,
suppliers of petroleum products would
need to estimate the potential emissions
of their non-crude feedstocks and
products based on volume and
characteristic information. Therefore
product volume metering and sampling
would be of utmost importance to
accurately calculate potential CO2
emissions.
Volume measurement. EPA is
proposing to require specific industrystandard test methods for flow meters
and tank gauges for measuring volumes
of feedstocks and products. For ultrasonic flow meters, we propose to require
the test method described in AGA
Report No. 9 (2007); for turbine meters,
American National Standards Institute,
ANSI/ASME MFC–4M–1986; for orifice
meters, American National Standards
Institute, ANSI/API 2530 (also called
AGA–3) (1991); and for coriolis meters,
ASME MFC–11 (2006). For tank gauges,
we propose to require the following test
methods: API–2550: Measurements and
Calibration of Petroleum Storage Tanks
(1965), API MPMS 2.2: A Manual of
Petroleum Measurement Standards
(1995), or API–653: Tank Inspection,
Repair, Alteration and Reconstruction,
3rd edition (2008).
We propose that all flow meters and
tank gauges must be calibrated prior to
monitoring under this rule using a
method published by a consensus
standards organization (e.g., ASTM,
ASME, American Petroleum Institute, or
NAESB), or using calibration procedures
specified by the flow meter
manufacturer. Product flow meters and
tank gauges would be required to be
recalibrated either annually or at the
minimum frequency specified by the
manufacturer.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Carbon content determination. To
translate data on petroleum product,
NGLs, and biomass types and quantities
into estimated potential GHG emissions,
it is necessary either to estimate or
measure the carbon content for each
product type. For this proposal, we
reviewed the existing CO2 emission
factors developed by EIA and used in
the U.S. GHG Inventory, and we
researched the sampling and test
methods that would be required for
direct measurement of carbon content
by reporters.
We also considered the benefits and
disadvantages of using default carbon
content factors and of using direct
measurements of carbon content.
Default CO2 emission factors have been
used extensively in the U.S. GHG
Inventory, in inventories of other
nations, and in corporate reporting
guidance; they are simple and cost
effective for evaluating GHG emissions
from common classes of biomass and
fossil fuel types (e.g., ethanol, motor
gasoline, jet fuel, distillate fuel, etc). It
is also possible to combine default CO2
emission factors to develop alternative
factors for fuel reformulations by
averaging according to weight. Some
products, however, can have multiple
chemical compositions due to different
feedstock, blending components, and/or
refinery processes, which can lead to
variations in carbon content. Default
CO2 emission factors for common
chemical compositions of common
products cannot account for the full
variability of carbon content in
petroleum, natural gas, and biomass
products.
Direct measurements would provide
the most accurate determination of
carbon content. It is relatively
expensive, however, to design and
implement a program for regular
sampling and testing for carbon content
across the variety of products produced
at refineries. Many products are
homogeneous because they must meet
‘‘minimum’’ specifications (e.g., jet
fuel), and the use of direct
measurements may not lead to
noticeable improvements in accuracy
over default CO2 emission factors.
Based on this information, we are
proposing that for purposes of
estimating emissions, reporters could
either use the default CO2 emission
factors for each product type published
in proposed 40 CFR part 98, subpart
MM or, in the case of petroleum
products and NGLs, develop their own
factors. Reporters that choose to
substitute their own values for density
and carbon share of individual
petroleum products and NGLs, and
develop their own CO2 emission factors
PO 00000
Frm 00126
Fmt 4701
Sfmt 4702
would be required to sample each
product monthly for the reporting year
and to test the composite sample at the
end of the reporting period using ASTM
D1298 (2003), ASTM D1657–02(2007),
ASTM D4052–96(2002)el, ASTM
D5002–99(2005), or ASTM D5004–
89(2004)el for density, as appropriate,
and ASTM D5291(2005) or ASTM
D6729–(2004)el for carbon share, as
appropriate (see Suppliers of Petroleum
Products TSD (EPA–HQ–OAR–2008–
0508–039)). For suppliers of seasonal
gasoline, reporters would be required to
take a sample each month of the season
and test the composite sample at the
end of the season.
We request comment on this
approach. We request comment on
whether reporters should be allowed to
combine default CO2 emission factors to
develop alternative factors for fuel
reformulations according to the volume
percent of each fuel component, and if
so using what methodology. We also
request comment on the appropriateness
and adequacy of the proposed default
CO2 emission factors—including factors
for biomass products—and ways to
improve these default values. For full
documentation of the derivation of the
proposed default factors, please refer to
the Suppliers of Petroleum Products
TSD (EPA–HQ–OAR–2008–0508–039).
In addition, we request comment on
the appropriateness of the proposed
sampling and analysis standards and
methods for developing CO2 emission
factors for petroleum products and
NGLs, especially the methods for
determining carbon share. Specifically,
we seek comment on specific ASTM or
other industry standards that would be
more appropriate for sampling
petroleum products and NGLs to
determine carbon share. Finally, we
request comment on potential methods
to determine carbon share of biomass
products.
The various approaches to monitoring
GHG emissions are elaborated in the
Suppliers of Petroleum Products TSD
(EPA–HQ–OAR–2008–0508–039).
4. Selection of Procedures for Estimating
Missing Data
Under this proposal, we are
suggesting methods for estimating data
that may be missing from different
source categories for various reasons.
Petroleum product suppliers would
need to estimate any missing data on the
amount of petroleum products or NGLs
supplied or exported, and the quantity
of the crude and non-crude feedstocks,
including biomass, consumed. In most
cases, the source category would be
missing data due to monitoring
equipment malfunction or shutdown.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
We have determined that the
information to be reported by petroleum
fuel suppliers is collected as part of
standard operating practices, and expect
that any missing data would be
negligible. Typically, products are
metered directly at multiple stages, and
billing systems require rigorous
reconciliation of data. In cases where
metered data are not available, we are
proposing that reporting parties may
estimate the missing volumes based
either on the last valid data point they
recorded or on an average of two valid
data points based on their established
procedures for purposes of product
tracking and billing. We seek comment
on the appropriateness and adequacy of
our proposed procedures for estimating
missing data. Petroleum product
suppliers reporting under this rule
would be required to keep sufficient
records to verify any volume estimates
(see Section V.MM.6 of this preamble).
5. Selection of Data Reporting
Requirements
We are proposing that suppliers of
petroleum products be required to
report the type, volume, and CO2
emissions associated with the complete
combustion or oxidation of each
individual petroleum product and NGL
they supply to the economy, export, or
use as a feedstock annually. We are also
proposing to require reporting on the
total CO2 emissions of all products they
supply to the economy annually, minus
any emissions associated with noncrude feedstocks, including biomass,
and renewable fuel blended in a
petroleum product. Additionally, we are
proposing to require refiners to report
information on the volume, API gravity,
sulfur content, and country of origin of
each crude oil batch used as feedstock
at a refinery. Finally, we are proposing
to require reporting on the volume of
diesel fuel that is most likely to be used
in the onroad mobile source sector.
The only GHG required to be reported
under proposed 40 CFR part 98, subpart
MM is CO2. Combustion of petroleum
products may also lead to trace
quantities of CH4 and N2O emissions.102
The amounts of CH4 and N2O are
dependent on factors other than fuel
characteristics such as combustion
temperatures, air-fuel mixes, and use of
pollution control equipment. These
other factors vary significantly across
and within the major categories of
petroleum product end-uses. EPA bases
national estimates of CH4 and N2O for
the U.S. GHG Inventory on bottom-up
102 CO , CH and N O emissions from combustion
2
4
2
of petroleum products were 1900, 3.1, and 34.1
million metric tons CO2e, respectively.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
data, such as penetration of control
technologies and distance traveled for
on-highway mobile sources.103 We seek
comment on whether or not EPA should
use the national inventory estimates of
CH4 and N2O emissions from petroleum
product combustion and apportion them
to individual petroleum product
suppliers based on the quantity of their
product.
Data related to products supplied to
or exported from the economy. We are
proposing that petroleum product
suppliers use a mass-balance method to
calculate CO2 emissions, which is used
extensively in national GHG inventories
and in existing reporting guidelines for
facilities, companies, and states, such as
the WRI/WBCSD GHG Protocol.104 The
mass balance approach is based on
readily available information: The
volume of fuel, which is typically
tracked by suppliers, and the carbon
content of the fuel, i.e., mass of carbon
per volume of fuel (the carbon content
of the petroleum product is also referred
to as the CO2 emission factor). The
formula to apply this method is simple
and can be automated.105 Carbon
content, where not measured directly,
can be estimated using other readily
available data and literature values.
There is substantial trade and transfer
of products between refiners, between
importers and refiners, and between
other parties. The products supplied by
one refiner might in some cases serve as
the feedstock for another refiner. To
avoid double-counting of emissions, we
are proposing an elaboration of the
mass-balance approach for use by
refiners. Under this elaborated
approach, to account for the fact that
any non-crude feedstock 106 entering a
refiner’s facility would have already
been reported by the non-crude
feedstock’s source (such as an importer
or another refiner), the refiner would
measure and report the potential CO2
emissions from the non-crude feedstock,
but then subtract the amount from the
overall CO2 emissions they report.
We are proposing that suppliers
report to EPA the types of products and
quantities of products sold during the
reporting period or otherwise
transferred to another facility, in the
103 2008 U.S. GHG Inventory, Annex 3—
Methodological Descriptions for Additional Source
or Sink Categories. pp. A–106 to A–120.
104 See The Greenhouse Gas Protocol (GHG
Protocol) https://www.ghgprotocol.org/; the 2008
U.S. Inventory https://www.epa.gov/climatechange/
emissions/downloads/08_Energy.pdf, and the 2006
IPCC Guidelines https://www.ipcc-nggip.iges.or.jp/
public/2006gl/vol2.html.
105 The generic formula is CO = Fuel Quantity *
2
Carbon Content * 44/12.
106 This could include both petroleum- and
natural gas-based products.
PO 00000
Frm 00127
Fmt 4701
Sfmt 4702
16573
case of refiners, or corporate entity, in
the case of importers and exporters.
This information underlies the proposed
CO2 emissions calculations. By focusing
on petroleum products sold versus
produced, we would avoid doublecounting products, especially semirefined products, that would either be
used onsite by the facility to generate
energy or that would be reused as a
feedstock at some point in the facility’s
production process.
We are not proposing that petroleum
product suppliers collect new
information on those petroleum
products which may be used or
converted by other entities into longlived products that are not oxidized or
combusted, or oxidized slowly over long
periods of time (e.g., plastics). A
comprehensive and rigorous system for
tracking the fate of non-energy
petroleum products and their various
end-uses is beyond the scope of this
rule, and would require a much more
burdensome reporting obligation for
petroleum product suppliers. However,
at some point, we may need to address
the question of non-emissive end uses of
petroleum products as part of future
climate policy development. We request
comment on our proposal to require
petroleum product suppliers to report
the CO2 emissions associated with
products that could potentially have
non-emissive end-uses. We also request
comment on ways in which nonemissive end-uses could be tracked and
reported.
Data related to crude feedstocks. We
are proposing that refiners report basic
information to EPA on the crude oil
feedstock type, API gravity, sulfur
content and country of origin during the
reporting period. This basic information
on the feedstock characteristics would
provide useful information to EPA to
assess the lifecycle GHG emissions
associated with petroleum refining.
Data related to non-crude petroleum
and natural gas feedstocks. As
discussed previously, in order to
minimize double-counting of non-crude
petroleum products and NGLs, we
would require refiners to report the
volume and CO2 emissions of any noncrude petroleum and natural gas
feedstock that was acquired from an
outside facility. We are not proposing to
require reporting of products produced
at the facility and recycled back into
processing. In the event that a reporter
cannot determine whether a feedstock is
petroleum-or natural gas-based, we are
proposing to have the reporter assume
the product is petroleum-based. We
request comment on methods for
distinguishing between natural gas- and
petroleum-based feedstock.
E:\FR\FM\10APP2.SGM
10APP2
16574
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Data related to co-processed biomass
and blended biomass-based fuels. We
are proposing to require reporters to
provide information on the biogenic
portion of petroleum products under
two circumstances discussed below. We
are proposing these reporting
requirements to ensure that EPA can
distinguish between potential emissions
of carbon from biogenic sources (i.e.,
biomass) and from non-biogenic sources
(i.e., fossil fuel). We believe it is
important to make this distinction
because CO2 emissions from biogenic
sources are traditionally accounted for
at the time of harvest, collection, or
disposal, rather than the point of fuel
combustion.
First, we are proposing to require
refiners to report information related to
biomass that is co-processed with a
petroleum feedstock (crude or noncrude) to produce a product that would
be supplied to the economy. We
propose that refiners report the volume
of and estimated CO2 emissions
associated with both the biomass and
petroleum-based portions of these
products. Refiners would then subtract
the estimated CO2 emissions from the
biomass portion from their total CO2
emissions calculation. We are not
proposing to require refiners to report
on CO2 emissions from biomass they
combust onsite or co-process with a
petroleum feedstock to produce a
product that they combust onsite; these
emissions are addressed in Section V.Y
of this preamble.
Second, in the case where a reporter
supplies or exports a petroleum product
that is blended with a biomass-based
fuel, we are proposing only to require
CO2 emissions information on the
petroleum-based portion of the product
along with the volume of the biomassbased fuel. This reporting requirement
would also apply to a refiner that
receives a blended fuel (e.g., gasoline
with ethanol) as feedstock to be further
refined or otherwise used onsite. We are
also assuming that all reporters would
know the percent volume of the
biomass-based component of any
product. We seek comment on this
assumption and on any necessary
methods for distinguishing between
biomass- and petroleum-based
components of blended fuels.
Under this proposal, we are proposing
to require reporters to calculate and
report CO2 emissions from products
derived from co-processing biomass and
petroleum feedstocks outside their
operations as if the products were
entirely petroleum-based. We are not
requiring reporters to report information
on products that were derived entirely
from biomass. We seek comment on this
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
proposed approach towards biomass
reporting.
Carbon Content. We are proposing
that petroleum product suppliers that
directly measure the batch-or facilityspecific density or carbon share of their
products report the density and carbon
content values along with the testing
and sampling standards they use for
each product.107 We are not proposing
that reporters that choose to use the
default carbon content values provided
in the proposed 40 CFR part 98, subpart
MM be required to report these values
since they can easily be back-calculated
with data on volume and CO2
emissions.
Designated End-use. Although not
required as a direct input to the massbalance equation for estimating total
emissions, EPA is also interested in
collecting data on designated end-use
(such as for use in a highway vehicle
versus a stationary boiler) of petroleum
products for effective policy
development. EPA recognizes that
petroleum product suppliers do not
always have full knowledge of the
ultimate end-use of their products. We
evaluated the potential end-uses that
petroleum product suppliers could
know, including end-use designations
required by EPA’s transportation fuel
regulations,108 and determined that
reporters should be able to identify
diesel fuel intended for use on highway
since it must contain less than 15 ppm
of sulfur and should not contain dyes or
markers associated with nonroad and
stationary fuel. We recognize, however,
that some of this fuel may ultimately be
used in nonroad and stationary sectors.
We request comment on this proposal,
on the extent to which this and other
refinery gate (ex refinery) and importer
end-use designations reflect actual enduse consumption patterns, and other
options EPA could pursue to track the
combustion-related end-uses of
petroleum products.
Reporting to EIA. We realize that most
petroleum product suppliers report
much of the relevant fuel quantity
information to EIA on a monthly,
quarterly, or annual basis. During
development of this proposal, EPA
consulted with EIA on its existing
reporting programs and discussed the
feasibility of sharing this information
through an interagency agreement,
rather than requiring reporting parties to
107 Proposed 40 CFR part 98, subpart MM
identifies the specific ASTM standards that
reporters must use, but allows discretion for the
reporter to select the most appropriate standard.
108 Current regulations require refiners and
importers to designate diesel fuel (40 CFR
80.598(a)(2)).
PO 00000
Frm 00128
Fmt 4701
Sfmt 4702
report the same information multiple
times to the Federal government.
However, we have concluded that
comparability and consistency in
reporting processes across all facilities
included in the entire rule is vital,
particularly with respect to timing of
submission, reporting formats, QA/QC,
database management, missing data
procedures, transparency and access to
information, and recordkeeping. In
addition, all refineries would be
reporting emissions from petroleum
refining processes under proposed 40
CFR part 98, subpart Y. Finally, as noted
above, we are requesting readily
available information from petroleum
product suppliers and do not consider
reporting information to more than one
Federal agency an undue burden for
these industries. We thus considered
but are not proposing an option in
which EPA obtains facility-specific data
for suppliers of petroleum products
through access to existing Federal
government reporting databases, such as
those maintained by EIA. However, in
order to reduce the reporting burden
placed on industry, we would consider
information that refiners and importers
already report to EIA with respect to
units and frequency, for example, when
crafting the reporting requirements for
refiners, importers, and exporters under
the final rule.
Reporting to EPA’s Office of
Transportation of Air Quality. EPA
currently collects a variety of
information associated with the
production and use of most
transportation fuels in the U.S. in order
to ensure compliance with existing fuel
regulations and standards. Over the
course of many years, EPA has
developed a reporting system for its
transportation fuels programs that
incorporates a number of compliance
and enforcement mechanisms. For
example, all reporting parties must
register their facilities with EPA and in
many cases use EPA’s dedicated
reporting web portal, the CDX, to submit
their reports. We review reports to
identify reporting errors (e.g. incorrect
report formats or missing data) but also
require reporting parties to self-report
any errors or anomalies in their data.
For some of our existing transportation
fuels reporting programs, we employ the
use of annual attest engagements, audits
of the reporting parties’ records by an
independent certified public accountant
or certified internal auditor, to help
ensure that the data submitted in reports
to EPA reflect data maintained in the
reporting parties’ records.
For purposes of this rule, we are
interested in minimizing the additional
reporting burden on reporters by
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
utilizing existing reporting and
verification systems, such as EPA’s
transportation fuel programs reporting
protocols, as appropriate. We request
comments on ways to take advantage of
existing reporting and verification
programs, particularly those related to
transportation fuels. Specifically, as
noted in Section IV.J.3 of this preamble,
we are seeking comment on requiring
annual attest engagements for all
reporters under proposed 40 CFR part
98, subpart MM. In addition, whereas
the proposed deadline for annual report
submission is March 31 following the
reporting year for all reporters under
this rule, we seek comment on an
alternative deadline of February 28
following the reporting year for annual
reports from suppliers of petroleum
products. This deadline would align
with the submission deadline for annual
compliance reports under several
existing EPA fuels programs.
6. Selection of Records That Must Be
Retained
We are proposing that reporters under
this source category must maintain all of
the following records: copies of all
reports submitted to EPA under this
rule, records documenting the type and
quantity of petroleum products and
NGLs supplied to or exported from the
economy, records documenting the
type, characteristics, and quantity of
purchased feedstocks, including crude
oil, LPGs, biomass, and semi-refined
feedstocks, records documenting the
CO2 emissions that would result from
complete combustion or oxidation of the
petroleum products, NGLs, and
biomass, and sampling and analysis
records related to all batch-or facilityspecific carbon contents developed and
used in reporting to EPA.
These records should contain data
directly used to calculate the emissions
that are reported and are necessary to
enable verification that the CO2
emissions monitoring and calculations
were done correctly. These records
would also consist of information used
to determine the required characteristics
of crude feedstocks.
NN. Suppliers of Natural Gas and
Natural Gas Liquids
1. Definition of the Source Category
This subpart would require reporting
by facilities and companies that
introduce or supply natural gas and
NGLs into the economy (e.g., LDCs).
These facilities and companies would
report the CO2 emissions that would
result from complete combustion or
oxidation of the quantities of natural gas
and NGLs supplied (e.g., as a fuel).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Combustion and other uses of natural
gas are addressed in other subparts,
such as proposed 40 CFR part 98,
subpart C (General Fuel Stationary
Combustion Sources).
Natural gas is a combustible gaseous
mixture of hydrocarbons, mostly CH4. It
is produced from wells drilled into
underground reservoirs of porous rock.
Natural gas withdrawn from the well
may contain liquid hydrocarbons and
nonhydrocarbon gases. The natural gas
separated from these components at gas
processing plants is considered ‘‘dry’’.
Dry natural gas is also known as
consumer-grade natural gas. In 2006, the
combustion of natural gas for useful
heat and work resulted in 1,155.1
million metric tons CO2e emissions out
of a total of 7,054.2 million metric tons
CO2e of GHG emissions in the U.S.
In addition to being combusted for
energy, natural gas is also consumed for
non-energy uses in the U.S. The nonenergy applications of natural gas are
diverse, and include feedstocks for
petrochemical production, ammonia,
and other products. In 2006, emissions
from non-energy uses of natural gas
were 138 million metric tons CO2e.
The supply chain for delivering
natural gas to consumers is complex,
involving producers (i.e., wells),
processing plants, storage facilities,
transmission pipelines, LNG terminals,
and local distribution companies. In
developing the proposed rule, we
concluded that inclusion of all natural
gas suppliers as reporters would not be
practical from an administrative
perspective, nor would it be necessary
for complete coverage of the supply of
natural gas. In determining the most
appropriate point in the supply chain of
natural gas, we applied the following
criteria: An administratively
manageable number of reporting
facilities; complete coverage of natural
gas supply as a group of facilities or in
combination with facilities reporting
under other subparts of this rule;
minimal irreconcilable double-counting
of natural gas supply; and feasibility of
monitoring or calculation methods.
Based on these criteria, we are
proposing to include LDCs for deliveries
of dry gas, and natural gas processing
facilities for the supply of NGLs as
reporters under this source category.
LDCs receive natural gas from the large
transmission pipelines and re-deliver
the gas to end users on their systems, or,
in some cases, re-deliver the natural gas
to other LDCs or even other
transmission pipelines. Importantly,
LDCs keep records on the amount of
natural gas delivered to their customers.
In 2006, LDCs delivered about 12.0
trillion cf or 60 percent of the total 19.9
PO 00000
Frm 00129
Fmt 4701
Sfmt 4702
16575
trillion cf delivered to consumers. The
balance of the natural gas is delivered
directly to large end users in industry
and for power generation. Most of these
large end users would already be
included as reporting facilities for direct
GHG emissions because their emissions
exceed the respective emissions
threshold for their source category.
LDCs meter the amount of gas they
receive and meter and bill for the
deliveries they make to all end-use
customers or other LDCs and pipelines.
Some of the end-use customers may be
large industrial or electricity generating
facilities that would be included under
other subparts for direct emissions
related to stationary combustion. LDCs
already report their total deliveries to
DOE as well as to State regulators. There
are approximately 1,207 LDCs in the
U.S.109
Natural gas processing facilities
(defined as any facility that extracts or
recovers NGLs from natural gas,
separates individual components of
NGLs using fractionation, or converts
one form of natural gas liquid into
another form such as butane to
isobutene using isomerization process)
take raw untreated natural gas from
domestic production and strip out the
NGLs, and other compounds. The NGLs
are then sold, and the processed gas is
delivered to transmission pipelines.110
According to EIA, processors generated
about 638 million barrels of NGLs, in
2006, which is 69 percent of NGLs
supplied in the U.S. Processors meter
the NGLs they produce and deliver to
pipelines. These data are reported to
DOE.
We are not proposing that processing
plants report supply of dry natural gas
to transmission pipelines. While the
processing industry in 2006 delivered
an estimated 13.8 trillion cf of
processed, pipeline quality gas into the
pipeline system, an estimated 30
percent of dry natural gas goes directly
from production fields to the
transmission pipelines, completely bypassing processing plants. In the interest
of increasing coverage, we considered
but decided not to propose including
109 This number includes all LDCs that report to
EIA on Form 176, and includes separate operating
companies owned by a single larger company, as for
example Niagara Mohawk, a LDC in New York,
owned by National Grid, which also owns other
LDCs in New York and New England. For the
purposes of this rule, LDCs are defined as those
companies that distribute natural gas to ultimate
end users and which are regulated as separate
entities by state public utility commissions.
110 This definition of processors does not include
field gathering and boosting stations, and is
therefore narrower in scope than the definition
provided earlier in the preamble for the oil and gas
sector.
E:\FR\FM\10APP2.SGM
10APP2
16576
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
production wells producing pipeline
quality natural gas (i.e., not needing
significant processing) due to the large
number of potential facilities affected.
We considered but are not proposing
to include the approximately 448,641
(in 2006) production wells in the U.S.
as covered facilities. Producers
routinely monitor production to predict
sales, to distribute sales revenues to
working interest owners, pay royalties,
and pay State severance taxes. These
data are reported regularly to State
agencies. At the national level, however,
inclusion of producers would be
administratively difficult and would
include many small facilities. EIA
collects reports from a subset of larger
producers in key States, but relies on
State data to develop comprehensive
aggregated national statistics.
We considered but are not proposing
to include interstate and intrastate
pipelines. Pipeline operators transport
almost all of the natural gas consumed
in the U.S. including both domestically
produced and imported natural gas.
While there are a relatively modest
number of transmission pipelines,
approximately 160, and the operators
meter flows and report these data to
DOE, their inclusion as reporters would
introduce significant complications. The
U.S. pipeline network is characterized
by interconnectivity, in which natural
gas moves through multiple pipelines
on its way to the consumers. Given the
hundreds of receipt and delivery points
and the interconnections with a
multiplicity of other pipelines,
processing plants, LDCs, and end users,
a substantial amount of double-counting
errors would be introduced. A time- and
resource-intensive administrative effort
by EPA and reporting companies would
be required annually in an attempt to
correct this double-counting.
We are also not proposing to include
importers of natural gas as reporting
facilities. Natural gas is imported by
land via transmission pipelines
(primarily from Canada), and as LNG via
a small number of port terminals
(predominantly on the East and Gulf
coasts). Imported natural gas ultimately
is delivered to consumers by LDCs or
sent directly to high volume consumers
who would report under other subparts
of proposed 40 CFR part 98.
EPA requests comment on the
inclusion of LDCs and processing
plants, and the exclusion of other parts
of the natural gas supply and
distribution chain. For additional
background information on suppliers of
natural gas, please refer to the Suppliers
of Natural Gas and NGLs TSD (EPA–
HQ–OAR–2008–0508–040).
2. Selection of Reporting Threshold
In developing the reporting threshold
for LDCs and natural gas processors,
EPA considered emissions-based
thresholds of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e
per year. For natural gas suppliers, these
thresholds are applied on the amount of
CO2 emissions that would result from
complete combustion or oxidation of the
natural gas. These thresholds translate
into 18,281 thousand cf, 182,812
thousand cf, 457,030 thousand cf, and
1,828,120 thousand cf of natural gas,
respectively.
Table NN–1 of this preamble
illustrates the LDC emissions and
facilities that would be covered under
these various thresholds.
TABLE NN–1. THRESHOLD ANALYSIS FOR LDCS
Threshold level metric tons CO2e/yr
Total national
emissions
metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
Emissions covered
Total number
of facilities
632,100,851
632,100,851
632,100,851
632,100,851
We propose to include all LDCs as
reporters in this source category. Of the
approximate 1,207 LDCs, the 25,000
metric tons CO2e threshold would
capture the 365 largest LDCs and 98
percent of the natural gas that flows
1,207
1,207
1,207
1,207
Metric tons
CO2e/yr
Percent
632,004,022
630,106,725
627,543,971
619,456,607
through them. The remaining LDCs
already report annual throughput to EIA
in form EIA 176. Thus, inclusion of all
LDC’s does not require collection of new
information. Comments on this
conclusion are requested.
Facilities covered
Number
99.98
99.68
99.28
98.00
Percent
1,022
521
365
206
85
43
30
17
Table NN–2 of this preamble
illustrates the NGL emissions and
number of processing facilities that
would be covered under these various
thresholds.
TABLE NN–2. THRESHOLD ANALYSIS FOR NGLS FROM PROCESSING PLANTS
Threshold level metric tons CO2e/yr
Total national
emissions
metric tons
CO2e/yr
1,000 ........................................................
10,000 ......................................................
25,000 ......................................................
100,000 ....................................................
164,712,077
164,712,077
164,712,077
164,712,077
We propose there be no reporting
threshold for natural gas processing
plants. Each natural gas processing
plant is already required to report the
supply (beginning stocks, receipts, and
production) and disposition (input,
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Emissions covered
Total number
of facilities
566
566
566
566
Metric tons
CO2e/yr
PO 00000
Frm 00130
Fmt 4701
Percent
164,704,346
164,404,207
163,516,733
157,341,629
shipments, fuel use and losses, and
ending stocks) of NGLs monthly on EIA
Form 816. Processing plants are also
required to report the amounts of
natural gas processed, NGLs produced,
shrinkage of the natural gas from NGLs
Sfmt 4702
Facilities covered
100
100
99
96
Number
466
400
347
244
Percent
82
71
61
43
extraction, and the amount of natural
gas used in processing on an annual
basis on EIA Form 64A.
For a full discussion of the threshold
analysis, please refer to the Suppliers of
Natural Gas and NGLs TSD (EPA–HQ–
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
OAR–2008–0508–040). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
Under this subpart, we are proposing
reporting the amount of natural gas and
NGLs produced or supplied to the
economy annually, as well as the CO2
emissions that would result from
complete oxidation or combustion of
this quantity of natural gas and NGLs.
The only GHG required to be reported
under this subpart is CO2. Combustion
of natural gas and NGLs may also lead
to trace quantities of CH4 and N2O
emission.111 Because the quantity of
CH4 and N2O emissions are small,
highly variable and dependent on
technology and operating conditions in
which the fuel is being consumed
(unlike CO2), we are not proposing that
natural gas suppliers report on these
emissions. We seek comment on
whether or not EPA should use the
national inventory estimates of CH4 and
N2O emissions from natural gas
combustion, and apportion them to
individual natural gas suppliers based
on the quantity of their product. We
request comments on this conclusion.
We are proposing that LDCs and
natural gas processing plants use a
mass-balance method to calculate CO2
emissions. The mass balance approach
is based on readily available
information: The quantity of fuel (e.g.,
thousand cf, barrels, mmBtus), and the
carbon content of the fuel. The formula
is simple and can be automated. The
mass-balance approach is used
extensively in national GHG
inventories, and in existing reporting
guidelines for facilities, companies, and
States, such as the WRI/WBCSD GHG
Protocol.
For carbon content, we have prepared
two look-up tables listing default CO2
emission factors of natural gas and
natural gas liquid. These emission
factors are drawn from published
sources, including the American
Petroleum Institute Compendium, EIA,
and the U.S. GHG Inventory.
Where natural gas processing plants
extract and separate individual
components of NGLs, the facilities
should report carbon content by
individual component of the NGLs. In
cases where raw NGLs are not
separated, the processing plants should
report carbon content for the raw NGLs.
111 In
2006, CO2, CH4 and N2O emissions from
natural gas combustion were 1,155.1, 1.0, and 0.6
MMTCO2e, respectively.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
LDCs and natural gas processing plants
can substitute their own values for
carbon content provided they are
developed according to nationallyaccepted ASTM standards for sampling
and analysis.
We considered but do not propose an
option in which LDCs and natural gas
processing plants would be required to
sample and analyze natural gas and
NGLs periodically to determine the
carbon content. Given the close
correlation between carbon content and
BTU value of natural gas and NGLs, and
the availability of BTU information on
these products, EPA believes that
periodic sampling and analysis would
impose a cost on facilities but would not
result in improved accuracy of reported
emissions values. We request comment
on an approach in which natural gas
suppliers would be required to develop
facility- and batch-specific carbon
contents through periodic sampling and
analysis. The various approaches to
monitoring GHG emissions are
elaborated in the Suppliers of Natural
Gas and NGLs TSD (EPA–HQ–OAR–
2008–0508–040).
4. Selection of Procedures for Estimating
Missing Data
EPA has determined that the
information to be reported by LDCs and
gas processing plants is routinely
collected by facilities as part of standard
operating practices, and expects that
any missing data would be negligible.
Typically, natural gas amounts are
metered directly at multiple stages, and
billing systems require rigorous
reconciliation of data. In cases where
metered data are not available, reporters
may estimate the missing volumes based
on contracted maximum daily quantities
and known conditions of receipt and
delivery during the period when data
are missing.
5. Selection of Data Reporting
Requirements
We propose that LDCs and gas
processing plants report CO2 emissions
directly to EPA on an annual basis.
LDCs would also report CO2 emissions
disaggregated into categories that
represent residential consumers,
commercial consumers, industrial
consumers, and electricity generating
facilities. Further information would be
provided on the facilities to which LDCs
deliver greater than 460,000 thousand cf
of natural gas during the calendar year,
which would be used by EPA to check
and verify information on facilities
covered under other subparts of this
PO 00000
Frm 00131
Fmt 4701
Sfmt 4702
16577
rule because of their onsite stationary
combustion or process emissions.112
Natural gas processing plants would
report CO2 emissions disaggregated by
individual components of NGLs
extracted and separated, where
applicable. Where raw NGLs are not
separated into individual components,
plants should report CO2 emissions for
raw NGLs.
We considered but are not proposing
an option in which EPA obtained
facility-specific data for natural gas and
NGLs through access to existing Federal
government reporting databases, such as
those maintained by EIA. We have
concluded that comparability and
consistency in reporting processes
across all facilities included in the
entire rule is vital, particularly with
respect to timing of submission,
reporting formats, QA/QC, database
management, missing data procedures,
transparency and access to information,
and recordkeeping. In addition, large
natural gas processing plants would
already be included as reporting
facilities under proposed 40 CFR
98.2(a)(2), therefore there is minimal
burden in reporting the additional
information proposed under this
subpart. Finally, as noted above, we are
requesting readily available information
from LDCs and natural gas processing
facilities, and do not consider reporting
information to more than one Federal
agency to place an undue burden on
these industries.
6. Selection of Records That Must Be
Retained
Records that must be kept include
quantity of individual fuels supplied,
BTU content, carbon content
determined, flow records and/or invoice
records for customers with amount of
natural gas received, type of customer
receiving natural gas (so the
disaggregated report by category can be
checked), and data for determining
carbon content for natural gas
processing plants. These records are
necessary to enable verification that the
GHG monitoring and calculations were
done correctly. Records related to the
end-user (e.g., ammonia facility) are
required to allow us to reconcile data
reported by different facilities and
entities, and to ensure that coverage of
natural gas supply and end-use is
comprehensive.
A full list of records that must be
retained onsite is included in proposed
40 CFR part 98, subparts A and NN.
112 460,000 thousand cf/year is a conservative
estimate of the amount of dry natural gas that when
fully combusted would produce at least 25,000
metric tons of CO2.
E:\FR\FM\10APP2.SGM
10APP2
16578
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
OO. Suppliers of Industrial GHGs
1. Definition of the Source Category
The industrial gas supply category
includes facilities that produce N2O or
fluorinated GHGs,113 importers of N2O
or fluorinated GHGs, and exporters of
N2O or fluorinated GHGs. These
facilities and entities are collectively
referred to as ‘‘suppliers of industrial
GHGs’’.
Under the proposed40 CFR part 98,
subpart OO, if you produce fluorinated
GHGs or N2O, you would be required to
report the quantities of these gases that
you produce, transform (use as
feedstocks in the production of other
chemicals), destroy, or send to another
facility for transformation or
destruction. Importers and exporters of
bulk fluorinated GHGs and N2O would
be required to report the quantities that
they imported or exported and the
quantities that they imported and sold
or transferred to another person for
transformation or destruction. As
described in Sections III and IV of this
preamble, emissions from general
stationary fuel combustion sources and
fugitive emissions from fluorinated gas
production are addressed separately
(Sections V.C and V.L of this preamble).
Fluorinated GHGs. Fluorinated GHGs
are man-made gases used in a wide
variety of applications. They include
HFCs, PFCs, SF6, NF3, fluorinated
ethers, and other compounds such as
perfluoropolyethers. CFCs and HCFCs
also contain fluorine and are GHGs, but
both the production and consumption
(production plus import minus export)
of these ODS are currently being phased
out and otherwise regulated under the
Montreal Protocol and Title VI of the
CAA. We are not proposing
requirements for ODS under proposed
40 CFR part 98.
Fluorinated GHGs are powerful GHGs
whose ability to trap heat in the
atmosphere is often thousands to tens of
thousands times as great as that of CO2,
on a pound-for-pound basis. Some
fluorinated GHGs are also very long
lived; SF6 and PFCs have lifetimes
ranging from 3,200 to 50,000 years.114
HFCs are the most commonly used
fluorinated GHGs, they are used
primarily as a replacement for ODS in
a number of applications, including airconditioning and refrigeration, foams,
fire protection, solvents, and aerosols.
PFCs are used in fire fighting and to
manufacture semiconductors and other
electronics. SF6 is used in a diverse
113 Please see the proposed definition of
fluorinated GHG near the end of this section.
114 IPCCC SAR available at: https://www.ipcc.ch/
ipccreports/assessments-reports.htm.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
array of applications, including
electrical transmission and distribution
equipment (as an electrical insulator
and arc quencher) and in magnesium
casting operations (as a cover gas to
prevent oxidation of molten metal). NF3
is used in the semiconductor industry,
increasingly to reduce overall
semiconductor GHG emissions through
processes such as NF3 remote cleaning
and NF3 substitution during in-situ
cleaning. Fluorinated ethers (HFEs and
HCFEs) are used as anesthetics (e.g.,
isofluorane, desflurane, and
sevoflurane) and as heat transfer fluids
(e.g., the H-Galdens).
In 2006, 12 U.S. facilities produced
over 350 million metric tons CO2e of
HFCs, PFCs, SF6, and NF3. More
specifically, 2006 production of HFCs is
estimated to have exceeded 250 million
metric tons CO2e while production of
PFCs, SF6, and NF3 was estimated to be
almost 100 million metric tons CO2e.
We estimate that an additional 6
facilities produced approximately 1
million metric tons CO2e of fluorinated
anesthetics.
Fluorinated GHGs are imported both
in bulk (contained in shipping
containers and cylinders) and in
products. For further information, see
the Bulk Imports and Exports of
Fluorinated Gases TSD (EPA–HQ–OAR–
2008–0508–042) and the Imports of
Fluorinated GHGs in Products TSD
(EPA–HQ–OAR–2008–0508–043). EPA
estimates that over 110 million metric
tons CO2e of bulk HFCs, PFCs, and SF6
were imported into the U.S. in 2007 by
over 100 importers (PIERS, 2007). In
CO2e terms, SF6 and NF3 each made up
about one third of this total, while HFCs
accounted for one quarter and PFCs
made up the remainder. Several other
fluorinated GHGs may be imported in
smaller quantities, including fluorinated
ethers such as the H-Galdens and
anesthetics such as desflurane (HFE–
236ea2), isoflurane (HCFE–235da2), and
sevoflurane.
A variety of products containing
fluorinated GHGs are imported into the
U.S. Imports of particular importance
include pre-charged air-conditioning,
refrigeration, and electrical equipment
and closed-cell foams. Pre-charged airconditioning and refrigeration
equipment contains a full or partial
(holding) charge of HFC refrigerant,
while pre-charged electrical equipment
contains a full or partial charge of SF6
insulating gas. Closed-cell foams
contain HFC blowing agent.
We estimate that in 2010,
approximately 18 million metric tons
CO2e of fluorinated GHGs would be
PO 00000
Frm 00132
Fmt 4701
Sfmt 4702
imported in pre-charged equipment.115
In 2006, an additional 2.5 million metric
tons CO2e of fluorinated GHGs were
imported in closed-cell foams. Together,
these imports are expected to constitute
between five and ten percent of U.S.
consumption of fluorinated GHGs.
Once produced or imported,
fluorinated GHGs can have hundreds of
millions of downstream emission
points. For example, the gases are used
in almost all car air conditioners and
household refrigerators and in other
ubiquitous products and applications.
Thus, tracking emissions of these gases
from all downstream uses would not be
practical.
Nitrous oxide. N2O is a clear,
colorless, oxidizing gas with a slightly
sweet odor. N2O is a strong GHG with
a GWP of 310.116
N2O is primarily used in carrier gases
with oxygen to administer more potent
inhalation anesthetics for general
anesthesia and as an anesthetic in
various dental and veterinary
applications. In this application, it is
used to treat short-term pain, for
sedation in minor elective surgeries and
as an induction anesthetic. The second
main use of N2O is as a propellant in
pressure and aerosol products, the
largest application being pressurepackaged whipped cream. In smaller
quantities, N2O is also used as an
oxidizing agent and etchant in
semiconductor manufacturing, an
oxidizing agent (with acetylene) in
atomic absorption spectrometry, an
oxidizing agent in blowtorches used by
jewelers and others, a fuel oxidant in
auto racing, and a component of the
production of sodium azide, which is
used to inflate airbags.
Two companies operate a total of five
N2O production facilities in the U.S..
These facilities produced an estimated
4.5 million metric tons CO2e of N2O in
2006.
N2O may be imported in bulk or
inside products. We estimate that
approximately 300,000 metric tons CO2e
of bulk N2O were imported into the U.S.
in 2007 by 18 importers. Products that
may be imported include several of
those listed above, particularly preblended anesthetics and aerosol
115 The number of refrigeration and AC units
imported in 2010 was assumed to equal the number
of units imported in 2006. The refrigeration and AC
units imported in 2006 were pre-charged with both
HFCs and HCFCs. (HCFCs are ozone-depleting
substances that are regulated under the Montreal
Protocol and are exempt from the proposed
definition of fluorinated GHG.) However, by 2010,
EPA expects that all imported refrigeration and AC
units will be charged with HFCs, because imports
pre-charged with HCFCs will not be permitted
starting in that year.
116 IPCCC SAR.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
products such as pressure-packaged
whipped cream.
Further information on N2O supply
and import can be found in the
Suppliers of Industrial GHGs TSD
(EPA–HQ–OAR–2008–0508–041).
Selection of Reporting Facilities and
Types of Data to be Reported. Because
fluorinated GHGs and N2O have an
extremely large number of relatively
small downstream sources, reporting of
downstream emissions of these gases
would be incomplete, impractical, or
both. On the other hand, the number of
upstream producers, importers, and
exporters is comparatively small, and
the quantities that would be reported by
individual gas suppliers are often quite
large. Thus, upstream reporting is likely
to be far more complete and costeffective than downstream reporting.
For these reasons, we are proposing to
require upstream reporting of the
quantities required to estimate U.S.
consumption of N2O and fluorinated
gases. ‘‘Consumption’’ is defined as the
sum of the quantities of chemical
produced in or imported into the U.S.
minus the sum of the quantities of
chemical transformed (used as a
feedstock in the production of other
chemicals), destroyed, or exported from
the U.S.
In developing this proposed rule, we
reviewed a number of protocols that
track chemical consumption, its
components (production, import,
export, etc.), or similar quantities. These
protocols included EPA’s Stratospheric
Ozone Protection regulations at 40 CFR
part 82, the EU Regulation on Certain
Fluorinated Greenhouse Gases (No. 842/
2006), the Australian Commonwealth
Government Ozone Protection and
Synthetic Greenhouse Gas Reporting
Program, EPA’s Chemical Substances
Inventory Update Rule at 40 CFR
710.43, EPA’s Acid Rain regulations at
40 CFR part 75, the TRI Program, and
the 2006 IPCC Guidelines.117
We reviewed these protocols both for
their overall scope and for their specific
requirements for monitoring and
117 We also reviewed other programs, including
the DOE’s 1605(b) Program, EPA’s Climate Leaders
Program, and the European Commission’s Article 6
reporting requirements, but we found that these
programs did not monitor consumption or its
components.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
reporting. The monitoring requirements
are discussed in Section V.OO.3 of this
preamble. The protocols whose scopes
were most similar to the one proposed
for industrial gas supply were EPA’s
Stratospheric Protection Program, the
EU Regulation on Certain Fluorinated
Greenhouse Gases, the Australian
Synthetic Greenhouse Gas Reporting
Program, and EPA’s Chemical
Substances Inventory Update Rule. All
four of these programs require reporting
of production and imports, and the first
three also require reporting of exports.
In addition, the EU regulation and
EPA’s Stratospheric Ozone Protection
Program require reporting of the
quantities of chemicals (ODS)
transformed or destroyed. In general, the
proposed requirements in this rule are
based closely on those in EPA’s
Stratospheric Ozone Protection
Program. By accounting for all chemical
flows into and out of the U.S., including
destruction and transformation, this
approach results in an estimate of
consumption that is more closely
related to actual U.S. emissions than are
estimates of consumption that do not
account for all of these flows.
Proposed Definition of Fluorinated
GHGs. We propose to define
‘‘Fluorinated GHG’’ as SF6, NF3, and any
fluorocarbon except for ODS as they are
defined under EPA’s stratospheric
protection regulations at 40 CFR part 82,
subpart A. In addition to SF6 and NF3,
this definition would include any
hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated
linear, branched or cyclic alkane, ether,
tertiary amine or aminoether, any
perfluoropolyether, and any
hydrofluoropolyether.
EPA is proposing this definition
because HFCs, PFCs, SF6, NF3, and
many fluorinated ethers are known to
have significant GWPs. (For a list of
these GWPs, see Table A–1 of proposed
40 CFR part 98, subpart A.) In addition,
although not all fluorocarbons have had
their GWPs evaluated, any fluorocarbon
with an atmospheric lifetime greater
than one year is likely to have a
significant GWP due to the radiative
properties of the carbon-fluorine bond.
As discussed above, ODS are
excluded from the proposed definition
PO 00000
Frm 00133
Fmt 4701
Sfmt 4702
16579
of fluorinated GHG because they are
already regulated under the Montreal
Protocol and Title VI of the CAA.
EPA requests comment on the
proposed definition. EPA also requests
comment on two other options for
defining or refining the set of
fluorinated GHGs to be reported. The
first option would permit a fluorocarbon
to be excluded from reporting if (1) the
GWP for the fluorocarbon were not
listed in Table A–1 of proposed 40 CFR
part 98, subpart A or in any of the IPCC
Assessment Reports or World
Meteorological Organization (WMO)
Scientific Assessments of Ozone
Depletion, and (2) the producer or
importer of the fluorocarbon could
demonstrate, to the satisfaction of the
Administrator, that the fluorocarbon
had an atmospheric lifetime of less than
one year and a 100-year GWP of less
than five. In general, we expect that new
fluorocarbons would be used in
relatively low volumes. For such
chemicals, a GWP of five may be a
reasonable trigger for reporting.
The second option would be to
require reporting only of those
fluorinated chemicals listed in Table
A–1 of proposed 40 CFR part 98,
subpart A. The disadvantage of this
approach is that it would exclude any
new (or newly important) fluorocarbons
whose GWPs have not been evaluated.
As discussed above, fluorocarbons in
general are likely to have significant
GWPs. Given the pace of technological
development in this area, production
(and emissions) of these gases could
become significant before the chemicals
were added to the table.
2. Selection of Reporting Threshold
In developing the proposed
thresholds for producers and importers
of fluorinated GHGs and N2O, we
considered production, capacity, and
import/export thresholds of 1,000
metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e, and
100,000 metric tons CO2e per year.
Table OO–1 of this preamble shows the
emissions and facilities that would be
covered under the various thresholds for
production and bulk imports of N2O and
HFCs, PFCs, SF6, and NF3.
E:\FR\FM\10APP2.SGM
10APP2
16580
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE OO–1. THRESHOLD ANALYSIS FOR INDUSTRIAL GAS SUPPLY
Source category
Total national
production or
import
(metric tons
CO2e/yr)
1,000
10,000
25,000
100,000
1,000
10,000
25,000
100,000
350,000,000
350,000,000
350,000,000
350,000,000
4,500,000
4,500,000
4,500,000
4,500,000
12
12
12
12
5
5
5
5
350,000,000
350,000,000
350,000,000
350,000,000
4,500,000
4,500,000
4,500,000
4,500,000
100
100
100
100
100
100
100
100
1,000
10,000
25,000
100,000
110,024,979
110,024,979
110,024,979
110,024,979
116
116
116
116
110,024,987
109,921,970
109,580,067
108,703,112
100
99.9
99.6
98.8
HFC, PFC, SF6, and
NF3 Producers ........
N2O Producers ...........
N2O and Fluorinated
GHG Importers
(bulk) .......................
Producers. We are proposing to
require reporting for all N2O and
fluorinated GHG production facilities.
As shown in Table OO–1 of this
preamble, all identified N2O, HFC, PFC,
SF6, and NF3 production facilities
would be covered at all capacity and
production-based thresholds considered
in this analysis. We do not have facilityspecific production capacity
information for the six facilities
producing fluorinated anesthetics;
however, if all these facilities produced
the same quantity in CO2e terms, they
too would probably be covered at all
capacity and production-based
thresholds.
The requirement that all facilities
report would simplify the rule and
permit facilities to quickly determine
whether or not they must report. The
one potential drawback of this
requirement is that small-scale
production facilities (e.g., for research
and development) could be
inadvertently required to report their
production, even though the quantities
produced would be small in both
absolute and CO2e terms. We are not
currently aware of any small-scale
deliberate production of N2O or
fluorinated GHGs, but we request
comment on this issue. These research
and development facilities could be
specifically exempt from reporting. An
alternative approach that would address
this concern would be to establish a
capacity-based threshold of 25,000
metric tons CO2e, summed across the
facility’s production capacities for N2O
and each fluorinated GHG. We request
comment on these alternative
approaches.
Importers and Exporters. We are
proposing to require importers and
VerDate Nov<24>2008
Production or imports covered
Emission
threshold level
(metrics tons
CO2e/yr)
15:41 Apr 09, 2009
Jkt 217001
Number of
facilities
Metric tons
CO2e/yr
exporters to report their imports and
exports if either their total imports or
their total exports, in bulk, of all
relevant gases, exceed 25,000 metric
tons CO2e. We are proposing this
threshold to reduce the compliance
burden on small businesses while still
including the vast majority of imports
and exports. As is true for HFC
production, HFC import and export
levels are expected to increase
significantly during the next several
years as HFCs replace ODS, which are
being phased out under the Montreal
Protocol.
Because it may be relatively easy for
importers and exporters to create new
corporations in order to divide up their
imports and exports and remain below
applicable thresholds, we considered
setting no threshold for importers and
exporters. However, we are not
proposing this option because we are
concerned that it would be too
burdensome to current small-scale
importers. We request comment on this
approach, specifically the burden on
small-scale importers if they were
required to report.
Further information on the threshold
analysis for industrial gas suppliers can
be found in the Suppliers of Industrial
GHGs TSD (EPA–HQ–OAR–2008–0508–
041). For specific information on costs,
including unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
a. Production
If you produce N2O or fluorinated
GHGs, we propose that you measure the
total mass of N2O or fluorinated gases
produced by chemical, including
PO 00000
Frm 00134
Fmt 4701
Sfmt 4702
Percent
Facilities Covered
Number
Percent
12
12
12
12
5
5
5
5
100
100
100
100
100
100
100
100
111
81
61
44
96
70
53
38
production that was later transformed or
destroyed at the facility, but excluding
any used GHG product that was added
to the production process (e.g., HFCs
returned to the production facility and
added to the HFC production process
for reclamation). Production would be
measured wherever it is traditionally
measured, e.g., at the inlet to the day
tank or at the shipping dock. The
quantities transformed or destroyed
would be reported separately; see
Sections V.OO.3.c and V.OO.3.d of this
preamble. The quantities of used
product added to the production
process would be measured and
subtracted from the total mass of
product measured at the end of the
process. This would avoid counting
used GHG product as new production.
b. Imports and Exports
If you import or export bulk N2O or
fluorinated GHGs, we propose that you
report the total quantities of N2O or
fluorinated GHGs that you import or
export by chemical. Reports would
include quantities imported in mixtures
and the name/number of the mixture, if
applicable (e.g., HFC–410A). Reporting
would occur at the corporate level. You
would not be required to report imports
or exports of heels (residual quantities
inside returned containers) or
transshipments (GHGs that originate in
a foreign country and that are destined
for another foreign country), but you
would be required to keep records
documenting the nature of these
transactions.
We propose to require reporting of
imports and exports in metric tons of
chemical because that is the unit in
which other quantities (production,
emissions, etc.) are proposed to be
reported under this rule. However,
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
because the preferred unit for Customs
reporting is kg rather than tons, EPA
requests comment on whether it should
require reporting of imports and exports
in kg of chemical.
In general, these proposed
requirements are consistent with those
of other programs that monitor imports
and exports of bulk chemical,
particularly EPA’s Stratospheric Ozone
Protection regulations.
Existing programs vary in their
treatment of products containing
chemicals whose bulk import must be
reported. The Australian program
requires reporting of all ODS and GHGs
imported in pre-charged equipment,
including the identity of the refrigerant,
the number of pieces of equipment, and
the charge size. The Inventory Update
Rule requires reporting of chemicals
contained in products if the chemical is
designed to be released from the
product when it is used (e.g., ink from
a pen). EPA’s Stratospheric Ozone
Protection regulations do not currently
require reporting of ODS contained in
imported equipment or other imported
products; however, (1) EPA has
prohibited the introduction into
interstate commerce, including import,
of certain non-essential products
typically pre-charged with these
chemicals, and (2) EPA is in the process
of proposing new regulations to prohibit
import of equipment pre-charged with
HCFCs.
We are not proposing to require that
importers of products containing N2O or
fluorinated GHGs report their imports.
In general, we are concerned that it
would be difficult for importers to
identify and quantify the GHGs
contained in these products and that the
number of importers would be high.
However, it may be easier for importers
to identify and quantify the GHGs
contained in a few types of products,
such as pre-charged equipment and
foams. For example, the identities and
amounts of fluorinated GHGs contained
in equipment are generally well known;
this data is typically listed on the
nameplate affixed to every unit.
Moreover, in aggregate, the quantities of
GHGs imported in equipment can be
large, for example, over 7 million metric
tons CO2e in imported pre-charged
window air-conditioners. We request
comment on whether we should require
reporting of imports or exports of precharged equipment and/or closed-cell
foams, including the likely burden and
benefits of such reporting.
c. N2O or Fluorinated GHGs
Transformed
Under the proposed rule, if you
chemically transform N2O or fluorinated
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
GHGs, you would be required to
estimate the mass of N2O or fluorinated
GHGs transformed. This estimate would
be the difference between (1) the
quantity of the N2O or fluorinated GHG
fed into the process for which the N2O
or fluorinated GHG was used as a
feedstock, and (2) the mass of any
unreacted feedstock that was not
returned to the process. Measuring the
quantity of N2O or fluorinated GHGs
actually fed into the process would
account for any losses between the point
where total production of the
fluorinated GHG is measured and the
point where the fluorinated GHG is
reacted as a feedstock (transformed).
The mass of any unreacted feedstock
that was not returned to the process
would be ascertained using mass flow
measurements and (if necessary) gas
chromatography.
d. Destruction
Under the proposed rule, if you
produce and destroy fluorinated GHGs,
you would be required to estimate the
quantity of each fluorinated GHG
destroyed. This estimate would be based
on (1) the quantity of the fluorinated
GHG fed into the destruction device,
and (2) the DE of the device. In
developing the estimate, you would be
required to account for any decreases in
the DE of the device that occurred when
the device was not operating properly
(as defined in State or local permitting
requirements and/or destruction device
manufacturer specifications). Finally,
you would be required to perform
annual fluorinated GHG concentration
measurements by gas chromatography to
confirm that emissions from the
destruction device were as low as
expected based on the DE of the device.
If emissions were found to be higher,
then you would have the option of using
the DE implied by the most recent
measurements or of conducting more
extensive measurements of the DE of the
device.
These proposed requirements are
identical to those proposed for
destruction of HFC–23 that is generated
as a byproduct during HCFC–22
production. They are also similar to
those contained in EPA’s Stratospheric
Ozone Protection Regulations. Those
regulations include detailed
requirements for reporting and verifying
transformation and destruction of
chemicals.
We are proposing requirements for
verifying the DE of destruction devices
used to destroy fluorinated GHGs
because fluorinated GHGs, particularly
PFCs and SF6, are difficult to destroy. In
many cases, these chemicals have been
selected for their end uses precisely
PO 00000
Frm 00135
Fmt 4701
Sfmt 4702
16581
because they are not flammable. For
destruction to occur, temperatures must
be quite high (over 2,300 °F), fuel must
be provided, flow rates of fuels and air
(or oxygen) must be kept above certain
limits, flow rates of fluorinated GHG
must be kept below others, and for some
particularly difficult-to-destroy
chemicals such as CF4, pure oxygen
must sometimes be fed into the process.
If one or more of these process
requirements is not met, DEs can drop
sharply (in some cases, by an order of
magnitude or more), and fluorinated
GHGs would simply be exhausted from
the device. Both construction
deficiencies and operator error can lead
to a failure to meet process
requirements; thus, both initial testing
and periodic monitoring are important
for verifying destruction device
performance. We request comment on
the option of requiring that the annual
destruction device emissions
measurement be performed using a
compound that is at least as difficult to
destroy as the most difficult-to-destroy
GHG ever fed into the device, e.g., SF6
or CF4.
We believe that owners or operators of
facilities that destroy fluorinated GHGs
are already likely to verify the DEs of
their destruction devices. Many
facilities destroying fluorinated GHGs
are likely to destroy ODS as well. In this
case, they are already subject to
requirements to verify the DEs of their
devices.
We request comment on the extent of
potential overlap between the
destruction reported under proposed 40
CFR part 98, subpart OO and that
reported under proposed 40 CFR part
98, subpart L. To obtain an accurate
estimate of the net supply of fluorinated
industrial greenhouse gases, fluorinated
GHGs that are produced and
subsequently destroyed should be
subtracted from the total produced or
imported. However, if fluorinated GHGs
are never included in the mass
produced (e.g., because they are
removed from the production process
with or as byproducts), then including
them in the mass destroyed would lead
to an underestimate of supply. One
possible solution to this problem would
be to require facilities producing and
destroying fluorinated GHGs to
separately estimate and report their
destruction of fluorinated GHGs that
have been counted as produced in either
the current year or previously.
EPA is not proposing to require
reporting of N2O destruction, because
EPA is not aware that such destruction
occurs. However, EPA requests
comment on this.
E:\FR\FM\10APP2.SGM
10APP2
16582
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
e. Precision, Accuracy, and Calibration
Requirements
The protocols and guidance reviewed
by EPA differ in their level of specificity
regarding the measurement of
production or other flows, particularly
regarding their precision and accuracy
requirements. Some programs, such as
the Stratospheric Ozone Protection
regulations, do not specify any accuracy
requirements, while other programs
specifically define acceptable errors and
reference industry standards for
calibrating and verifying monitoring
equipment. One of the latter is 40 CFR
part 75, Appendix D, which establishes
requirements for measuring oil and gas
flows as a means of estimating SO2
emissions from their combustion. These
requirements include a requirement that
the fuel flowmeter accuracy be within 2
percent of the upper range value and a
requirement that flowmeters be
recalibrated at least once a year.
In today’s proposed rule, we are
proposing to require facilities to
measure the mass of N2O or fluorinated
GHGs produced, transformed, or
destroyed using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of 0.2 percent of
full scale or better. In addition, we are
proposing to require that weigh scales,
flowmeters, and/or other measurement
devices be calibrated every year or
sooner if an error is suspected based on
mass-balance calculations or other
information. Facilities could perform
the verification and calibration of their
scales and flowmeters during routine
product line maintenance. Finally, we
are proposing that facilities
transforming or destroying fluorinated
GHGs calibrate gas chromatographs by
analyzing, on a monthly basis, certified
standards with known GHG
concentrations that are in the same
range (percent levels) as the process
samples.
EPA requests comment on these
proposed requirements. EPA
specifically requests comment on the
proposed frequency of calibration for
flowmeters; the Agency understands
that some types of flowmeters that are
commonly employed in chemical
production, such as the Coriolis type,
may require less frequent calibration.
We are proposing specific accuracy,
precision, and calibration requirements
because the high GWPs and large
volumes of fluorinated GHGs produced
make such requirements worthwhile for
this source category. For example, a one
percent error at a typical facility
producing fluorinated GHGs would
equate to 300,000 metric tons CO2e. The
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Agency believes that these precision
and accuracy requirements (0.2 percent)
should not represent a significant
burden to chemical producers, who
already use and regularly calibrate
measurement devices with similar
accuracies.
EPA is not proposing precision and
accuracy requirements for importers and
exporters of bulk chemical; however,
EPA requests comment on whether such
requirements (e.g., 0.5 to 1 percent)
would be appropriate.
conversion. This approach could be
used in the very unlikely event that
neither primary nor secondary direct
measures of production were available.
4. Selection of Procedures for Estimating
Missing Data
5. Selection of Data Reporting
Requirements
Under the proposed rule, facilities
would be required to submit data,
described below, in addition to the
production, import, export, feedstock,
and destruction data listed above. This
data is intended to permit us to check
the main estimates submitted. A
complete list of data to be reported is
included in proposed 40 CFR part 98,
subparts A and OO.
a. Production
In the event that any data on the mass
produced, fed into the production
process (for used material being
reclaimed), fed into transformation
processes, fed into destruction devices,
or sent to another facility for
transformation or destruction, is
unavailable, we propose that facilities
be required to use secondary
measurements of these quantities. For
example, facilities that ordinarily
measure production by metering the
flow into the day tank could use the
weight of product charged into shipping
containers for sale and distribution. We
understand that the types of flowmeters
and scales used to measure fluorocarbon
production (e.g., Coriolis meters) are
generally quite reliable, and therefore it
should rarely be necessary to rely on
secondary production measurements. In
general, production facilities rely on
accurate monitoring and reporting of
production and related quantities.
If concentration measurements were
unavailable for some period, we propose
that the facility be required to report the
average of the concentration
measurements from just before and just
after the period of missing data.
There is one proposed exception to
these requirements: If the facility has
reason to believe that either method
would result in a significant under- or
overestimate of the missing parameter,
then the facility would be required to
develop an alternative estimate of the
parameter and explain why and how it
developed that estimate. We would have
the option of rejecting this alternative
estimate and replacing it with the value
developed using the usual missing data
method if we did not agree with the
rationale or method for the alternative
estimate.
We request comment on these
methods for estimating missing data. We
also request comment on the option of
estimating missing production data
based on consumption of reactants,
assuming complete stoichiometric
PO 00000
Frm 00136
Fmt 4701
Sfmt 4702
b. Imports and Exports
We do not believe that missing data
would be a problem for importers and
exporters of GHGs due to their
requirement to declare the quantities of
GHGs imported or exported for Customs
purposes. However, we request
comment on this assumption.
a. Production
Facilities producing N2O or
fluorinated GHGs would be required to
submit data on the total mass of
reactants fed into the production
process, the total mass of non-GHG
reactants and byproducts permanently
removed from the process, and the mass
of used product added back into the
production process. Facilities would
also be required to provide the names
and addresses of other facilities to
which they sent N2O or fluorinated
GHGs for transformation or destruction.
All quantities would be annual totals in
metric tons, by chemical.
b. Imports/Exports and Destroyers of
Fluorinated GHG
Importers of N2O or fluorinated GHGs
would be required to submit an annual
report that summarized their imports,
providing the following information for
each import: The quantity of GHGs
imported by chemical, the date on
which the GHGs were imported, the
port of entry through which the GHGs
passed, the country from which the
imported GHGs were imported, and the
importer number for the shipment.
Importers would also be required to
provide the names and addresses of any
persons and facilities to which the
imported GHGs were sold or transferred
for transformation or destruction.
Exporters of N2O and fluorinated
GHGs would be required to submit an
annual report that summarized their
exports, similar to the report provided
by importers. A complete list of data to
be reported is included in the proposed
rule.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
These proposed requirements are very
similar to those that apply to importers
and exporters of ODS under EPA’s
Stratospheric Ozone Protection
Program. We are proposing them
because they would provide us with
valuable information for verifying the
nature and size of GHG imports and
exports.
In addition to annually reporting the
mass of fluorinated GHG fed into the
destruction device, facilities destroying
fluorinated GHGs would be required to
submit a one-time report including the
following: The destruction unit’s DE,
the methods used to record volume
destroyed and to measure and record
DE, and the names of other relevant
Federal or State regulations that may
apply to destruction process. This onetime report is very similar to that
required under EPA’s Stratospheric
Ozone Protection regulations.
6. Selection of Records That Must Be
Retained
EPA is proposing that the following
records be retained because they are
necessary to verify production, import,
export, transformation, and destruction
estimates and related quantities and
calibrations.
a. Production
Owners or operators of facilities
producing N2O or fluorinated GHGs
would be required to keep records of the
data used to estimate production, as
well as records documenting the initial
and periodic calibration of the
flowmeters or scales used to measure
production.
b. Imports and Exports
Importers of N2O or fluorinated GHGs
would be required to keep the following
records substantiating each of the
imports that they report: A copy of the
bill of lading for the import, the invoice
for the import, the U.S. Customs entry
form, and dated records documenting
the sale or transfer of the imported GHG
for transformation or destruction (if
applicable).
Every person who imported a
container with a heel would be required
to keep records of the amount brought
into the U.S. and document that the
residual amount in each shipment is
less than 10 percent of the net mass of
the container when full and would:
Remain in the container and be
included in a future shipment, be
recovered and transformed, or be
recovered and destroyed.
Exporters of N2O, or fluorinated
GHGs, would be required to keep the
following records substantiating each of
the exports that they report: A copy of
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
the bill of lading for the export and the
invoice for the import.
c. Transformation
Owners or operators of production
facilities using N2O or fluorinated GHGs
as feedstocks would be required to keep
records documenting: The initial and
annual calibration of the flowmeters or
scales used to measure the mass of GHG
fed into the destruction device and the
periodic calibration of gas
chromatographs used to analyze the
concentration of N2O fluorinated GHG
in the product for which the GHG is
used as a feedstock.
d. Destruction
Owners or operators of GHG
production facilities that destroy
fluorinated GHGs would be required to
keep records documenting: The
information that they send in the onetime and annual reports, the initial and
annual calibration of the flowmeters or
scales used to measure the mass of GHG
fed into the destruction device, the
method for tracking startups,
shutdowns, and malfunctions and any
GHG emissions during these events, and
the periodic calibration of gas
chromatographs used to annually
analyze the concentration of fluorinated
GHG in the destruction device exhaust
stream, as well as the representativeness
of the conditions under which the
measurement took place.
PP. Suppliers of Carbon Dioxide (CO2)
1. Definition of the Source Category
CO2 is used for a variety of
commercial applications, including food
processing, chemical production,
carbonated beverage production,
refrigeration, and petroleum production
for EOR, which involves injecting a CO2
stream into injection wells at well fields
for the purposes of increasing crude oil
production. Possible suppliers of CO2
include industrial facilities or process
units that capture a CO2 stream, such as
those found at electric power plants,
natural gas processing plants, cement
kilns, iron and steel mills, ammonia
manufacturing plants, petroleum
refineries, petrochemical plants,
hydrogen production plants, and other
combustion and industrial process
sources. These suppliers can capture
and/or compress CO2 for delivery to a
variety of end users as discussed above.
To ensure consistent treatment of CO2
suppliers and given the large percentage
of CO2 supplied from CO2 production
wells, we have also proposed inclusion
of facilities producing CO2 from CO2
production wells in the proposal.
Importers and exporters of CO2 are
PO 00000
Frm 00137
Fmt 4701
Sfmt 4702
16583
discussed under suppliers of industrial
GHGs (see Section V.OO of this
preamble) because most of these
facilities import or export multiple
industrial gases. For a full discussion of
this source category, refer to the
Suppliers of CO2 TSD (EPA–HQ–OAR–
2008–0508–044).
According to the U.S. GHG Inventory
in 2006, the total supply of CO2 from
industrial facilities and CO2 production
wells was approximately 40.6 million
metric tons CO2e. Further research in
support of this rulemaking identified
three additional facilities capturing a
CO2 stream for sale. Data for two of
these facilities suggest an additional 0.5
million metric tons CO2e captured.
Currently, the majority of CO2 (79
percent) is produced from CO2
production wells. Approximately 18
percent of CO2 is produced at natural
gas processing facilities and less than 2
percent from ammonia production
facilities. Less than 1 percent of CO2 is
captured at other industrial facilities.
Fugitive Emissions from CO2 Supply.
Fugitive CO2 emissions can occur from
the production of CO2 streams from CO2
production wells or capture at industrial
facilities or process units, as well as
during transport of the CO2, and during
or after use of the gas. We propose to
exclude the explicit reporting of fugitive
CO2 emissions from CO2 supply at
industrial facilities or process units and
CO2 production wells, as well as from
CO2 pipelines, injection wells and
storage sites. Much of the CO2 that
could ultimately be released as a
fugitive emission during transportation,
injection and storage, would be
accounted for in the CO2 supply
calculated using the methods below.
Although separate calculation and
reporting of fugitive CO2 emissions are
not proposed for inclusion, we believe
that obtaining robust data on fugitive
CO2 emissions from the entire carbon
capture and storage chain would
provide a more complete understanding
of the efficacy of carbon capture and
storage technologies as an option for
mitigating CO2 emissions.
We seek comment on the decision to
exclude the reporting of fugitive CO2
emissions from the carbon capture and
storage chain. We have concluded that
there could be merit in requiring the
reporting of fugitive emissions from
geologic sequestration of CO2, in
particular. This is discussed further
below.
Geologic Sequestration of CO2. CO2
used in most industrial applications
would eventually be released to the
atmosphere. For EOR applications,
however, some amount of CO2 could
ultimately remain sequestered in deep
E:\FR\FM\10APP2.SGM
10APP2
16584
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
geologic formations. The objective of
EOR operations is not to maximize
reservoir CO2 retention rates, but to
maximize oil production and the
amount of CO2 trapped underground
would be a function of site specific and
operational factors. There are several
EOR operations in the Permian Basin of
Texas. One study showed that retention
rates for eight reservoirs ranged from 38
to 100 percent with an average of 71
percent, but many of these projects are
not mature enough to predict final
retention (see Suppliers of CO2 TSD
(EPA–HQ–OAR–2008–0508–044)).
We are not proposing the inclusion of
geologic sequestration in the proposed
rulemaking. However, the Agency
recognizes that there may be significant
stakeholder interest in reporting the
amount of CO2 injected and geologically
sequestered at EOR operations in order
to demonstrate the effectiveness of EOR
projects that ultimately intend to store
the CO2 for long periods of time. If an
EOR project intends to sequester CO2 for
long periods of time, there would be
additional operational factors and postoperational considerations and
monitoring. Although EPA is not
proposing inclusion of this source in the
rulemaking, we have outlined initial
thoughts about how geologic
sequestration might be included in a
reporting program for EOR sequestration
or other types of geologic sequestration.
We welcome comment on the approach
outlined below or other suggestions for
how to quantify and verify the amount
of CO2 sequestered in geologic
formations.
We reviewed a number of existing and
proposed methodologies for monitoring
and reporting fugitive emissions from
carbon capture, transport, injection and
storage. A summary of these protocols
can be found in the Review of Existing
Programs memorandum (EPA–HQ–
OAR–2008–0508–054). Based on this
review, a possible approach to include
geologic sequestration might be to ask
EOR operators to submit a geologic
sequestration report. This report could
provide information on the amount of
CO2 sequestered (based on the amount
of CO2 injected minus any fugitive
emissions) along with a written
description of the activities undertaken
to document and verify the amount
sequestered at each site. This report
could include the following supporting
information:
• The owner and operator of the
geologic sequestration site(s). Including
the business name, address, contact
name, and telephone number.
• Location of the geologic
sequestration site(s) including a map
showing the modeled aerial extent of
the CO2 plume over the lifetime of the
project.
• Permitting information. Including
information on the UIC well permit(s)
issued by the appropriate State or
Federal agency: Permit number or other
unique identification, date the permit
was issued and modified if applicable,
permitting agency, contact name, and
telephone number.
• An overview of the site
characteristics, referencing or providing
information which demonstrates
sufficient storage capacity for the
expected operating lifetime of the plant
and the presence of an effective
confining system overlying the injection
zone.
• An assessment of the risks of CO2
leakage, or escape of CO2 from the
subsurface to the atmosphere, including
an evaluation of potential leakage
pathways such as deep wells, faults, and
fractures.
• An overview of the methods used to
model the subsurface behavior of CO2
and the results.
• Baseline conditions used to
evaluate performance of the site
including the amount of naturally
occurring CO2 emissions and/or other
characteristics that would be used to
demonstrate the effectiveness of the
system to contain CO2.
• Summary of the monitoring plan
that would be used to determine CO2
emissions from the site including a
discussion of the methodology,
rationale, and frequency of monitoring.
The information listed above could be
submitted one time and then updated as
appropriate. However, the volume of
CO2 injected and any emissions from
the storage site, including physical
leakage from the geologic formation (via
natural features or wells) and/or fugitive
emissions of CO2 co-produced with oil/
gas, would be reported on an annual
basis in order to quantify the amount of
CO2 geologically sequestered.
2. Selection of Reporting Threshold
EPA has identified at least nine
industrial facilities or process units in
the U.S. that currently capture CO2
(three natural gas processing plants, two
ammonia facilities, two electricity
generation facilities, one soda ash
production plant, and one coal
gasification facility) (Table PP–1 of this
preamble).
TABLE PP–1. THRESHOLD ANALYSIS FOR CO2 SUPPLY FROM INDUSTRIAL FACILITIES OR PROCESS UNITS
Total national
emissions
(metric tons
CO2e)
Threshold level metric tons
CO2e
1,000 ........................................................................
10,000 ......................................................................
25,000 ......................................................................
100,000 ....................................................................
Under the proposed rule, all
industrial facilities that capture and
transfer a CO2 stream would be required
to report the mass of CO2 captured and/
or transferred. All known existing
facilities exceed all but the highest
reporting threshold of 100,000 metric
tons CO2e, taking into account solely the
mass of CO2 captured. At the 25,000
metric tons CO2e threshold considered
by other subparts of this rule, all
industrial facilities and capture sites
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Total number
of U.S.
facilities
8,184,875
8,184,875
8,184,875
8,184,875
9
9
9
9
Emissions covered
Metric tons
CO2e/yr
8,186,881
8,186,881
8,186,881
8,036,472
exceed the threshold. The analysis did
not account for stationary combustion at
each facility. We concluded that all
facilities capturing CO2 would likely
already exceed the reporting thresholds
under other subparts of proposed 40
CFR part 98 for their downstream
emissions. Therefore, a proposed
threshold of ‘‘All In’’ for reporting CO2
supply from industrial facilities or
process units would not bring in
additional facilities not already
PO 00000
Frm 00138
Fmt 4701
Sfmt 4702
Facilities covered
Percent
100
100
100
98
Number
Percent
9
9
9
5
100
100
100
56
triggering other subparts of the proposed
rule.
Based on the volumes of CO2 supplied
by facilities producing a CO2 stream
from CO2 production wells, we also
propose that they be subject to
reporting. Currently there are four
natural formations—Jackson Dome,
Bravo Dome, Sheep Mountain, and
McElmo Dome. Data are not available to
estimate emissions from individual
owners or operators operating within
E:\FR\FM\10APP2.SGM
10APP2
16585
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the Domes, therefore emissions data are
presented at the Dome level (Table PP–
2 of this preamble). We propose that all
CO2 production wells owned by a single
owner or operator in a given Dome
report the mass of CO2 extracted and/or
transferred off site. We are seeking
comment on alternative methods for
defining the reporting facility (e.g.,
reporting at the level of an individual
well).
TABLE PP–2. THRESHOLD ANALYSIS FOR CO2 SUPPLY CO2 PRODUCTION WELLS
Total national
emissions
(metric tons
CO2e)
Threshold level metric tons CO2e
1,000 ....................................................................
10,000 ..................................................................
25,000 ..................................................................
100,000 ................................................................
Total number
of U.S.
facilities *
31,358,853
31,358,853
31,358,853
31,358,853
4
4
4
4
Emissions covered
Metric tons
CO2e/yr
31,358,853
31,358,853
31,358,853
31,358,853
Facilities covered
Percent
100
100
100
100
Number
Percent
4
4
4
4
100
100
100
100
* Under this proposal, owners or operator would be required to report on all CO2 production wells under their ownership/operation in a single
Dome.
We have concluded that reporting the
volume of the CO2 streams from CO2
production wells is important given the
large fraction of CO2 supplied from CO2
production wells. Further, we conclude
that there is minimal burden associated
with these requirements, as all
necessary monitoring equipment should
already be installed to support current
operating practice.
Importers and exporters of CO2 in
bulk should review the threshold
language for industrial GHG suppliers
found in Section OO of this preamble,
which proposes a threshold of 25,000
metric tons CO2e, for applicability. We
decided to have a single threshold
applicable for bulk importers and
exporters of all industrial gases, because
many are importing and/or exporting
multiple industrial gases. We decided
not to include CO2 imported or exported
in products (e.g., fire extinguishers),
because of the potentially large number
of sources.
For additional information on the
threshold analysis please refer to the
Suppliers of CO2 TSD (EPA–HQ–OAR–
2008–0508–044). For specific
information on costs, including
unamortized first year capital
expenditures, please refer to section 4 of
the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring
Methods
The monitoring plan for CO2
suppliers at industrial facilities or
process units, CO2 production wells,
and CO2 importers and exporters
involves accounting for the total volume
of the CO2 stream captured, extracted,
imported and exported. We propose that
if CO2 suppliers already have the flow
meter installed to directly measure the
CO2 stream at the point of capture,
extraction, import and/or export, that
facilities use the existing flow meter to
measure CO2 supply. We propose that
facilities sample the composition of the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
gas on at least a quarterly basis to
determine CO2 composition of the CO2
stream. If the necessary flow meters are
not currently installed, CO2 suppliers
would use mass flow meters to measure
the volume of the CO2 stream
transferred offsite.
We propose to require reporting on
the volume of the CO2 stream at the
point of capture, extraction, import and
export because this would provide
information on the total quantity of CO2
available for sale. Measuring at this
initial point could provide additional
information in the future on fugitive
CO2 emissions from onsite purification,
processing, and compression of the gas.
However, if the necessary flow meters
are not currently in place, facilities may
conduct measurements at the point of
CO2 transfer offsite.
We conclude that there is minimal
incremental burden associated with this
approach for CO2 suppliers at industrial
facilities or process units, CO2
production wells, importers and
exporters because these sites likely
already have the necessary flow meters
installed to monitor the CO2 stream. In
addition, facilities need to know CO2
composition of the gas in order to
ensure the gas meets appropriate
specifications (e.g., food grade CO2).
We also considered requiring CO2
suppliers to report only on CO2 sales,
without determining the actual CO2
composition of the gas sold. This is a
relatively simple method, however,
facilities already routinely measure the
composition of the gas, providing
greater certainty in the potential
emissions data.
The methods proposed are generally
consistent with existing GHG reporting
protocols. Although existing protocols
focus on accounting for fugitive
emissions, and not quantity of CO2
supplied, direct measurement is
commonly the recommended approach
for measuring fugitive emissions. We
PO 00000
Frm 00139
Fmt 4701
Sfmt 4702
concluded that while direct
measurement of fugitive emissions may
not be common practice, and is
therefore not proposed, measurement of
CO2 transfer is.
4. Selection of Procedures for Estimating
Missing Data
Facilities with missing monitoring
data on the volume of the CO2 stream
captured, extracted, imported, and
exported should use the greater of the
volume of the CO2 stream transferred
offsite or the quarterly or average value
for the parameter from the past calendar
year. The owners or operators of
facilities monitoring emissions at the
point of transfer offsite, that have
missing monitoring data on the CO2
stream transferred, may use the
quarterly or average value for the
parameter from the past calendar year.
Facilities with missing data on the
composition of the CO2 stream captured,
extracted, imported, and exported
should use the quarterly or average
value for the parameter from the past
calendar year.
5. Selection of Data Reporting
Requirements
For CO2 supply, the proposed
monitoring method is based on direct
measurement of the gaseous and liquid
CO2 streams. All CO2 suppliers would
report, on an annual basis, the measured
volume of the CO2 stream that is
captured, extracted, imported and
exported if the proper flow meter is
installed to carry out these
measurements. Facilities monitoring
emissions at the point of transfer offsite
would report the annual volume of the
CO2 stream transferred. All suppliers
also would report, on an annual basis,
the CO2 composition of the gas sold.
The end-use application of the supplied
CO2 (e.g., EOR, food processing) should
also be reported, if known.
E:\FR\FM\10APP2.SGM
10APP2
16586
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
EPA proposes to collect data on the
measured volume of the CO2 stream
captured, extracted, imported and
exported, as well as gas composition
because these form the basis of the GHG
calculations and are needed for EPA to
understand the emissions data and
verify reasonableness of the reported
emissions. EPA also proposes to collect
information on the end use of the
transferred CO2, if known, because CO2
can be used in emissive or non-emissive
applications. Collecting data on the
ultimate fate of the CO2 stream can
provide information on the potential
emissions of CO2 released to the
atmosphere.
6. Selection of Records That Must Be
Retained
Owners or operators of all CO2
suppliers would be required to retain
onsite all quarterly measurements for
the volume of the CO2 stream captured,
extracted, imported and exported, and
CO2 composition. Where measurements
are based on CO2 transferred offsite,
these quarterly measurements would be
retained, along with CO2 composition.
QQ. Mobile Sources
1. Definition of the Source Category
This section of the preamble describes
proposed GHG reporting requirements
for manufacturers of new mobile
sources, including motor vehicles and
engines, nonroad vehicles and engines,
and aircraft engines.118 It also seeks
comment on the need to collect
additional in-use travel activity and
other emissions-related data from States
and local governments and mobile
source fleet operators. These proposed
requirements and the requests for
comments are based on EPA’s authority
under CAA Sections 114 and 208.
Not discussed in this portion of the
preamble are proposed GHG reporting
requirements related to transportation
fuels (see Section V.MM of this
preamble, Suppliers of Petroleum
Products) and motor vehicle and engine
manufacturing facilities (see Section V.C
of this preamble, General Stationary
Fuel Combustion Sources).
Total Emissions. For the U.S.
transportation sector, the 2008 U.S.
Inventory includes GHGs from the
118 The
terms ‘‘manufacturers’’ and
‘‘manufacturing companies’’, as used in this
section, mean companies that are subject to EPA
emissions certification requirements. This primarily
includes companies that manufacture vehicles and
engines domestically and foreign manufacturers
that import vehicles and engines into the U.S.
market. In some cases, this also includes domestic
companies that are required to meet EPA
certification requirements when they import
foreign-manufactured vehicles or engines.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
operation of passenger and freight
vehicles within U.S. boundaries, natural
gas used to power domestic pipelines,
lubricants associated with mobile
sources, and international bunker fuels
purchased in the U.S. for travel outside
U.S. boundaries. GHG emissions from
these sources in 2006 totaled 2102.6 Tg
CO2e, representing 29.3 percent of total
U.S. GHG emissions. Just under 79
percent of these emissions came from
on-road sources, including passenger
cars and light-duty trucks (58.8 percent),
medium- and heavy-duty trucks (19.2
percent), buses (0.6 percent) and
motorcycles (0.1 percent). Aircraft
(including domestic military flights)
accounted for 11.6 percent of
transportation GHGs, ships and boats 5
percent, rail 2.8 percent, pipelines 1.5
percent, and lubricants 0.5 percent.
These estimates primarily reflect GHGs
resulting from the combustion of fuel to
power U.S. transportation sources.
These estimates do not include
emissions from the operation of other
non-transportation mobile equipment
and recreational vehicles, which
collectively accounted for over 2
percent of total U.S. GHG emissions.
GHGs produced by transportation
sources include CO2, N2O and CH4,
which result primarily from the
combustion of fuel to power these
sources or from treatment of the exhaust
gases, and HFCs, which are released
through the operation, servicing and
retirement of vehicle A/C systems. CO2
is the predominant GHG from these
sources, representing 95 percent of
transportation GHG emissions (weighted
by the GWP of each gas). HFCs account
for 3.3 percent, N2O for 1.6 percent, and
CH4 for 0.1 percent of transportation
GHG emissions. EPA is proposing
reporting requirements for each of these
gases, where appropriate.
2. Selection of Proposed GHG
Measurement, Reporting, and
Recordkeeping Requirements
For the new vehicle and engine
manufacturer reporting requirements
proposed in this Notice, EPA intends to
build on our long-established programs
that control vehicle and engine
emissions of criteria pollutants
including hydrocarbons, NOX, CO, and
PM. These programs, which include
emissions standards, testing procedures,
and emissions certification and
compliance requirements, are based on
emission rates over prescribed test
cycles (e.g., grams of pollutant per mile
or grams per kilowatt-hour). Thus, we
propose having manufacturers also
report GHG emissions in terms of
emission rates for this reporting
program. It is important to note that this
PO 00000
Frm 00140
Fmt 4701
Sfmt 4702
approach is somewhat different from the
direct reporting of tons per year of
emissions that is appropriate for the
non-mobile source categories addressed
elsewhere in this preamble. However,
EPA would be able to use the GHG
emission rate data from manufacturers
with our existing models and other
information to project tons of GHG
emissions for the various mobile source
categories.
Although the new reporting
requirements proposed here focus on
emission rates from new vehicles and
engines, EPA also is very interested in
continually updating and improving our
understanding of the in-use activity and
total emissions from mobile sources.
Thus, we are seeking comment on the
need to collect in-use travel activity and
other emissions-related data from States
and local governments and mobile
source fleet operators. Section V.QQ.4 of
this preamble describes the existing
State and local government and fleet
operator data that EPA currently collects
and requests public comment on the
need for, and substance of, additional
reporting requirements.
3. Mobile Source Vehicle and Engine
Manufacturers
a. Overview
As mentioned above, EPA is
proposing GHG reporting requirements
that fit within the reporting framework
established for EPA’s long-established
criteria pollutant emissions control
programs and vehicle fuel economy
testing program. While the details of the
programs vary widely among the vehicle
and engine categories, EPA generally
requires manufacturers to conduct
emissions testing and report the
resulting emissions data to EPA for
approval on an annual basis prior to the
introduction of the vehicles or engines
into commerce. As a part of this process,
since the early 1970s, EPA has collected
criteria pollutant emissions data for all
categories of vehicles and engines used
in the transportation sector, including
engines used in nonroad equipment (see
Table QQ–1 of this preamble).
TABLE QQ–1. MOBILE SOURCE
VEHICLE AND ENGINE CATEGORIES
Category
Light-duty vehicles
Highway heavy-duty vehicles (chassis-certified)
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotive engines
Nonroad small spark ignition engines
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE QQ–1. MOBILE SOURCE VEHI- We believe that this exemption would
CLE AND ENGINE CATEGORIES— avoid the relatively high per-vehicle or
per-engine reporting costs for small
Continued
Category
Nonroad large spark ignition engines
Marine spark ignition engines/personal
watercraft
Snowmobiles
Off-highway motorcycles and all terrain vehicles
Aircraft engines
For purposes of EPA certification,
manufacturers typically group vehicles/
engines with similar characteristics into
families and perform emission tests on
representative or worst-case vehicles/
engines from each family. Integral to
EPA’s existing certification procedures
are well-established methods for
assuring the completeness and quality
of reported emission test data. We are
proposing to require manufacturers to
measure and report GHG emissions data
as part of these current emissions testing
and certification procedures. These
procedures, appropriate here because of
the long-standing history and structure
of mobile source control programs, are
necessarily different from the
monitoring-based methods proposed for
other sources elsewhere in this notice.
After a discussion of the proposed
small business threshold, the following
subsections describe the proposed GHG
emissions measurement and reporting
requirements for manufacturers. As
discussed in those subsections, some
manufacturers already measure and
report some GHG emissions, some
measure but do not have to report GHG
emissions, and others would need to
measure and report for the first time. We
propose that the new measurement and
reporting requirements apply beginning
with the 2011 model year, although we
encourage voluntary measurement and
reporting for model year 2010.
b. Selection of a Reporting Threshold
In most of EPA’s recent mobile source
regulatory programs for criteria
pollutants, EPA has applied special
provisions to small manufacturers. EPA
proposes to exempt small manufacturers
from the GHG reporting requirements.
We define ‘‘small business’’ or ‘‘small
volume manufacturer’’ separately for
each mobile source category. These
definitions were established in the
regulations during the rulemaking
process for each category, which
included consultation with small
entities and with the Small Business
Administration. We’re proposing to use
these same definitions in each case for
the reporting requirements exemption.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
manufacturers without detracting from
the goals of the reporting program, as
discussed below.
It is important to note that this
‘‘threshold’’ would differ from the
approach proposed for other source
categories discussed in Section V of this
preamble. That is, EPA would not have
manufacturers determine their
eligibility based on total tons emitted
per year. As discussed above, EPA’s
current mobile source criteria pollutant
control programs are based on emissions
rates over prescribed test cycles rather
than tons per year estimates. Since we
are proposing to build on our existing
system, we believe that a threshold
based on manufacturer size is
appropriate for the mobile source sector.
Although the emission rates of some
vehicles and engines would not be
reported, we do not believe this is a
concern because the technologies—and
thus emission rates—from larger
manufacturers represent the same basic
technologies and emission rates of
essentially all vehicles and engines. It is
also worth noting that the
manufacturers that meet the small
manufacturer definitions represent a
very small fraction of overall vehicle
and engine sales. For nine out of the
twelve non-aircraft mobile source
categories (there are currently no small
aircraft engine manufacturers), we
estimate that sales from small
manufacturers represent less than 10
percent of overall sales (for eight of
these categories, including light-duty
vehicles, small manufacturers account
for less than 3 percent of sales). For the
remaining three categories (highway
motorcycles, all terrain vehicles/off-road
motorcycles, and small spark ignition
engines) we estimate that small entities
account for less than 32 percent of sales.
Please see the discussion of our
compliance with the RFA in Section
IX.C of this preamble. We request
comments on our proposed approach for
the reporting threshold for mobile
source categories.
c. Light-Duty Vehicles
We propose that manufacturers of
passenger cars, light trucks, and
medium-duty passenger vehicles
measure and report emissions of CO2
(including A/C-related CO2), CH4, N2O,
and refrigerant leakage.119 Existing
criteria pollutant emissions certification
regulations, as well as fuel economy
testing regulations, already require
119 See 40 CFR 1803–01 for full definitions of
‘‘light-duty vehicle’’.
PO 00000
Frm 00141
Fmt 4701
Sfmt 4702
16587
manufacturers to measure and report
CO2 for essentially all of their vehicle
testing. Requiring manufacturers to also
measure and report the other GHGs
emitted by these vehicles, as proposed
in this Notice and discussed below,
would introduce a modest but
reasonable additional testing and
reporting burden.
For CH4 and N2O, we propose that
manufacturers begin to measure these
emissions as a part of existing emissions
certification and fuel economy test
procedures (FTP, SFTP, HFET, et al.), if
they are not already doing so, and then
to report those emissions in the same
cycle-weighted format that they report
other emission results under the current
certification requirements. Because such
testing has not generally been required,
some manufacturers would need to
install additional exhaust analysis
equipment for the measurement of CH4
and/or N2O. In most cases, both of these
types of new analyzers could be added
as modular units to existing test
equipment.
In the case of N2O, since this
pollutant has not previously been
included in the certification testing
process, it is necessary to introduce a
new analytical procedure for the
measurement of N2O over the FTP. This
is not the case for CH4, however, since
an analytical procedure for CH4 testing
already exists. We propose that
manufacturers use an N2O procedure
found in the regulatory language
associated with this notice that would
be based largely on the procedures
currently used to measure CO2 and CO,
using nondispersive infrared
measurement technology. In addition,
EPA is proposing a ‘‘scrubbing’’ stage as
a part of this procedure that would
remove sulfur compounds that can
contribute to N2O formation in the
sample bag. (See proposed 40 CFR
1065.257 and 1065.357 for the proposed
N2O measurement procedures.) EPA
requests comments on all aspects of the
proposed N2O measurement procedure,
including potential alternate methods
with equal or better analytical
performance.
Measuring and Reporting A/C-Related
CO2. Manufacturers of light-duty
vehicles, unlike manufacturers of heavyduty and nonroad engines, sell their
products as complete engine-plusvehicle combinations that include the
vehicles’ A/C systems. Thus, we believe
it is appropriate that these
manufacturers report A/C-related
emissions as a part of their existing
vehicle certification requirements. EPA
does not currently require these
manufacturers to measure or report the
A/C-related CO2 emissions (or the
E:\FR\FM\10APP2.SGM
10APP2
16588
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
leakage of refrigerants, as discussed
below) under current regulations. We
propose that these manufacturers begin
to measure A/C-related CO2 emissions
(i.e., the indirect CO2 emissions
resulting from the additional load
placed on the engine by an operating A/
C system), using a proposed new test
cycle, which is described below. This
testing would not require new
equipment, and the proposed test cycle
is similar to one that exists in many
State Inspection & Maintenance (I/M)
programs.
The current FTP for light-duty
vehicles is performed with the A/C
turned on only during the SC03, or ‘‘air
conditioning,’’ test procedure. This test
is used to verify emissions compliance
in a ‘‘worst-case’’ situation when the A/
C system is operating under relatively
extreme conditions. The SC03 is also
used in the 5-cycle fuel economy
calculation for fuel economy labeling.
Thus, although the SC03 test results in
a value for CO2 emissions (in grams per
mile), the incremental increase of CO2
resulting from operation of the A/C
system, especially in a more typical
situation, is not quantified.
In order to provide for consistent,
accurate measurement of A/C-related
CO2 emissions, EPA proposes to
introduce a specifically-designed test
procedure for A/C-related CO2
emissions. Manufacturers would run
this proposed test, the A/C CO2 Idle
Test, with the engine idling, upon
completion of an emissions certification
test—such as the FTP, highway fuel
economy, or US06 test. The proposed A/
C CO2 Idle Test is similar to the ‘‘Idle
CO’’ test, which was once a part of
vehicle certification, and is still used in
State I/M programs (see 40 CFR part 51,
subpart S, Appendix B).
Within each vehicle model type,
various configurations of engine and
cooling system options can be expected
to have somewhat different A/C-related
CO2 performance.120 However, we
believe that vehicles sharing certain
technical characteristics would
generally have similar A/C-related CO2
emissions. Specifically, vehicles with
the same engine, A/C system design,
and interior volume would be expected
in most cases to have similar A/Crelated CO2 performance. In order to
minimize the number of new tests that
manufacturers would be required to
perform, EPA is proposing that
manufacturers be allowed to select a
subset of vehicles for A/C CO2 Idle
120 In the existing regulations covering vehicle
emissions certification, under ‘Definitions’ in 40
CFR 600.002–85(a)(15), ‘‘model type’’ means a
unique combination of car line, basic engine, and
transmission class.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Testing, each of which would represent
the performance of a larger group of
vehicles with common A/C-related
technical characteristics. We believe
that in most cases the vehicles that
manufacturers currently test for fuel
economy purposes (as described in 40
CFR 600.208(a)(2)) would generally also
capture the key engine-A/C systemvehicle configurations that may exist
within a given model type. The
complete set of our proposed criteria for
manufacturers to meet in selecting the
representative vehicles for the A/C CO2
Idle Test is found in the regulatory
language in the proposed rule (see
proposed 40 CFR 86.1843–01, ‘‘Air
conditioning system commonality’’).
The A/C CO2 Idle Test would
compare the additional CO2 generated at
idle with the A/C system in operation to
the CO2 generated at idle with the A/C
system off. Manufacturers would run
the test with the vehicle’s A/C system
operating under complete control of the
climate control system and for a
sufficient length of time to stabilize the
cabin conditions and tailpipe emission
levels. EPA believes that this test would
account for the CO2 contributions from
most of the key A/C system components
and modes of operation.
The additional CO2 generated when
the A/C is operated during the Idle Test
would then be normalized to account
for the interior cabin volume of the
vehicle. This normalization is necessary
because the size and capacity of an A/
C system is related to the volume of air
that an A/C system must cool. Rather
than simply reporting the vehicle’s CO2
emissions, this normalization would
provide a more appropriate metric of
CO2 emissions to compare systems that
must cool relatively larger volumes with
those that cool smaller volumes. EPA
proposes that the interior cabin volume
be defined as the volume of air that the
air conditioner cools, which includes
the volume of space used by passengers
and, in some vehicles, the volume used
for cargo. The proposed calculation of
interior cabin volume is adapted from
an industry protocol, Society of
Automotive Engineers (SAE) Surface
Vehicle Standard J1100.
The proposed A/C CO2 Idle Test
would require three approximately 10minute periods of CO2 emissions
measurement once the vehicle’s cabin
conditions and climate control system
have stabilized in order to quantify the
A/C related CO2. The test would be run
at 75 °F, the standard temperature of the
FTP. As discussed below, EPA
considered proposing a more complex
procedure that would be performed at a
higher temperature, such as the 95 °F
used in the SC03 test. However, we
PO 00000
Frm 00142
Fmt 4701
Sfmt 4702
believe that A/C-related CO2 can be
accurately demonstrated on the Idle
Test at 75 °F, avoiding the significant
facility and testing issues associated
with higher temperature testing. In
order to better simulate ‘‘real world’’
idling conditions, we propose that the
A/C CO2 Idle Test be performed with
the engine compartment hood and
windows closed and without operating
the test site cooling fan that is usually
used to simulate the motion of the
vehicle on the road.
The proposed A/C CO2 Idle Test
procedure specifies how climate control
systems, whether manual or automatic,
would need to be set to appropriately
simulate the maximum and minimum
cooling demands on the A/C system.
CO2 exhaust emission measurements, in
grams per minute, would be taken
during both of these modes.
Manufacturers would conduct the idle
test following the completion of a FTP
certification test, a fuel economy test, or
a test over the US06 cycle. As discussed
above, manufacturers would measure
the change in CO2 due to A/C operation
in grams per minute and then would
divide this value by the interior volume
in cubic feet, for an A/C CO2 emission
value in terms of grams per minute per
cubic foot. The manufacturer would
report this value to EPA with other
emission results.
EPA also requests comment on three
different approaches that could be used
alone or in combination with the
proposed A/C CO2 Idle Test or with
each other. Each of these tests would
capture a somewhat different set of
aspects of A/C-related CO2 emissions.
First, EPA is seeking comment on basing
reporting requirements on the SC03 test
(or some variant of this test), which, as
described above, is designed to simulate
more extreme driving conditions than
the standard certification tests. Using
the SC03 test to determine A/C-related
CO2 performance would likely require
manufacturers to run tests in additional
modes or to repeat the test in order to
capture more real-world A/C usage (i.e.,
a stabilized cabin temperature).
Therefore such an approach could
involve significant modifications to the
SC03 test procedure. The rationale for
considering such an adapted SC03 test
would be to characterize more systemic
technological features (such as thermal
management and transient A/C control)
that may not be captured in a 75 °F idle
test or a bench test (as discussed below).
Second, EPA is seeking comment on
basing reporting requirements on a
‘‘bench’’ test procedure similar to the
one being developed by the SAE and the
University of Illinois, which was
employed to measure A/C efficiency
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
improvements for the industry/
government Improved Mobile Air
Conditioning project. This bench test
only measures the power consumption
of the A/C compressor with simulated
loads, and is not integrated into a
vehicle (as would be the case in the
proposed A/C CO2 Idle Test, which is a
‘‘chassis,’’ or whole-vehicle, test). The
purpose of the bench test for
characterizing A/C-related CO2
emissions would be to have a relatively
repeatable test that could represent a
variety of temperature and humidity
conditions around the country. Unlike a
chassis test, there would not be a direct
connection to a vehicle’s interior
volume, and we would need to develop
assumptions about a vehicle’s interior
volume in order to normalize the
results. This test procedure might be
less expensive than a modified SC03
test.
Finally, EPA is seeking comment on
basing reporting requirements on
design-based criteria for characterizing
A/C-related CO2 emissions. Designbased criteria would be conceptually
similar to the ones proposed for leakage
emissions characterization as described
below. A manufacturer would choose
technologies from a list provided by
EPA in the rule where we would specify
the A/C-related CO2 characteristics
associated with each major component
and technology, including system
control strategy and systems integration.
While such a design-based approach
might capture the expected CO2
emissions of individual components
and controls, it would not necessarily
capture overall system A/C-related CO2
(when the A/C components would be
integrated into the vehicle and would
interact with the engine, cabin
conditions, and other vehicle
characteristics, such as the under-hood
environment).
Calculating and Reporting a ‘‘Score’’
for A/C-Related Refrigerant Leakage. As
part of most of EPA’s existing mobile
source emissions testing and
certification programs, where robust test
procedures have been developed and
are in widespread use, EPA has relied
on ‘‘performance-based’’ approaches,
where emissions are measured directly
during vehicle or engine operation to
determine emission levels. Examples of
performance-based test procedures
include the FTP and the proposed A/C
CO2 Idle Test discussed above. In the
case of A/C refrigerant leakage, where it
is known that leakage of refrigerants
with high GWPs occurs, a reliable,
performance-based test procedure to
measure such emissions from a vehicle
does not yet exist. Instead, we are
proposing a ‘‘design-based’’ approach to
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
establish a vehicle’s expected refrigerant
leakage emissions.
Under our proposal, each key A/Crelated component and system would be
assigned an expected rate of refrigerant
leakage, in the form of a leakage
‘‘score,’’ in terms of grams per year.
These individual scores would be added
to result in an overall leakage score for
the vehicle. We propose that
manufacturers establish an overall
leakage score for the same test vehicle(s)
on which they run the A/C CO2 Idle
Test, as described above.
The cooperative industry and
government Improved Mobile Air
Conditioning Program referenced above
also has developed a comprehensive set
of leakage scores that EPA proposes to
use to represent the significant sources
of A/C refrigerant leakage from newer
vehicles. The Improved Mobile Air
Conditioning Program and the SAE have
established a template for calculating
individual leakage scores based on the
quantity and type of components,
fittings, seals, and hoses utilized in a
specific A/C system design; this
template is known as the SAE Surface
Vehicle Standard J2727. EPA is
proposing a set of component and
system leakage scores, based closely on
J2727, but expanded to place greater
emphasis on characterizing leakage
emissions later in the vehicle’s life. Like
the J2727, this proposed EPA protocol
would associate each technology or
system design approach with a specific
leakage score. Each score would be a
design-based, ‘‘leakage-equivalent’’
value that would take into account
expected early-in-life refrigerant leakage
from the specified components and
systems. Manufacturers would report
this value to EPA on their application
for certification.
In addition, we request comment on
the whether other A/C design
considerations, such as use of
alternative refrigerants, monitoring
refrigerant leakage (with fault storage
and indicators), and minimizing
refrigerant quantity, should be used in
determining an A/C leakage score.
d. Highway Heavy-Duty Diesel and
Gasoline Vehicles and Engines
EPA’s highway heavy-duty vehicle
and engine emissions testing and
certification programs generally cover
vehicles above 8,500 pounds Gross
Vehicle Weight Rating.121 For most large
trucks, manufacturers are required to
measure and report criteria air pollutant
emissions data for engines rather than
vehicles. Engine manufacturers measure
121 See 40 CFR 1803–01 for full definitions of
‘‘heavy-duty vehicle’’ and ‘‘heavy-duty engine.’’
PO 00000
Frm 00143
Fmt 4701
Sfmt 4702
16589
and report emissions prior to the
engines being sold to separate
companies that build trucks or buses
and install engines in them.
Manufacturers of gasoline-fueled
complete vehicles below 14,000 pounds
Gross Vehicle Weight Rating, such as
large pick-ups and SUVs, are required to
measure and report vehicle emissions,
as do manufacturers of light-duty
vehicles. These vehicles are described
as ‘‘complete’’ vehicles because the
vehicles leave the primary
manufacturing facility fully assembled,
with the engine and associated
hardware installed and the loadcarrying container attached.
Manufacturers That Certify Engines.
EPA proposes to require manufacturers
to report CO2 emissions from highway
heavy-duty diesel and gasoline engines.
All manufacturers currently measure
CO2 as an integral part of calculating
emissions of criteria pollutants, and
some report CO2 emissions in some
form. We propose that engine
manufacturers report CO2 to EPA with
criteria pollutant emission results and,
as with the criteria emissions, report the
CO2 emissions in terms of brake-specific
emissions (i.e., in units of grams of CO2
per brake-horsepower-hour).
We also propose that highway heavyduty engine manufacturers measure and
report CH4 emissions. This would
require most manufacturers to install
CH4 exhaust analytical equipment or to
arrange for testing at another facility.
This equipment is usually designed to
be installed as a modular addition to
existing analytical equipment.
Procedures for analyzing CH4 are
currently in place.
Finally, we also propose that these
manufacturers measure and report N2O.
As with CH4, this would require most
manufacturers to install new, usually
modular, N2O exhaust analytical
equipment, or to arrange for testing at
another facility. Because it has not been
necessary in the past to measure N2O,
we are proposing a new procedure for
measuring N2O (see proposed 40 CFR
1065.257 and 1065.357).
As with CO2, manufacturers would
measure both CH4 and N2O as a part of
the existing FTP for heavy-duty engines
and report the results to EPA with other
criteria pollutant emission test results.
Manufacturers That Certify Complete
Highway Heavy-Duty Vehicles. We
propose that manufacturers certifying
complete heavy-duty vehicles be subject
to the same measurement and reporting
requirements as manufacturers of heavyduty engines. Thus, as described above,
these manufacturers would report the
CO2 emissions they are currently
measuring as part of criteria air
E:\FR\FM\10APP2.SGM
10APP2
16590
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
pollutant emissions testing and would
additionally measure and report CH4
and N2O. Although vehicle emissions
testing (also known as ‘‘chassis testing’’)
is different than engine-only testing,
measurement procedures are the same,
and we are proposing measurement and
reporting requirements for complete
heavy-duty vehicles that are essentially
identical to our proposed requirements
for heavy-duty engines.
However, manufacturers of complete
heavy-duty vehicles, unlike heavy-duty
engine manufacturers, are generally
responsible for installing the vehicle’s
A/C equipment. For this reason, we
propose that these manufacturers be
responsible for reporting A/C-related
emissions, in exactly the same ways that
we are proposing for light-duty
manufacturers, as described in Section
V.QQ.3.c of this preamble. Thus, we
propose that these manufacturers
perform the A/C CO2 Idle Test and
report the A/C-related CO2 emissions.
We also request comment on the
potential applicability of the alternate
A/C CO2 measurement procedures
discussed above to manufacturers of
complete heavy-duty vehicles. In
addition, we propose that these
manufacturers calculate and report an
overall A/C refrigerant leakage ‘‘score,’’
using the same assigned component and
system scores we have developed for the
proposed light-duty scoring system.
Vehicle Manufacturers That Install
Certified Engines. We are not proposing
any requirements for the heavy-duty
truck and bus manufacturers that install
certified engines into their vehicles.
These truck manufacturers currently are
not required to certify their trucks to
EPA emissions standards and do not
conduct emissions testing. However, we
recognize that these vehicles are
generally equipped with A/C systems by
the truck or bus manufacturer. We
request comment on the
appropriateness, feasibility, and cost of
extending some form of the proposed
A/C CO2 Idle Test and refrigerant
leakage score requirements discussed
above for manufacturers of complete
heavy-duty trucks to these truck and bus
manufacturers as well. In addition, we
request comment on how originalequipment or aftermarket auxiliary
power units—if used to provide power
for cabin A/C—might be incorporated
into a GHG reporting program.
e. Nonroad Diesel Engines and Nonroad
Large Spark-Ignition Engines
Nonroad diesel engines and nonroad
large spark-ignition (generally gasolinefueled) engines are used in a wide
variety of construction, agricultural, and
industrial equipment applications.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
However, these engines are very similar
(in terms of design, technology, and
certification process) to their
counterparts certified for highway
operation. Given these similarities, we
propose that manufacturers of these
engines measure and report CO2, CH4,
and N2O in the same manner as
manufacturers of highway heavy-duty
diesel and gasoline engines, as
described earlier in this section of the
preamble.
Like highway heavy-duty truck and
bus manufacturers that use certified
engines, nonroad diesel equipment
manufacturers install certified engines
into their equipment but do not certify
their equipment. As with trucks and
buses, this equipment is often equipped
with A/C systems. While we are not
proposing any reporting requirements
for nonroad equipment manufacturers,
we request comment on the
appropriateness, feasibility, and cost of
extending some form of the proposed A/
C CO2 Idle Test and refrigerant leakage
score reporting requirements discussed
above to nonroad equipment
manufacturers. We also request
comment on extending A/C-related GHG
reporting requirements to transportation
refrigeration units that are equipped
with separate engines that are certified
under EPA’s nonroad engine program.
f. Nonroad Small Spark-Ignition
Engines, Marine Spark-Ignition Engines,
Personal Watercraft, Highway
Motorcycles, and Recreational Engines
and Vehicles
There is a large range of spark-ignition
engines in this category including
engines used in portable power
equipment, snowmobiles, all terrain
vehicles, off-highway motorcycles,
automotive-based, inboard engines used
in marine vessels. For purposes of this
proposed reporting rule, we also include
highway motorcycles, which are tested
as complete vehicles. We are proposing
that manufacturers measure and report
CO2, CH4, and N2O emissions for these
engines and vehicles. As part of existing
criteria pollutant emissions testing
requirements, manufacturers must
determine the amount of fuel consumed
either through direct measurement or
through chemical balances of the fuel,
intake air, and exhaust. With the
‘‘chemical balance’’ approach, CO2
levels in the intake air and exhaust are
measured (along with either the intake
air flow rate or exhaust flow rate), and
fuel consumption is calculated based on
fuel properties and the change in CO2
level between the intake and exhaust
flows. (CO2 levels with associated flow
rates can be used to calculate a CO2
emission rates). Alternatively, when a
PO 00000
Frm 00144
Fmt 4701
Sfmt 4702
‘‘direct measurement’’ approach is used
to determine fuel consumption, there is
no need to measure CO2 levels in the
intake air or exhaust. For manufacturers
that generally use only the direct
measurement approach, new analysis
equipment might be required to measure
CO2 levels in the intake air and exhaust.
We propose that manufacturers measure
and report cycle-weighted CO2
emissions (in the same ‘‘grams-per-unitof-work’’ format used for criteria
pollutant emissions reporting) for all
engines in these categories, regardless of
the method used to determine fuel
consumption. We also propose that
highway motorcycle manufacturers
measure and report CO2 in terms of
grams per mile.
For CH4, many of the engines
described above are subject to ‘‘total’’
hydrocarbon, or ‘‘hydrocarbon + NOX ’’
standards (as opposed to ‘‘non-CH4’’
hydrocarbon standards applying to
some other categories), and thus CH4
emissions may not typically be
measured. In these cases, the
manufacturers would need to install
CH4 emissions analysis equipment. We
propose that manufacturers report cycleweighted CH4 emissions for these
engines and for highway motorcycles.
Finally, we are proposing that
manufacturers also report the cycleweighted N2O emissions for these
engines and for highway motorcycles.
As with CH4, manufacturers would
likely need to install N2O emissions
analysis equipment. The proposed new
procedure for measuring N2O is found
in the draft regulations (40 CFR
1065.257 and 1065.357).
g. Locomotive and Marine Diesel
Engines
We are proposing that manufacturers
of locomotive and marine diesel
engines—including those who certify
‘‘remanufactured’’ engines—measure
and report CO2, CH4, and N2O emissions
for locomotive and marine diesel
engines. Manufacturers of these engines
already measure CO2 emissions during
the course of existing criteria air
pollutant emission testing requirements,
but generally do not report this to EPA.
For manufacturers of these engines, we
propose that CO2 emissions be reported
in the same cycle-weighted, work-based
format (i.e., g/bhp-hr) as used for criteria
pollutant emissions reporting. For C3
marine diesel engines, we are requesting
comment on whether indirect CO2
measurement (i.e., calculating the CO2
levels based on fuel flow rate and fuel
composition parameters) is an
appropriate method for those
manufacturers that do not utilize CO2
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
analysis equipment in the course of
emission testing.
Since diesel locomotives are subject
to ‘‘total’’ hydrocarbon standards (which
include CH4 in the measured and
reported hydrocarbon value), as
opposed to ‘‘non-CH4’’ hydrocarbon
standards (which do not include CH4),
manufacturers typically do not measure
CH4 emissions. With the exception of C3
marine diesel engines (which do not
have any ‘‘hydrocarbon’’ emission
standards, and are not required to
measure hydrocarbon or CH4
emissions), we propose that
manufacturers measure and report CH4
emissions as a part of certification. To
do so, we expect that some
manufacturers would need to install
equipment for analyzing CH4 emissions.
We also propose that manufacturers—
except for C3 marine—measure and
report N2O emissions as well. For C3
marine diesel engines, we are requesting
comment on the appropriateness and
feasibility of requiring N2O
measurement and reporting on the small
number of engines represented by this
category. As with CH4, we expect that
most or all manufacturers would need to
install N2O emissions analysis
equipment. The proposed new
procedure for measuring N2O is found
in the proposed regulations (40 CFR
1065.257 and 1065.357).
h. Aircraft Engines
This category comprises turbofan,
turbojet, turboprop (turbine-driven
propeller), turboshaft (turbine-driven
helicopters), and piston propulsion
engines for commercial, air taxi, and
general aviation aircraft. In the case of
turbofan and turbojet engines of rated
output (or thrust) greater than 26.7
kilonewtons, manufacturers of these
engines are already measuring and
recording CO2 emissions as part of
existing criteria air pollutant emission
requirements for the landing and takeoff
cycle. In this notice, we propose that
manufacturers measure, record and
report CO2 separately for each mode of
the landing and takeoff (LTO) cycle
used in the emission certification test,
as well as for the entire landing and
takeoff cycle. (The modes of the landing
and takeoff cycle are taxi/idle, takeoff,
climb out, and approach.)
CH4 may be emitted by gas turbine
engines during idle and by relatively
older technology engines, but recent
data suggest that little or no CH4 may be
emitted by some newer engines.
Manufacturers of turbofan and turbojet
engines of rated output greater than 26.7
kilonewtons are currently measuring
hydrocarbon emissions as part of
existing criteria air pollutant emissions
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
testing, and CH4 is included in the total
hydrocarbon measurement. We propose
that manufacturers of these engines
begin to separately measure and report
CH4 for all engines in this category for
which they are currently required to
measure and record criteria air pollutant
emissions as part of the certification
process. Some manufacturers may need
to acquire CH4 emissions analysis
equipment. We ask for comment on the
degree to which engine manufacturers
now have the needed equipment in their
certification test cells to measure CH4.
Since little or no N2O is formed in
modern gas turbine engines, we are not
proposing to require N2O measurement
or reporting.
Within the mobile source sector, NOX
is a climate change gas unique to
aviation. As required in 40 CFR part 87,
manufacturers of turbofan and turbojet
engines of rated output greater than 26.7
kilonewtons measure and record NOX
emissions in each of the four LTO test
modes, and these manufacturers must
comply with the LTO NOX emission
standard (for the entire LTO cycle). EPA
asks for comment on whether NOX
emissions in the four LTO test modes
and for the overall LTO cycles should be
reported under the provisions of this
proposal, as they are now not reported
to EPA for public consideration as is the
case with all other mobile sources.122
EPA does not currently require
manufacturers of piston engines (used
in any application) to measure, record
or report criteria air pollutant or GHG
emissions, and no official FTP exists for
these engines.123 For these reasons, we
are not proposing any GHG reporting
requirements for these engines.
However, we request comment on the
potential costs and benefits of reporting
requirements for GHG emissions from
these engines, including how an
appropriate emission test cycle might be
designed. We also ask for comment on
whether the requirements should be
applied to turbofan and turbojet engines
of rated output less than or equal to 26.7
kilonewtons, turboprop engines, and
turbo shaft engines which are not now
122 Currently, these engine manufacturers
voluntarily report criteria air pollutant emissions
for the LTO cycle to the International Civil Aviation
Organization.
123 EPA received an administrative petition
asking the agency to determine under section 231
of the CAA whether lead emissions from general
aviation (piston engine) aircraft cause or contribute
to air pollution which may reasonably be
anticipated to endanger public health or welfare,
and, if so, to establish standards for such emissions.
Today’s proposal regarding GHG emissions from
piston-engine aircraft is not intended to respond in
any way to the petition regarding general aviation
lead emissions.
PO 00000
Frm 00145
Fmt 4701
Sfmt 4702
16591
regulated under 40 CFR 87 requirements
for criteria air pollutant emissions.124
4. Request for Comments on Travel
Activity and Other In-Use, EmissionsRelated Data
Travel activity and other emissionsrelated data from State and local
governments and fleet operators are
critical to understanding the overall
GHG contribution of the mobile source
sector. These data serve the important
role of reflecting real-world conditions
and capturing activity levels (e.g.,
distance traveled and hours operated)
from all vehicles and engines, which
can complement data that
manufacturers report on expected
emissions rates from new vehicles and
engines. EPA already receives some inuse data through existing reporting
programs. The purpose of this section of
the preamble is to describe these
existing data sources and to request
public comment on the need for
additional data. In Section V.QQ.4.a of
this preamble, we describe data
currently reported by State and local
governments, and request comment on
the potential benefits of the collection of
additional data. In Section V.QQ.4.b of
this preamble, we highlight the types of
data reported by fleet operators as part
of the SmartWay Transport Program or
other Federal programs, and request
comment on the value of other potential
reporting requirements.
a. Travel Activity and Other Data From
State and Local Governments
Travel activity is a term EPA
primarily uses for on-road vehicle
activity and includes the number and
type of vehicles and the distance they
travel. State and local governments
collect many types of travel activity
data, including VMT by vehicle type
and model year, fuel type, and/or
functional road class (e.g., limited
access highways, arterials with traffic
signals, etc.). Other types of emissionsrelated data include vehicle operation
and environmental conditions that can
affect emissions during travel, such as
idling practices and ambient
temperature. Travel activity and other
emissions-related data can vary over
time, between regions, and between
metropolitan and rural areas within a
given State. EPA can use these data to
evaluate how changes in vehicle
124 Existing regulations in 40 CFR part 87 include
smoke number standards for turbofan and turbojet
engines of rated output less than or equal to 26.7
kilonewtons and turboprop engines of rated output
greater than or equal to 1,000 kilowatts.
Requirements for the term turboshaft engine are
currently not specified in 40 CFR part 87.
E:\FR\FM\10APP2.SGM
10APP2
16592
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
technology or travel activity can affect
emissions.
EPA currently collects on-road mobile
source data to better understand criteria
air pollutant emissions, and some of
these data can also be used to
understand GHG emissions. For
example, States provide VMT data to
the Agency through the AERR.125 EPA
currently relies on AERR data to
develop the NEI 126 which is used for,
among other things, evaluating Federal
vehicle and fuel standards for criteria
pollutants and mobile source air toxics.
The AERR requires State air agencies
to report mobile source data, including
VMT data at the county level by
roadway type, 127 every three calendar
years beginning with the 2002 calendar
year (i.e., states report mobile source
inventories for 2005, 2008, 2011, etc.).
The most recent submissions are for the
2005 calendar year. Although not
required by the rule, EPA understands
that some State air agencies consult
with State and local transportation
agencies in preparing VMT data
submissions. States also submit other
information that can be used to estimate
criteria pollutant emissions, e.g., age
and speed distributions of vehicles by
vehicle class and roadway type, fuel
properties by county, month, and year,
and temperature and humidity data by
county, month, and year. The AERR also
requires certain emissions-related
information, such as activity data (e.g.,
hours/day of operation), for nonroad
mobile sources, according to similar
submission requirements as described
above.
In addition to EPA’s existing data
collection requirements, there are other
sources of travel activity and emissionsrelated data. DOT currently collects
statewide VMT data for urban and rural
roadway types through its Highway
Performance Monitoring System. DOT
and DOE also publish statistical reports
such as the Census Transportation
Planning Package, National Personal
Transportation Survey, and the Urban
Mobility Study. In the past, the U.S.
125 EPA promulgated the AERR in December 2008
(73 FR 76539) (40 CFR part 51, subpart A). EPA
promulgated the AERR to consolidate, reduce, and
simplify the current requirements; add limited new
requirements; provide additional flexibility to states
in the ways they collect and report emissions data;
and accelerate the reporting of emissions data to
EPA by state and local agencies. The AERR replaces
the Consolidated Emissions Reporting Rule (CERR)
which was promulgated in June 2002 (67 FR 39602)
in part to streamline existing periodic emissions
inventory requirements for criteria pollutants.
126 EPA prepares a national database of air
emissions information from numerous state and
local air agencies, from tribes, and from industry:
https://www.epa.gov/ttn/chief/eiinformation.html.
127 Under the AERR, VMT data should reflect
both roadway type and vehicle type information.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Census Bureau conducted the Vehicle
Inventory and Use Survey, which
provided valuable data on the physical
and operational characteristics of the
nation’s private and commercial truck
populations.128 In specific geographic
areas, agencies such as metropolitan
planning organizations, State
departments of transportation, transit
agencies, air quality agencies, and
county planning agencies also collect
and project State and local travel
activity and emissions data to meet
Federal requirements, such as DOT’s
transportation planning requirements
and EPA’s SIP and transportation
conformity requirements.
In light of the existing data available
to EPA, the Agency is not proposing any
new reporting requirements for State
and local governments at this time.
However, EPA is interested in
requesting comment on several topics.
(1) Should EPA require States, local
governments, or other entities to report
additional travel activity or emissionsrelated data beyond what is required
under EPA’s existing reporting
requirements? How would such data be
used to inform future climate policy?
(2) What, if any, are the specific gaps
in the currently reported travel activity
or emissions-related data that are
important for understanding on-road
mobile source GHG emissions? For
example, would it be helpful for EPA to
better understand State- or county-level
VMT growth rates (e.g., based on VMT
data collected over the past five or ten
years or other methodology) or
emissions data related to the freight
sector (e.g., hours of long-duration truck
idling or truck data that was previously
provided by the Vehicle Inventory and
Use Survey)? What is the quality of
currently reported State and local VMT
data, and should travel activity and
emissions-related data quality be
improved?
(3) Is it sufficient to collect travel
activity or emissions-related data every
three years as currently required, or
should EPA collect such data on an
annual basis, similar to other collections
discussed in today’s action?
(4) Should EPA consider any
threshold(s) for States, local
governments, or other entities that must
report additional travel activity or other
emissions-related data? For example,
should additional data be reported only
from larger metropolitan areas with
more sophisticated transportation
systems (e.g., metropolitan planning
128 The
primary goal of the Vehicle Inventory and
Use Survey database was to produce national and
state-level estimates of the total number of trucks.
This survey was conducted every 5 years, until it
was discontinued in 2002.
PO 00000
Frm 00146
Fmt 4701
Sfmt 4702
organizations with an urbanized
population of 200,000 or more)?
(5) What nonroad activity data is of
most interest for understanding GHG
emissions, and should EPA consider
any additional requirements for
reporting such data beyond what is
currently required?
b. Mobile Source Fleet Operator Data
Mobile source fleet operators 129 are in
a unique position to collect data that
reflect real-world conditions that are
difficult to integrate into vehicle and
engine testing procedures or to capture
in travel activity surveys. Fleet operator
data includes fuel consumption, which
can be robustly converted into CO2
emissions, distance traveled, and the
number and/or weight of passengers and
freight transported. EPA currently
collects fleet operator data from sources
that include DOT surveys such as the
Vehicle Inventory and Use Survey
(described in Section V.QQ.4.a of this
preamble, but discontinued in 2002), inuse testing as part of vehicle and engine
manufacturer compliance programs, adhoc internal and external field studies
and surveys, and voluntary programs
such as the SmartWay Transport
Partnership. The rest of this section of
the preamble describes the data EPA
collects as part of our voluntary
programs as well as the DOT’s (DOT)
rail and aviation fleet reporting
requirements, and requests comment on
the need for, and substance of, any
additional reporting requirements.
EPA believes that one of the most
important functions of collecting fleet
operator data is to inform operators
about their emissions profiles and to
shed light on opportunities to reduce
emissions through the use of clean
technologies, fuels, and operational
strategies. Through the SmartWay
Transport Partnership program, EPA
requires participating truck and rail
equipment operators, or ‘‘partners,’’ to
report data as part of their voluntary
commitment to measure and improve
the environmental performance of their
fleets. EPA uses this data to evaluate
partner performance. Partners report
annually on their fuel consumption by
fuel type, miles traveled, and tonnage of
freight carried. Truck operators also
have the option of reporting the
configuration and model year of each of
their trucks. There is no minimum
emissions reporting threshold for either
truck or rail operators. EPA requires
partners to report their annual data
129 For the purpose of our request for comments,
‘‘fleet operators’’ are defined as entities that have
operational control over mobile sources.
‘‘Operational control’’ is defined as having the full
authority to introduce and implement operational,
environmental, health, and safety policies.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
through the SmartWay Freight Logistics
Environmental and Energy Tracking
performance model.130 The SmartWay
Freight Logistics Environmental and
Energy Tracking model translates the
partners’ fuel consumption data into
CO2 emissions based on EPA’s default
emissions factors for fuels. EPA does not
publicly release individual partners’
emissions data. At present, the
SmartWay Transport Partnership has
received annual data from more than
400 trucking companies and all seven
Class I rail companies. These partners’
CO2 emissions represent approximately
20 percent and 80 percent, respectively,
of the 2005 national inventory of
trucking and rail GHG emissions.131
EPA’s Climate Leaders program also
requires participating companies that
operate mobile sources to report CO2,
N2O, CH4, and HFC emissions from
those sources annually as a part of their
voluntary commitment to develop a
comprehensive, corporate-wide GHG
inventory. There are no minimum
emissions reporting thresholds for
mobile sources. Companies quantify
mobile source emissions based on the
Climate Leaders reporting protocol,132
which outlines several methods for
calculating CO2 including applying
EPA’s default factors to fuel
consumption data. The reporting
protocol also includes default N2O and
CH4 factors for non-road fuel
consumption and on-road miles traveled
by vehicle model year or technology
type. Additionally, the reporting
protocol includes default HFC leakage
factors for mobile A/C units. As with
SmartWay, EPA does not publicly
release individual participating
companies’ emissions data. Currently,
the Climate Leaders program has
received mobile source data from 37
companies representing roughly 0.09
percent of the 2005 national inventory
of transportation sector GHG
emissions.133
In addition, DOT collects and
publicly releases extensive data from
rail and aircraft operators. All seven
Class I 134 rail operators are required to
130 The SmartWay Freight Logistics
Environmental and Energy Tracking model and
accompanying user guide and glossary is available
at https://www.epa.gov/otaq/smartway/
smartway_fleets_software.htm.
131 Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990–2005, EPA, 2007.
132 See Direct Emissions from Mobile Combustion
Sources and Direct HFC and PFC Emissions from
Use of Refrigeration and Air Conditioning
Equipment, available at https://www.epa.gov/
climateleaders/resources/cross-sector.html.
133 Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990–2005, EPA, 2007.
134 A ‘‘Class I railroad’’ is defined as a carrier that
has an annual operating revenue of $250 million or
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
report annual fuel consumption and
ton-miles, among other data, to the
Surface Transportation Board per the
reporting guidelines in 49 U.S.C. 11145.
Large certificated air carriers,135 small
certificated air carriers, and commuter
air carriers with more than $20,000,000
in annual operating revenues must
report monthly fuel usage data to the
Bureau of Transportation Statistics via
Form 41 pursuant to 14 CFR part 217
and part 241. Large certificated air
carriers must also report monthly traffic
data including distance traveled,
tonnage of freight transported, and
number of passengers transported.
In light of the existing data available
to EPA, the Agency is not proposing
mandatory reporting requirements for
mobile source fleet operators, but is
requesting comments on the need for,
and substance of, potential reporting
requirements at this time. We request
comment on the following questions:
(1) Should fleet operators be required
to report to EPA outside of voluntary
participation in the SmartWay or
Climate Leaders programs? How would
this data be used to inform future
climate policy?
(2) Are there certain categories of
mobile sources that should be included
or excluded in potential reporting
requirements (e.g., lawn mowers,
commercial light-duty vehicles, heavyduty trucks, rail equipment, aircraft,
waterborne vehicles)?
(3) Should one or more minimum
emissions thresholds apply based on the
mobile source category, and what would
be appropriate annual thresholds?
(4) Are there certain categories of
fleets that should be included or
excluded from potential reporting
requirements (e.g., public fleets versus
private fleets)?
(5) If reporting requirements were to
be introduced, what types of data
should operators report (e.g., fuel
consumption for estimating CO2 and
non-road N2O and CH4 emissions;
mileage and vehicle technology for
estimating on-road N2O and CH4
emissions; efficiency metrics such as
emissions per tons carried)?
more after applying the railroad revenue deflator
formula, which is based on the Railroad Freight
Price Index developed by the U.S. Department of
Labor, BLS. The formula is the current year’s
revenues x 1991 average index/current year’s
average index.
135 The definition of ‘‘large certified air
carrier’’,‘‘small certified air carrier’’, and
‘‘commuter air carrier’’ for Form 41 reporting
requirements is available at: https://www.bts.gov/
programs/statistical_policy_and_research/
source_and_accuracy_compendium/
form41_schedule.html.
PO 00000
Frm 00147
Fmt 4701
Sfmt 4702
16593
(6) What type of data verification or
quality control should EPA require in
any potential reporting requirements?
(7) For potential reporting
requirements, are there preferred
emissions quantification methods other
than those presented in the SmartWay
Freight Logistics Environmental and
Energy Tracking model or the Climate
Leaders reporting protocol?
VI. Collection, Management, and
Dissemination of GHG Emissions Data
A. Purpose
This section of the preamble describes
the process by which EPA proposes to
collect, manage, and disseminate data
under the GHG reporting rule.
Section V.B of this preamble describes
the proposed establishment of a new
reporting system that would accept
electronic submissions of GHG
emissions and supporting data, quality
assure the submissions, store the results,
and provide access to the public. The
new system would follow Agency
standards for design, security, data
element and reporting format
conformance, and accessibility.
Existing sources that would be
affected by the proposed GHG reporting
rule may currently report emissions or
other data to the Agency (or in some
cases States) under other titles of the
CAA including Title I (Emission
Inventory, SIP, NSPS and NESHAP),
Title II (National Emissions Standards
Act), Title IV (Acid Rain), Title V (Air
Operating Permits) and Title VI
(Stratospheric Ozone Protection). EPA
intends to develop a reporting scheme
that minimizes the burden of
stakeholders by integrating the new
reporting requirements with existing
data collection and data management
systems, when feasible. Also, EPA
would work with States to ease the
burden on reporters to State and Federal
systems by harmonizing data
management, where possible.
Section VI.B of this preamble further
describes the proposal regarding the
frequency and timeliness of reporting,
the requirement for a Designated
Representative certification, and the
units of measure for submissions and
published results.
Section VI.C of this preamble
describes QA that EPA would perform
to ensure the completeness, accuracy,
and validity of submissions. It also
describes the feedback that EPA would
provide to emission reporters indicating
the results of the electronic data quality
checks.
Section VI.D of this preamble
discusses publication of data that would
be collected under the proposed
E:\FR\FM\10APP2.SGM
10APP2
16594
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
mandatory GHG reporting rule. EPA
proposes to make data collected under
this rule available to State agencies and
the public, with the exception of any
CBI data, as discussed in Section I.C of
this preamble. EPA requests comments
on proposed strategies regarding data
collection, management, and
dissemination outlined in this section of
the preamble.
B. Data Collection
1. Data Collection Methods
If a reporting source already reports
GHG emissions data to an existing EPA
program, the Agency would make efforts
to minimize any additional burden on
the sources. Some existing programs,
however, have data collection and
reporting requirements that are
inconsistent with the proposed
requirements for the mandatory GHG
reporting rule. When it is not feasible to
adapt the existing program to collect the
appropriate emissions data and
supplemental data, EPA proposes to
require affected sources to submit the
data in the requested format to the new
data reporting system for the mandatory
GHG reporting rule.
Emission sources may fall into one or
more categories:
(1) Reporting sources that use existing
data collection and reporting methods
and would not be required to report
separately to the new data reporting
system for the GHG reporting rule.
(2) Reporting sources that use existing
data collection and reporting methods
but would be required to report the data
separately to the new data reporting
system for the GHG reporting rule.
(3) Reporting sources that are not
currently required to collect and report
GHG emissions data to EPA and would
be required to report using the new data
reporting system for the mandatory GHG
reporting rule.
EPA believes that using existing data
collection methods and reporting
systems, when feasible, to collect data
required by this proposed rule would
minimize additional burden on sources
and the Agency. We seek comment on
the use of existing collection methods
and reporting systems to collect
information required by this proposed
rule.
For those sources that do not report
GHGs or data used to calculate GHG
emissions through an existing reporting
system, EPA proposes to develop a new
system for emission reporters to submit
the required data. The detailed data
elements that would be reported and
other requirements are specified in
Sections III, IV and V of this preamble.
In general, reporters using this new
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
method would report annually to the
Agency covering each calendar year by
March 31 of the following year (e.g.,
annual emissions for calendar year 2010
would be reported by March 31, 2011.)
unit of time and CO2e emissions per
unit of time. Reporting the quantity and
type of gas emitted allows for future
recalculation of CO2e emissions in the
event that GWP factors change.
2. Data Submission
The Designated Representative
(described in proposed 40 CFR part 98,
subpart A and Section IV.G of this
preamble) must use an electronic
signature device (for example, a PIN or
password) to submit a report. If the
Designated Representative holds an
electronic signature device that is
currently used for valid electronic
signatures accepted under another
Agency program, we propose that the
new reporting system would also accept
valid electronic signatures executed
with that device where feasible. (See 40
CFR 3.10 and the definitions of
‘‘electronic signature device’’ and ‘‘valid
electronic signature’’ under 40 CFR 3.3.)
6. Delegation of Authority to State
Agencies To Collect GHG Data
The Agency proposes that affected
sources submit the emissions data and
supplemental data directly to EPA. The
Agency believes this would reduce the
burden on reporters and State agencies,
provide faster access to national
emission data, and facilitate consistent
QA.
Under CAA Section 114(b), EPA may
delegate the authority to collect
emissions data from stationary sources
to State agencies provided the State
agency can satisfy the procedural
requirements. We seek comment on the
possibility of delegating the authority to
State agencies that request such
authority and assessing whether the
State agency has procedures that are
deemed consistent and adequate with
the procedures outlined in this rule. For
example, how should EPA determine
whether a requesting State agency has
‘‘consistent and adequate’’ procedures?
3. Unique Identifiers for Facilities and
Units
We believe that the Agency’s
reporting format for a given reporting
year could make use of several ID
codes—unique codes for a unit or
facility. To ensure proper matching
between databases, e.g., EPA-assigned
facility ID codes and the ORIS (DOE) ID
code, and consistency from one
reporting year to the next, we are
proposing that the reporting system
provide each facility with a unique
identification code to be specified by
the Administrator.
4. Reporting Emissions in a Single Unit
of Measure
To maintain consistency with existing
State-level and Federal-level greenhouse
gas programs in the U.S. and
internationally, the Agency is proposing
that all emission measurements be in
the SI, also referred to as metric, units.
Data used in calculations and
supplemental data for QA could still be
submitted in English weights and
measures (e.g., mmBtu/hr) but the
specific units of measure would be
included in the data submission. All
emissions data would be submitted to
the agency in kg or metric tons per unit
of time (per year in most cases, but for
a few source categories emissions per
hour, day, month, quarter, or other unit
of time could also be required).
5. Conversion of Emissions to CO2e
Under this proposed rule, reporters
would submit the quantity of each
applicable GHG emitted (or other
metric) in two forms. The data would be
in the form of quantity of the gas
emitted (e.g., metric tons of N2O) per
PO 00000
Frm 00148
Fmt 4701
Sfmt 4702
7. Submission Method
EPA proposes to require all sources
affected by this rule to report in an
electronic format to be specified by the
Administrator. Advantages of electronic
reporting include reduced burden on
reporters and EPA staff, greater accuracy
because data do not need to be manually
entered by EPA staff, enhanced ability
to conduct electronic audits to ensure
data quality, improved comparability
because data would be reported in a
consistent format, and improved data
availability for EPA and the public.
By not specifying the exact reporting
format in the regulatory text, EPA
maintains flexibility to modify the
reporting format and tools in a timely
manner. Changes based on stakeholder
comment, implementation experience,
and new technology could be executed
without regulatory action. EPA has used
this approach successfully with existing
programs, such as the ARP and the Title
VI Stratospheric Ozone Protection
Program, facilitating the deployment of
new reporting formats and tools that
take advantage of technologies (e.g.,
XML) and reduce the burden on
reporters and the Agency. The
electronic reports submitted under this
rule would also be subject to the
provisions of 40 CFR 3.10, specifying
EPA systems to which electronic
submissions must be made and the
requirements for valid electronic
signatures.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
C. Data Management
1. QA Procedures
The new reporting system would
include automated checks for data
completeness, data quality, and data
consistency. Such automated checks are
used for many other Agency programs
(e.g., ARP).
2. Providing Feedback to Reporters
EPA has established a variety of
mechanisms under existing programs to
provide feedback to reporters who have
submitted data to the Agency. EPA will
consider the approaches used by other
programs (e.g., electronic confirmations,
results of QA checks) and develop
appropriate mechanisms to provide
feedback to reporters for the GHG
reporting rule. The process is largely
dependent upon such factors as the type
of data being submitted and the manner
of data transmission. Regardless of data
collection system specifics, the goal is to
ensure appropriate transparency and
timeliness when providing feedback to
submitting entities.
D. Data Dissemination
1. Public Access to Emissions Data
The Agency proposes to publish data
submitted or collected under this
rulemaking through EPA’s Web site,
reports, and other formats, with the
exception of any CBI data, as discussed
in Section I.C of this preamble. This
level of transparency would inform the
public and facilitate greater data
verification and review. Transparency
helps to ensure data quality and build
public confidence in the data so the data
can be used to support the development
of potential future climate policies or
programs.
EPA proposes to disseminate the data
on an annual basis. Under this proposed
rule, affected sources would be required
to report at least on an annual basis,
with some reporting more frequently to
existing data reporting programs (e.g.,
the ARP). The Agency believes it would
be appropriate to post or publish data
collected under this rule once a year
after the reporting deadline. The Agency
recognizes the high level of public
interest in this data, and proposes to
disclose it in a timely manner, while
also assuring accuracy.
2. Sharing Emission Data With Other
Agencies
There are a growing number of
programs at the State, Tribe, Territory,
and Local level that require emission
sources in their respective jurisdictions
to monitor and report GHG emissions.
These programs would likely still
continue because they may be broader
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
in scope or more aggressive in
implementation than this proposal. In
order to be consistent with and
supportive of these programs and to
reduce burden on reporters and program
agencies, EPA proposes that it share
emission data with the exception of any
CBI data, as discussed in Section III.C of
this preamble, with relevant agencies or
approved entities using, where
practical, shared tools and
infrastructure.
VII. Compliance and Enforcement
A. Compliance Assistance
To facilitate implementation and
compliance, EPA plans to conduct an
active outreach and technical assistance
program following publication of the
final rule. The primary audience would
be potentially affected industries. We
intend to develop implementation and
outreach materials to help facilities
understand if the rule applies to them
and explain the reporting requirements
and timetables. The program
particularly would target industrial,
commercial, and institutional sectors
that do not routinely deal with air
pollution regulations.
Compliance materials could be
tailored to the needs of various sectors.
These materials might include, for
example, compliance guides, brochures,
fact sheets, frequently asked question
and answer documents, sample
reporting forms, and GHG emissions
calculating tools. We also are
considering a compliance assistance
hotline for answering questions and
providing technical assistance. (We may
also want to consider creating a
compliance assistance center (https://
www.assistancecenters.net).) EPA
requests comment on the types of
assistance needed and the most effective
mechanisms for delivering this
assistance to various industry sectors.
B. Role of the States
State and local air pollution control
agencies routinely interact with many of
the sources that would report under this
rule. Further, as mentioned in Section II
of this preamble, many States have
already implemented or are in the
process of implementing mandatory
GHG reporting and reduction programs.
In fact, many States may have reporting
programs that are broader in scope or
more aggressive in implementation
because those programs are either
components of established reduction
programs (e.g., cap and trade) or being
used to design and inform specific
complementary measures (e.g., energy
efficiency).
PO 00000
Frm 00149
Fmt 4701
Sfmt 4702
16595
Therefore, State and local agencies
will serve an important role in
communicating the requirements of the
rule and providing compliance
assistance. In concert with their routine
inspection and other compliance and
enforcement activities for other CAA
programs, State and local agencies also
can assist with educating facilities and
assuring compliance at facilities subject
to this rule.
As discussed in Section VI of this
preamble, CAA section 114(b) allows
EPA to delegate to States the authority
to implement and enforce Federal rules.
At this time, however, EPA does not
propose to formally delegate
implementation of the rule to State and
local agencies. Even without delegation,
EPA will work with States to ease
burden on reporters to State and Federal
systems by harmonizing data
management, where possible. Further,
as discussed in Section VI of this
preamble, EPA is proposing to make the
data collected under this rule available
to States and other interested parties as
soon as possible. For example, the
quarterly data reported to EPA under
Title IV of the CAA is often available on
EPA’s Web site within a month after it
is reported. Furthermore, we recognize
that many States with mandatory
reporting programs are members of TCR.
In some cases, TCR would provide
States support in reporting tools,
database management and serve as the
ultimate repository for data reported
under State programs, after the States
have verified the data. Given the
leadership many of the States have
shown in developing and implementing
GHG reporting and reduction programs,
EPA is seeking comment on the
possibility of delegating the authority to
collect data under this rule to State
agencies. Overall, we request comments
on the role of States in implementing
this rule and on how States and EPA
could interact in administering the
reporting program.
C. Enforcement
Facilities that fail to report GHG
emissions according to the requirements
of the proposed rule could potentially
be subject to enforcement action by EPA
under CAA sections 113 and 203–205.
The CAA provides for several levels of
enforcement that include
administrative, civil, and criminal
penalties. The CAA allows for
injunctive relief to compel compliance
and civil and administrative penalties of
up to $32,500 per day.136
136 The Federal Civil Penalties Inflation
Adjustment Act of 1990, Public Law 101–410, 104
E:\FR\FM\10APP2.SGM
Continued
10APP2
16596
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Deviations from the rule that could
ultimately be considered violations
include but are not limited to the
following:
• Failure to report GHG emissions.
• Failure to collect data needed to
estimate GHG emissions.
• Failure to continuously monitor
and test as required. Note that merely
filling in missing data as specified does
not excuse a failure to perform the
monitoring or testing.
• Failure to keep records needed to
verify GHG emissions estimates.
• Failure to estimate GHG emissions
according to the methodology(s)
specified in the rule.
• Falsification of reports.
VIII. Economic Impacts of the Proposed
Rule
This section of the preamble examines
the costs and economic impacts of the
proposed rule, including the estimated
costs and benefits of the proposed rule,
and the estimated economic impacts of
the proposed rule on affected entities,
including estimated impacts on small
entities. Complete detail of the
economic impacts of the proposed rule
can be found in the text of the
regulatory impact analysis (RIA) (EPA–
HQ–OAR–2008–0318–002).
A. How are compliance costs estimated?
EPA estimated costs of complying
with the proposed rule for process
emissions of GHGs in each affected
industrial facility, as well as emissions
from stationary combustion sources at
industrial facilities and other facilities,
and emissions of GHGs from mobile
sources. 2006 is the representative year
of the analysis in that the annual costs
were estimated using the 2006
population of emitting sources. EPA
used available industry and EPA data to
characterize conditions at affected
sources. Incremental monitoring,
recordkeeping, and reporting activities
were then identified for each type of
facility and the associated costs were
estimated.
The costs of complying with the
proposed rule would vary from one
facility to another, depending on the
types of emissions, the number of
affected sources at the facility, existing
monitoring, recordkeeping, and
reporting activities at the facility, etc.
Stat. 890, 28 U.S.C. 2461, note, as amended by
Section 31001(s)(1) of the Debt Collection
Improvement Act of 1996, Public Law 104–134, 110
Stat. 1321–373, April 26, 1996, requires EPA and
other agencies to adjust the ordinary maximum
penalty that it will apply when assessing a civil
penalty for a violation. Accordingly, EPA has
adjusted the CAA’s provision in Section 113(b) and
(d) specifying $25,000 per day of violation for civil
violations to $32,500 per day of violation.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
The costs include labor costs for
performing the monitoring,
recordkeeping, and reporting activities
necessary to comply with the proposed
rule. For some affected facilities, costs
include costs to monitor, record, and
report emissions of GHGs from
production processes and from
stationary combustion units. For other
facilities, the only emissions of GHGs
are from stationary combustion. EPA’s
estimated costs of compliance are
discussed in greater detail below:
Labor Costs. The costs of complying
with and administering this proposed
rule include time of managers,
technical, and administrative staff in
both the private sector and the public
sector. Staff hours are estimated for
activities, including:
• Monitoring (private): Staff hours to
operate and maintain emissions
monitoring systems.
• Reporting (private): Staff hours to
gather and process available data and
reporting it to EPA through electronic
systems.
• Assuring and releasing data
(public): Staff hours to quality assure,
analyze, and release reports.
Staff activities and associated labor
costs would potentially vary over time.
Thus, cost estimates are developed for
start-up and first-time reporting, and
subsequent reporting. Wage rates to
monetize staff time are obtained from
the BLS.
Equipment Costs. Equipment costs
include both the initial purchase price
of monitoring equipment and any
facility/process modification that may
be required. For example, the cost
estimation method for mobile sources
involves upstream measurement by the
vehicle manufacturers. This may require
an upgrade to their test equipment and
facility. Based on expert judgment, the
engineering costs analyses annualized
capital equipment costs with the
appropriate lifetime and interest rate
assumptions. Cost recovery periods and
interest rates vary by industry, but
typically, one-time capital costs are
amortized over a 10-year cost recovery
period at a rate of 7 percent.
B. What are the costs of this proposed
rule?
For the cost analysis, EPA gathered
existing data from EPA, industry trade
associations, States, and publicly
available data sources (e.g., labor rates
from the BLS) to characterize the
processes, sources, sectors, facilities,
and companies/entities affected. Costs
were estimated on a per entity basis and
then weighted by the number of entities
affected at the 25,000 metric tons CO2e
threshold.
PO 00000
Frm 00150
Fmt 4701
Sfmt 4702
To develop the costs for the rule, EPA
estimated the number of affected
facilities in each source category, the
number and types of combustion units
at each facility, the number and types of
production processes that emit GHGs,
process inputs and outputs (especially
for monitoring procedures that involve
a carbon mass balance), and the
measurements that are already being
made for reasons not associated with the
proposed rule (to allow only the
incremental costs to be estimated).
Many of the affected sources categories,
especially those that are the largest
emitters of GHGs (e.g., electric utilities,
industrial boilers, petroleum refineries,
cement plants, iron and steel
production, pulp and paper) are subject
to national emission standards and we
use data generated in the development
of these standards to estimate the
number of sources affected by the
reporting rule.
Other components of the cost analysis
included estimates of labor hours to
perform specific activities, cost of labor,
and cost of monitoring equipment.
Estimates of labor hours were based on
previous analyses of the costs of
monitoring, reporting, and
recordkeeping for other rules;
information from the industry
characterization on the number of units
or process inputs and outputs to be
monitored; and engineering judgment
by industry and EPA industry experts
and engineers. Labor costs were taken
from the BLS and adjusted to account
for overhead. Monitoring costs were
generally based on cost algorithms or
approaches that had been previously
developed, reviewed, accepted as
adequate, and used specifically to
estimate the costs associated with
various types of measurements and
monitoring.
A detailed engineering analysis was
conducted for each subpart of the
proposed rule to develop unique unit
costs. This analysis is documented in
the RIA. The TSDs for each source
category provide a discussion of the
applicable measurement technologies
and any existing programs and
practices. Section 4 of the RIA contains
a description of the engineering cost
analysis.
Table VIII–1 of this preamble presents
by subpart: The number of entities, the
downstream emissions covered, the first
year capital costs and the first year
annualized costs of the proposed rule.
EPA estimates that the total national
annualized cost for the first year is $168
million, and the total national
annualized cost for subsequent years is
$134 million (2006$). Of these costs,
roughly 5 percent fall upon the public
E:\FR\FM\10APP2.SGM
10APP2
16597
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
sector for program administration, while
95 percent fall upon the private sector.
General stationary combustion sources,
which are widely distributed
throughout the economy, are estimated
to incur approximately 18 percent of
ongoing costs; other sectors incurring
relatively large shares of costs are oil
and natural gas systems (21 percent of
ongoing costs), and iron and steel
manufacturing (11 percent).
The threshold, in large part,
determines the number of entities
required to report GHG emissions and
hence the costs of the rule. The number
of entities excluded increases with
higher thresholds. Table VIII–2 of this
preamble provides the cost-effectiveness
analysis for the various thresholds.
Three metrics are used to evaluate the
cost-effectiveness of the emissions
threshold. The first is the average cost
per metric ton of emissions reported ($/
metric ton CO2e). The second metric for
evaluating the threshold option is the
incremental cost of reporting emissions.
The incremental cost is calculated as the
additional (incremental) cost per metric
ton starting with the least stringent
option and moving successively from
one threshold option to the next. The
third metric shown is the marginal cost
of reported emissions. For this analysis,
the marginal cost of reporting indicates
the cost per metric ton of each threshold
option relative to the 25,000 metric ton
CO2e proposed threshold). For more
information about the first year capital
costs (unamortized), project lifetime and
the amortized (annualized) costs for
each subpart, please refer to section 4 of
the RIA and the RIA cost appendix. Not
all subparts require capital expenditures
but those that do are clearly
documented in the RIA.
TABLE VIII–1. ESTIMATED COVERED ENTITIES, EMISSIONS AND COSTS BY SUBPART (2006$)
Downstream emissions
Number of
covered
entities
Subpart
Subpart A—General Provisions
Subpart B—Reserved
Subpart C—General Stationary Fuel
Combustion Sources ............................
Subpart D—Electricity Generation ...........
Subpart E—Adipic Acid Production .........
Subpart F—Aluminum Production ...........
Subpart G—Ammonia Manufacturing ......
Subpart H—Cement Production ..............
Subpart I—Electronics Manufacturing .....
Subpart J—Ethanol Production ...............
Subpart K—Ferroalloy Production ...........
Subpart L—Fluorinated Gas Production ..
Subpart M—Food Processing ..................
Subpart N—Glass Production ..................
Subpart O—HCFC–22 Production ...........
Subpart P—Hydrogen Production ...........
Subpart Q—Iron and Steel Production ....
Subpart R—Lead Production ...................
Subpart S—Lime Manufacturing ..............
Subpart T—Magnesium Production .........
Subpart U—Miscellaneous Uses of Carbonates .................................................
Subpart V—Nitric Acid Production ...........
Subpart W—Oil and Natural Gas Systems ......................................................
Subpart X—Petrochemical Production ....
Subpart Y—Petroleum Refineries ............
Subpart Z—Phosphoric Acid Production
Subpart AA—Pulp and Paper Manufacturing .....................................................
Subpart BB—Silicon Carbide Production
Subpart CC—Soda Ash Manufacturing ...
Subpart DD—Sulfur Hexafluoride (SF6)
from Electric Power Systems ...............
Subpart EE—Titanium Dioxide Production ........................................................
Subpart FF—Underground Coal Mines ...
Subpart GG—Zinc Production .................
Subpart HH—Landfills .............................
Subpart II—Wastewater ...........................
Subpart JJ—Manure Management ..........
Subpart KK—Suppliers of Coal and
Coal-based Products & Subpart LL—
Suppliers of Coal-based Liquid Fuels ..
Subpart MM—Suppliers of Petroleum
Products ...............................................
Subpart NN—Suppliers of Natural Gas
and Natural Gas Liquids ......................
Subpart OO—Suppliers of Industrial
Greenhouse Gases ..............................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
First year capital costs
(Million of
MtCO2e)
(Million)
Share
(%)
First year total annualized
costs 2
Share
(%)
(Million)
Share
(%)
3,000
1,108
4
14
24
107
96
85
9
12
113
55
3
41
121
13
89
11
220.0
2,262.0
9.3
6.4
14.5
86.8
5.7
0.0
2.3
5.3
0.0
2.2
13.8
15.0
85.0
0.8
25.4
2.9
6
58
0
0
0
2
0
0
0
0
0
0
0
0
2
0
1
0
$12.7
0.0
0.0
0.0
0.0
5.4
0.0
0.3
0.0
0.0
0.0
0.0
0.0
0.0
0.0
0.0
4.9
0.0
15
0
0
0
0
6
0
0
0
0
0
0
0
0
0
0
6
0
$29.0
3.3
0.1
0.4
0.4
6.9
3.6
0.5
0.3
0.0
0.6
0.6
0.0
0.6
18.2
0.3
5.3
0.1
17
2
0
0
0
4
2
0
0
0
0
0
0
0
11
0
3
0
0
45
0.0
17.7
0
0
0.0
0.2
0
0
0.0
0.9
0
1
1,375
88
150
14
129.9
54.8
204.7
3.8
3
1
5
0
37.8
0.0
1.6
0.8
43
0
2
1
32.5
1.6
3.7
0.8
19
1
2
0
425
1
5
57.7
0.1
3.1
1
0
0
14.8
0.0
0.0
17
0
0
9.2
0.0
0.0
5
0
0
141
10.3
0
0.0
0
0.4
0
8
100
5
2,551
0
43
3.7
33.5
0.8
91.1
0.0
1.5
0
1
0
2
0
0
0.0
0.6
0.0
7.9
0.0
0.0
0
1
0
9
0
0
0.1
2.3
0.1
15.3
0.0
0.2
0
1
0
9
0
0
1,237
(1)
0
0.0
0
11.0
7
214
(1)
0
0.0
0
2.0
1
1,554
(1)
0
0.0
0
2.1
1
121
464.1
12
0.0
0
0.4
0
PO 00000
Frm 00151
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16598
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE VIII–1. ESTIMATED COVERED ENTITIES, EMISSIONS AND COSTS BY SUBPART (2006$)—Continued
Downstream emissions
Number of
covered
entities
Subpart
First year capital costs
(Million of
MtCO2e)
(Million)
Share
(%)
First year total annualized
costs 2
Share
(%)
(Million)
Share
(%)
Subpart PP—Suppliers of Carbon Dioxide (CO2) ..............................................
Subpart QQ—Motor Vehicle and Engine
Manufacturers .......................................
Private Sector, Total ................................
Public Sector, Total ..................................
13
(1)
0
0.0
0
0.0
0
350
13,205
NA
35.4
3,869.9
NA
1
100
NA
0.0
87.1
NA
0
100
NA
7.4
160.4
8.0
4
95
5
Total ..................................................
13,205
3,869.9
100
87.1
100
168.4
100
1 Emissions
from upstream facilities are excluded from these estimates to avoid double counting.
costs include labor and capital costs incurred in the first year. Capital Costs are annualized using appropriate equipment lifetime and interest rate (see additional details in RIA section 4).
2 Total
TABLE VIII–2. THRESHOLD COST-EFFECTIVENESS ANALYSIS (2006$)
Entities
(covered)
Threshold (metric tons CO2e)
100,000 ....................................................
25,000 ......................................................
10,000 ......................................................
1,000 ........................................................
Total costs
(million $)
Million
metric tons
CO2e/year
(covered)
Percentage
of total
emissions
reported
$101
160
213
426
3,699
3,870
3,916
3,951
52
55
56
56
6,598
13,205
20,765
59,587
Average
cost
($/metric
ton)
$0.03
0.04
0.05
0.11
Incremental
cost
($/metric
ton)
—
$0.35
1.16
6.09
Marginal
cost *
($/metric
ton)
¥$0.35
—
1.16
3.29
* Cost per metric ton relative to the selected option.
Table VIII–3 of this preamble presents
costs broken out by upstream and
downstream sources. Upstream sources
include the fuel suppliers and industrial
GHG suppliers. Downstream suppliers
include combustion sources, industrial
processes, and biological processes.
Most upstream facilities (e.g., coal
mines, refineries, etc.) are also direct
emitters of GHGs and are included in
the downstream side of the table. As
shown in Table VIII–3 of this preamble,
over 99 percent of industrial processes
emissions are covered at the 25,000
metric tons CO2e threshold for a cost of
approximately $36 million. However, it
should be noted that due to data
limitations the coverage estimates for
upstream and downstream source
categories are approximations.
TABLE VIII–3. UPSTREAM VERSUS DOWNSTREAM COSTS
Upstream 1
Source category
No. of
Reporters
Downstream 2 3 4
Emissions
coverage
(%) 10
First year
cost
(millions)
Coal Supply ......................
Petroleum Supply .............
Natural Gas Supply ..........
1,237
214
1,554
100.0
100.0
68.0
$11.03
1.99
2.14
Industrial Gas Supply .......
133
99.91
0.41
Source category
Coal 5 6 Combustion ..........
Petroleum 5 Combustion 10
Natural Gas 5 Combustion
Sub Total Combustion ......
Industrial Gas Consumption.
Industrial Processes .........
Fugitive Emissions (coal,
oil and gas).
Biological Processes ........
Vehicle 7 and Engine Manufacturers 9.
No. of
Reporters 2
Emissions
coverage 3 10
(%)
First year
cost 3
(millions)
N/A
N/A
N/A
4,108
265
99.0
20.0
23.0
5 N/A
28.0
N/A
N/A
N/A
46.16
3.70
1,077
1,475
99.6
86.6
36.12
34.86
2,792
350
55.5
84.0
16.59
7.41
Notes:
1 Most upstream facilities (e.g., coal mines, refineries, etc.) are also direct emitters of greenhouse gases, and are included in the downstream
side of the table.
2 Estimating the total number of downstream reporters by summing the rows will result in double-counting because some facilities are included
in more than one row due to multiple types of emissions (e.g., facilities that burn fossil fuel and have process/fugitive/biological emissions will be
included in each downstream category).
3 The coverage and costs for downstream reporters apply to the specific source category, i.e., the fixed costs are not ‘‘double-counted’’ in both
stationary combustion and industrial processes for the same facility.
4 The thresholds used to determine covered facilities are additive, i.e., all of the source categories located at a facility (e.g., stationary combustion and process emissions) are added together to determine whether a facility meets the proposed threshold (e.g., 25,000 metric tons of CO2e/
yr).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00152
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16599
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
5 Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels. National level
data on the number of reporters could be estimated. However, estimating the number of reporters by fuel was not possible because a single facility can combust multiple fuels. For these reasons there is not a reliable estimate of the total of the emissions coverage from the downstream
stationary combustion.
6 Approximately 90 percent of downstream coal combustion emissions are already reported to EPA through requirements for electricity generating units under the Acid Rain Program.
7 Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take into account
thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that would result from this rule. To estimate total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the industrial and
electricity generation sectors and divided that by total national GHG emissions from the combustion of that fuel.
8 The percent of coverage here is percentage of vehicle and engine manufacturers covered by this proposal rather than emissions coverage.
This rule proposes to collect an emissions rate for the four ‘‘transportation-related’’ GHG emissions (CO2, CH4, N2O and HFCs). The amounts of
CH4 and N2O are dependent on factors other than fuel characteristics such as combustion temperatures, air-fuel mixes, and use of pollution control equipment.
9 The emissions coverage for petroleum combustion includes combustion of fuel by transportation sources as well as other uses of petroleum
(e.g., home heating oil). It cannot be broken out by transportation versus other uses as there are difficulties associated with tracking which products from petroleum refiners are used for transportation fuel and which were not. We know that although refiners make these designations for the
products leaving their gate, the actual end use can and does change in the market. For example, designated transportation fuel can always be
used as home heating oil.
10 Emissions coverage from the combustion of fossil fuels upstream represents CO emissions only. It is not possible to estimate nitrous oxide
2
and methane emissions without knowing where and how the fuel is combusted. In the case of downstream emissions from stationary combustion
of fossil fuels, nitrous oxide and methane emissions are included in the emissions coverage estimate. They represent approximately 1 percent of
the total emissions.
11 EPA estimates that the majority of the costs for manufacturers of vehicles and engines can be attributed to the reporting requirements for
non-CO2 gases.
C. What are the economic impacts of the
proposed rule?
EPA prepared an economic impact
analysis to evaluate the impacts of the
proposed rule on affected industries and
economic sectors. In evaluating the
various reporting options considered,
EPA conducted a cost-effectiveness
analysis, comparing the cost per metric
ton of GHG emissions across reporting
options. EPA used this information to
identify the preferred options described
in today’s proposed rule.
To estimate the economic impacts of
the proposed rule, EPA first conducted
a screening assessment, comparing the
estimated total annualized compliance
costs by industry, where industry is
defined in terms of North American
Industry Classification System (NAICS)
code, with industry average revenues.
Overall national costs of the rule are
significant because there are a large
number of affected entities, but perentity costs are low. Average cost-tosales ratios for establishments in
affected NAICS codes are uniformly less
than 0.8 percent.
These low average cost-to-sales ratios
indicate that the proposed rule is
unlikely to result in significant changes
in firms’ production decisions or other
behavioral changes, and thus unlikely to
result in significant changes in prices or
quantities in affected markets. Thus,
EPA followed its Guidelines for
Preparing Economic Analyses (EPA,
2002, p. 124–125) and used the
engineering cost estimates to measure
the social cost of the proposed rule,
rather than modeling market responses
and using the resulting measures of
social cost. Table VIII–4 of this
preamble summarizes cost-to-sales
ratios for affected industries.
TABLE VIII–4. ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES
Average
cost per
entity
($1,000/
entity)
NAICS
NAICS description
211 ...............................................
212 ...............................................
221 ...............................................
322 ...............................................
324 ...............................................
325 ...............................................
327 ...............................................
331 ...............................................
334 ...............................................
335 ...............................................
486 ...............................................
562 ...............................................
325199 .........................................
325311 .........................................
327310 .........................................
331112 .........................................
3272 .............................................
325120 .........................................
331112 .........................................
3314 .............................................
327410 .........................................
325311 .........................................
324110 .........................................
325312 .........................................
322110 .........................................
324110 .........................................
Oil & gas extraction ...............................................................................................
Mining (except oil & gas) .......................................................................................
Utilities ...................................................................................................................
Paper mfg ..............................................................................................................
Petroleum & coal products mfg .............................................................................
Chemical mfg .........................................................................................................
Nonmetallic mineral product mfg ...........................................................................
Primary metal mfg .................................................................................................
Computer & electronic product mfg .......................................................................
Electrical equipment, appliance, & component mfg ..............................................
Pipeline transportation ...........................................................................................
Waste management & remediation services .........................................................
All other basic organic chemical mfg ....................................................................
Nitrogenous fertilizer mfg .......................................................................................
Cement mfg ...........................................................................................................
Electrometallurgical ferroalloy product mfg ...........................................................
Glass & glass product mfg ....................................................................................
Industrial gas mfg ..................................................................................................
Electrometallurgical ferroalloy product mfg ...........................................................
Nonferrous metal (except aluminum) production & processing ............................
Lime mfg ................................................................................................................
Nitrogenous fertilizer mfg .......................................................................................
Petroleum refineries ...............................................................................................
Phosphatic fertilizer mfg ........................................................................................
Pulp mills ...............................................................................................................
Petroleum refineries ...............................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00153
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
$23
10
1
22
16
12
51
112
37
37
12
6
24
19
65
28
11
3
150
23
60
20
19
60
22
24
Average
entity costto-sales
ratio 1
0.1%
0.1
<0.1
0.1
<0.1
<0.1
0.8
0.4
0.1
0.2
0.1
0.2
<0.1
0.1
0.2
<0.1
0.1
<0.1
0.3
0.1
0.4
0.1
<0.1
0.1
<0.1
<0.1
16600
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE VIII–4. ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES—Continued
Average
cost per
entity
($1,000/
entity)
NAICS
NAICS description
327910 .........................................
3251 .............................................
325188 .........................................
3314 .............................................
Abrasive product mfg .............................................................................................
Basic chemical mfg ................................................................................................
All other basic inorganic chemical mfg ..................................................................
Nonferrous metal (except aluminum) production & processing ............................
1 This
Average
entity costto-sales
ratio 1
11
9
9
19
0.1
<0.1
<0.1
0.1
ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not include initial start-up activities.
D. What are the impacts of the proposed
rule on small entities?
As required by the RFA and SBREFA,
EPA assessed the potential impacts of
the proposed rule on small entities
(small businesses, governments, and
non-profit organizations). (See Section
IX.C of this preamble for definitions of
small entities.)
EPA believes the proposed thresholds
maximize the rule coverage with 85 to
90 percent of U.S. GHG emissions
reported by approximately 13,205
reporters, while keeping reporting
burden to a minimum and excluding
small emitters. Furthermore, many
industry stakeholders that EPA met with
expressed support for a 25,000 metric
ton CO2e threshold because it
sufficiently captures the majority of
GHG emissions in the U.S., while
excluding smaller facilities and sources.
For small facilities that are captured by
the rule, EPA has proposed simplified
emission estimation methods where
feasible (e.g., stationary combustion
equipment under a certain rating can
use a simplified mass balance approach
as opposed to more rigorous direct
monitoring) to keep the burden of
reporting as low as possible. For further
detail on the rationale for excluding
small entities through threshold
selection please see the Thresholds TSD
(EPA–HQ–OAR–2008–0508–046).
EPA conducted a screening
assessment comparing compliance costs
for affected industry sectors to industryspecific receipts data for establishments
owned by small businesses. This ratio
constitutes a ‘‘sales’’ test that computes
the annualized compliance costs of this
proposed rule as a percentage of sales
and determines whether the ratio
exceeds some level (e.g., 1 percent or 3
percent).137 The cost-to-sales ratios were
constructed at the establishment level
(average reporting program costs per
establishment/average establishment
receipts) for several business size
ranges. This allowed EPA to account for
receipt differences between
establishments owned by large and
small businesses and differences in
small business definitions across
affected industries. The results of the
screening assessment are shown in
Table VIII–5 of this preamble.
TABLE VIII–5. ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a
Owned by enterprises with:
Industry
NAICS description
SBA Size
standard
(effective
March 11,
2008)
Average
cost per
entity
($1,000/
entity)
All enterprises
(%)
211
Oil & gas extraction
500
$23
212
500
221
Mining (except oil &
gas).
Utilities ...................
322
Paper mfg ..............
324
Petroleum & coal
products mfg.
Chemical mfg ........
NAICS
Oil and Gas Extraction.
Petroleum and Coal
Products.
SF6 from Electrical
Systems.
Pulp & Paper Manufacturing.
Petroleum and Coal
Products.
Chemical Manufacturing.
Cement & Other
Mineral Production.
Primary Metal Manufacturing.
Computer and
Electronic Product Manufacturing.
Electrical Equipment, Appliance,
and Component
Manufacturing.
Oil & Natural Gas
Transportation.
325
327
331
334
335
486
137 EPA’s RFA guidance for rule writers suggests
the ‘‘sales’’ test continues to be the preferred
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
750 to
999 Employees
(%)
1,000 to
1,499
Employees
(%)
0.1
1.5
0.1
0.1
0.0
0.0
0.0
10
0.1
0.9
0.2
0.1
0.1
0.1
0.1
1
0.0
0.1
0.0
0.0
0.0
0.0
0.0
22
0.1
1.3
0.3
0.1
0.1
0.0
0.0
16
0.0
0.4
0.1
0.1
0.0
0.1
0.0
12
0.0
0.6
0.1
0.0
0.0
0.0
0.0
51
0.8
4.9
1.0
0.5
0.4
0.6
0.4
500 to
1,000
500 to
1,000
112
0.4
9.1
1.4
0.4
0.2
0.1
0.2
37
0.1
2.9
0.5
0.1
0.1
0.1
0.1
500 to
1,000
37
0.2
2.9
0.5
0.2
0.1
0.1
0.1
(d)
Electrical equipment, appliance,
& component
mfg.
Pipeline transportation.
500 to
749 Employees
(%)
500 to
1,000
500 to
1,000
Computer & electronic product
mfg.
100 to
499 Employees
(%)
500 to
750
(c)
Primary metal mfg
20 to 99
Employees
(%)
(b)
Nonmetallic mineral
product mfg.
<20
Employees f
12
0.1
0.1
0.4
0.4
NA
NA
NA
quantitative metric for economic impact screening
analysis.
PO 00000
Frm 00154
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16601
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE VIII–5. ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a—Continued
Owned by enterprises with:
Industry
NAICS
Waste Management and Remediation Services.
Adipic Acid .............
325199
Ammonia ...............
325311
Cement ..................
Ferroalloys .............
327310
331112
Glass .....................
3272
Hydrogen Production.
Iron and Steel ........
325120
Lead Production ....
3314
Lime Manufacturing
Nitric Acid ..............
327410
325311
Petrochemical ........
324110
Phosphoric Acid ....
325312
Pulp and Paper .....
Refineries ..............
322110
324110
Silicon Carbide ......
327910
Soda Ash Manufacturing.
Titanium Dioxide ....
3251
325188
Zinc Production .....
3314
562
331112
NAICS description
SBA Size
standard
(effective
March 11,
2008)
Average
cost per
entity
($1,000/
entity)
All enterprises
(%)
(e)
6
1,000
Waste management & remediation services.
All other basic organic chemical
mfg.
Nitrogenous fertilizer mfg.
Cement mfg ...........
Electrometallurgical
ferroalloy product
mfg.
Glass & glass product mfg.
Industrial gas mfg ..
Electrometallurgical
ferroalloy product
mfg.
Nonferrous metal
(except aluminum) production & processing.
Lime mfg ...............
Nitrogenous fertilizer mfg.
Petroleum refineries.
Phosphatic fertilizer
mfg.
Pulp mills ...............
Petroleum refineries.
Abrasive product
mfg.
Basic chemical mfg
All other basic inorganic chemical
mfg.
Nonferrous metal
(except aluminum) production & processing.
<20
Employees f
20 to 99
Employees
(%)
100 to
499 Employees
(%)
500 to
749 Employees
(%)
750 to
999 Employees
(%)
1,000 to
1,499
Employees
(%)
0.2
0.9
0.1
0.1
0.1
0.0
0.1
24
0.0
0.9
0.3
0.1
NA
0.0
NA
1,000
19
0.1
1.0
0.6
NA
NA
NA
NA
750
750
65
28
0.2
0.0
2.1
NA
1.6
NA
0.3
NA
NA
NA
NA
NA
0.1
NA
500 to
1,000
1,000
11
0.1
1.7
0.2
0.1
0.0
0.1
0.0
3
0.0
0.6
0.0
0.1
NA
NA
NA
750
150
0.3
NA
NA
NA
NA
NA
NA
750 to
1,000
23
0.1
1.5
0.2
0.1
NA
NA
0.1
500
1,000
60
20
0.4
0.1
16.5
1.0
1.2
0.6
NA
NA
NA
NA
NA
NA
NA
NA
(c)
19
0.0
0.3
0.0
0.0
0.0
NA
NA
500
60
0.1
10.1
NA
NA
NA
NA
NA
750
(c)
22
24
0.0
0.0
1.5
0.4
NA
0.0
NA
0.0
NA
0.0
NA
NA
NA
NA
500
11
0.1
0.8
0.2
0.1
NA
NA
NA
500 to
1,000
1,000
9
0.0
0.3
0.1
0.0
0.0
0.0
0.0
9
0.0
0.7
0.4
0.1
NA
NA
NA
750 to
1,000
19
0.1
1.2
0.1
0.1
NA
NA
0.1
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise—the enterprise employment and annual payroll are summed from the associated establishments. Enterprise size designations are determined by the summed employment of
all associated establishments. Since the SBA’s business size definitions (https://www.sba.gov/size) apply to an establishment’s ultimate parent company, we assume in
this analysis that the enterprise definition above is consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses.
b NAICS codes 221111, 221112, 221113, 221119, 221121, 221122—A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission,
and/or distribution of electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million MW hours.
c 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as
facilities under a processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract
must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks.
d NAICS codes 486110 = 1,500 employees; NAICS 486210 = $6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 = $11.5 million
annual receipts.
e Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910—
Environmental Remediation Services:
(1) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern
must be engaged primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to,
preliminary assessment, site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated
materials, storage of contaminated materials and security and site closeouts. If one of such activities accounts for 50 percent or more of a concern’s total revenues,
employees, or other related factors, the concern’s primary industry is that of the particular industry and not the Environmental Remediation Services Industry.
(2) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a
contaminated environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering), smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as: Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse
Systems; Sanitary Services, Not Elsewhere Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If
any activity in the procurement can be identified with a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50 percent or more of the value of the entire procurement, then the proper size standard is the one for that particular industry, and not the Environmental
Remediation Service size standard.
f Given the Agency’s selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
NA: Not available. SUSB did not report the data necessary to calculate this ratio.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00155
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16602
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
EPA was not able to calculate a costto-sales ratio for manure management
(NAICS 112) as SUSB (SBA, 2008a) data
does not provide establishment
information for agricultural NAICS
codes (e.g., NAICS 112 which covers
manure management). EPA estimates
that the total first year reporting costs
for the entire manure management
industry to be $0.2 million with an
average cost per ton reported of $0.14.
As shown, the cost-to-sales ratios are
less than 1 percent for establishments
owned by small businesses that EPA
considers most likely to be covered by
the reporting program (e.g.
establishments owned by businesses
with 20 or more employees).
EPA acknowledges that several
enterprise categories have ratios that
exceed this threshold (e.g., enterprise
with one to 20 employees). EPA took a
conservative approach with the model
entity analysis. Although the
appropriate SBA size definition should
be applied at the parent company
(enterprise) level, data limitations
allowed us only to compute and
compare ratios for a model
establishment within several enterprise
size ranges. To assess the likelihood that
these small businesses would be
covered by the rule, we performed
several case studies for manufacturing
industries where the cost-to-receipt ratio
exceeded 1 percent. For each industry,
we used and applied emission data from
a recent study examining emission
thresholds.138 This study provides
industry-average CO2 emission rates
(e.g., tons per employee) for these
manufacturing industries.
The case studies showed two
industries (cement and lime
manufacturing) where emission rates
suggest small businesses of this
employment size could potentially be
covered by the rule. As a result, EPA
examined corporate structures and
ultimate parent companies were
identified using industry surveys and
the latest private databases such as Dun
& Bradstreet. The results of this analysis
show cost to sales ratios below 1
percent.
For the other enterprise categories
identified with ratios between 1 percent
and 3 percent EPA examined industry
specific bottom up databases and
previous industry specific studies to
ensure that no entities with less than 20
employees are captured under the rule.
Although this rule would not have a
significant economic impact on a
substantial number of small entities, the
Agency nonetheless tried to reduce the
impact of this rule on small entities,
including seeking input from a wide
range of private- and public-sector
stakeholders. When developing the
proposed rule, the Agency took special
steps to ensure that the burdens
imposed on small entities were
minimal. The Agency conducted several
meetings with industry trade
associations to discuss regulatory
options and the corresponding burden
on industry, such as recordkeeping and
reporting. The Agency investigated
alternative thresholds and analyzed the
marginal costs associated with requiring
smaller entities with lower emissions to
report. The Agency also recommended a
hybrid method for reporting, which
provides flexibility to entities and helps
minimize reporting costs.
Additional analysis for a model small
government also showed that the
annualized reporting program costs
were less than 1 percent of revenue.
These impacts are likely representative
of ratios in industries where data
limitations do not allow EPA to
compute sales tests (e.g., general
stationary combustion and manure
management). Potential impacts of the
proposed rule on small governments
were assessed separately from impacts
on Federal Agencies. Small
governments and small non-profit
organizations may be affected if they
own affected stationary combustion
sources, landfills, or natural gas
suppliers. However, the estimated costs
under the proposed rule are estimated to
be small enough that no small
government or small non-profit is
estimated to incur significant impacts.
For example, from the 2002 Census (in
$2006), revenues for small governments
(counties and municipalities) with
populations fewer than 10,000 are $3
million, and revenues for local
governments with populations less than
50,000 is $7 million. As an upper bound
estimate, summing typical perrespondent costs of combustion plus
landfills plus natural gas suppliers
yields a cost of approximately $17,047
per local government. Thus, for the
smallest group of local governments
(<10,000 people), cost-to-revenue ratio
would be 0.8 percent. For the larger
group of governments less than 50,000,
the cost-to-revenue ratio is 0.3 percent.
on their relevance to policy making,
transparency issues, and market
efficiency, and therefore benefits would
be very difficult to quantify and
monetize. Instead of a quantitative
analysis of the benefits, EPA conducted
a systematic literature review of existing
studies including government,
consulting, and scholarly reports.
A mandatory reporting system would
benefit the public by increased
transparency of facility emissions data.
Transparent, public data on emissions
allows for accountability of polluters to
the public stakeholders who bear the
cost of the pollution. Citizens,
community groups, and labor unions
have made use of data from Pollutant
Release and Transfer Registers to
negotiate directly with polluters to
lower emissions, circumventing greater
government regulation. Publicly
available emissions data also would
allow individuals to alter their
consumption habits based on the GHG
emissions of producers.
The greatest benefit of mandatory
reporting of industry GHG emissions to
government would be realized in
developing future GHG policies. For
example, in the EU’s Emissions Trading
System, a lack of accurate monitoring at
the facility level before establishing CO2
allowance permits resulted in allocation
of permits for emissions levels an
average of 15 percent above actual levels
in every country except the United
Kingdom.
Benefits to industry of GHG emissions
monitoring include the value of having
independent, verifiable data to present
to the public to demonstrate appropriate
environmental stewardship. Such
monitoring allows for inclusion of
standardized GHG data into
environmental management systems,
providing the necessary information to
achieve and disseminate their
environmental achievements.
Standardization would also be a
benefit to industry, once facilities invest
in the institutional knowledge and
systems to report emissions, the cost of
monitoring should fall and the accuracy
of the accounting should improve. A
standardized reporting program would
also allow for facilities to benchmark
themselves against similar facilities to
understand better their relative standing
within their industry.
138 Nicholas Institute for Environmental Policy
Solutions, Duke University. 2008. Size Thresholds
for Greenhouse Gas Regulation: Who Would be
Affected by a 10,000-ton CO2 Emissions Rule?
Available at: https://www.nicholas.duke.edu/
institute/10Kton.pdf.
E. What are the benefits of the proposed
rule for society?
EPA examined the potential benefits
of the GHG reporting rule. Because the
benefits of a reporting system are based
A. Executive Order 12866: Regulatory
Planning and Review
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00156
Fmt 4701
Sfmt 4702
IX. Statutory and Executive Order
Reviews
Under section 3(f)(1) of EO 12866 (58
FR 51735, October 4, 1993), this action
is an ‘‘economically significant
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
regulatory action’’ because it is likely to
have an annual effect on the economy
of $100 million or more. Accordingly,
EPA submitted this action to the OMB
for review under EO 12866 and any
changes made in response to OMB
recommendations have been
documented in the docket for this
action.
In addition, EPA prepared an analysis
of the potential costs and benefits
associated with this action. A copy of
the analysis is available in Docket No.
EPA–HQ–OAR–2008–0508–002 and is
briefly summarized in Section VIII of
this preamble.
B. Paperwork Reduction Act
The information collection
requirements in this proposed rule have
been submitted for approval to the OMB
under the Paperwork Reduction Act, 44
U.S.C. 3501 et seq. The ICR document
prepared by EPA has been assigned EPA
ICR number 2300.01.
EPA plans to collect complete and
accurate economy-wide data on facilitylevel greenhouse gas emissions.
Accurate and timely information on
greenhouse gas emissions is essential for
informing future climate change policy
decisions. Through data collected under
this rule, EPA will gain a better
understanding of the relative emissions
of specific industries, and the
distribution of emissions from
individual facilities within those
industries. The facility-specific data will
also improve our understanding of the
factors that influence greenhouse gas
emission rates and actions that facilities
are already taking to reduce emissions.
Additionally, EPA will be able to track
the trend of emissions from industries
and facilities within industries over
time, particularly in response to policies
and potential regulations. The data
collected by this rule will improve
EPA’s ability to formulate climate
change policy options and to assess
which industries would be affected, and
how these industries would be affected
by the options.
This information collection is
mandatory and will be carried out under
CAA sections 114 and 208. Information
identified and marked as CBI will not be
disclosed except in accordance with
procedures set forth in 40 CFR part 2.
However, emissions information
collected under CAA sections 114 and
208 cannot be claimed as CBI and will
be made public.
The projected cost and hour burden
for non-federal respondents is $143
million and 1.63 million hours per year.
The estimated average burden per
response is 2 hours; the proposed
frequency of response is annual for all
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
respondents that must comply with the
proposed rule’s reporting requirements,
except for electricity generating units
that are already required to report
quarterly under 40 CFR part 75 (EPA
Acid Rain Program); and the estimated
average number of likely respondents
per year is 18,775. The cost burden to
respondents resulting from the
collection of information includes the
total capital cost annualized over the
equipment’s expected useful life
(averaging $20.7 million), a total
operation and maintenance component
(averaging $22.4 million per year), and
a labor cost component (averaging
$100.0 million per year). Burden is
defined at 5 CFR 1320.3(b). These cost
numbers differ from those shown
elsewhere in the RIA for several reasons:
• ICR costs represent the average cost
over the first three years of the rule, but
costs are reported elsewhere in the RIA
for the first year of the rule and for
subsequent years of the rule;
• The costs of reporting electricity
purchases have been excluded from the
ICR, but are still reported in the RIA,
although electricity use reporting has
been removed from the proposed rule
and EPA is soliciting comment on it (see
Section 4.2.2, pg 4–18); and
• The first-year costs of coverage
determination, estimated to be $867.60
per facility for approximately 16,800
facilities that ultimately determine they
do not have to report, are included in
the ICR but not in the RIA (see Section
4.2.2, pg 4–18). These costs, averaged
over 3 years, are $4.87 million incurred
by an average of 5,613 respondents per
year.
An agency may not conduct or
sponsor, and a person is not required to
respond to, a collection of information
unless it displays a currently valid OMB
control number. The OMB control
numbers for EPA’s regulations in 40
CFR are listed in 40 CFR part 9. To
comment on the Agency’s need for this
information, the accuracy of the
provided burden estimates, and any
suggested methods for minimizing
respondent burden, EPA has established
a public docket for this rule. Submit any
comments related to the ICR to EPA and
OMB. See ADDRESSES section at the
beginning of this notice for where to
submit comments to EPA. Send
comments to OMB at the Office of
Information and Regulatory Affairs,
Office of Management and Budget, 725
17th Street, NW., Washington, DC
20503, Attention: Desk Office for EPA.
Since OMB is required to make a
decision concerning the ICR between 30
and 60 days after April 10, 2009, a
comment to OMB is best assured of
having its full effect if OMB receives it
PO 00000
Frm 00157
Fmt 4701
Sfmt 4702
16603
by May 11, 2009. The final rule will
respond to any OMB or public
comments on the information collection
requirements contained in this proposal.
C. Regulatory Flexibility Act (RFA)
The RFA generally requires an agency
to prepare a regulatory flexibility
analysis of any rule subject to notice
and comment rulemaking requirements
under the Administrative Procedure Act
or any other statute unless the agency
certifies that the rule will not have a
significant economic impact on a
substantial number of small entities.
Small entities include small businesses,
small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts
of today’s rule on small entities, small
entity is defined as: (1) A small business
as defined by the Small Business
Administration’s regulations at 13 CFR
121.201; (2) a small governmental
jurisdiction that is a government of a
city, county, town, school district or
special district with a population of less
than 50,000; and (3) a small
organization that is any not-for-profit
enterprise which is independently
owned and operated and is not
dominant in its field.
After considering the economic
impacts of today’s proposed rule on
small entities, I certify that this action
will not have a significant economic
impact on a substantial number of small
entities. The small entities directly
regulated by this proposed rule include
small businesses across all sectors
encompassed by the rule, small
governmental jurisdictions and small
non-profits. We have determined that
some small businesses will be affected
because their production processes emit
GHGs that must be reported, or because
they have stationary combustion units
onsite that emit GHGs that must be
reported. Small governments and small
non-profits are generally affected
because they have regulated landfills or
stationary combustion units onsite, or
because they own a LDC.
For affected small entities, EPA
conducted a screening assessment
comparing compliance costs for affected
industry sectors to industry-specific
data on revenues for small businesses.
This ratio constitutes a ‘‘sales’’ test that
computes the annualized compliance
costs of this proposed rule as a
percentage of sales and determines
whether the ratio exceeds some level
(e.g., 1 percent or 3 percent). The costto-sales ratios were constructed at the
establishment level (average compliance
cost for the establishment/average
establishment revenues). As shown in
Table VIII–5 of this preamble, the cost-
E:\FR\FM\10APP2.SGM
10APP2
16604
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
to-sales ratios are less than 1 percent for
establishments owned by small
businesses that EPA considers most
likely to be covered by the reporting
program.139
The screening analysis thus indicates
that the proposed rule will not have a
significant economic impact on a
substantial number of small entities. See
Table VIII–4 of this preamble for sectorspecific results. The screening
assessment for small governments
compared the sum of average costs of
compliance for combustion, local
distribution companies, and landfills to
average revenues for small governments.
Even for a small government owning all
three source types, the costs constitute
less than 1 percent of average revenues
for the smallest category of governments
(those with fewer than 10,000 people).
Although this proposed rule will not
have a significant economic impact on
a substantial number of small entities,
EPA nonetheless took several steps to
reduce the impact of this rule on small
entities. For example, EPA determined
appropriate thresholds that reduce the
number of small businesses reporting. In
addition, EPA is not requiring facilities
to install CEMS if they do not already
have them. Facilities without CEMS can
calculate emissions using readily
available data or data that are less
expensive to collect such as process
data or material consumption data. For
some source categories, EPA developed
tiered methods that are simpler and less
burdensome. Also, EPA is requiring
annual instead of more frequent
reporting.
Through comprehensive outreach
activities, EPA held approximately 100
meetings and/or conference calls with
representatives of the primary audience
groups, including numerous trade
associations and industries that include
small business members. EPA’s
outreach activities are documented in
the memorandum, ‘‘Summary of EPA
Outreach Activities for Developing the
Greenhouse Gas Reporting Rule,’’
located in Docket No. EPA–HQ–OAR–
2008–0508–055. EPA maintains an
‘‘open door’’ policy for stakeholders to
provide input on key issues and to help
inform EPA’s understanding of issues,
including thresholds for reporting and
greenhouse gas calculation and
reporting methodologies.
EPA continues to be interested in the
potential impacts of the proposed rule
on small entities and welcomes
139 U.S. Small Business Administration (SBA).
2008. Firm Size Data from the Statistics of U.S.
Businesses: U.S. Detail Employment Sizes: 2002.
https://www.census.gov/csd/susb/
download_susb02.htm.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
comments on issues related to such
impacts.
D. Unfunded Mandates Reform Act
(UMRA)
Title II of the UMRA of 1995 (UMRA),
2 U.S.C. 1531–1538, requires Federal
agencies, unless otherwise prohibited by
law, to assess the effects of their
regulatory actions on State, local, and
Tribal governments and the private
sector.
EPA has developed this regulation
under authority of CAA sections 114
and 208. The required activities under
this Federal mandate include
monitoring, recordkeeping, and
reporting of GHG emissions from
multiple source categories (e.g.,
combustion, process, biologic and
fugitive). This rule contains a Federal
mandate that may result in expenditures
of $100 million for the private sector in
any one year. As described below, we
have determined that the expenditures
for State, local, and Tribal governments,
in the aggregate, will be approximately
$14.1 million per year, based on average
costs over the first three years of the
rule. Accordingly, EPA has prepared
under section 202 of the UMRA a
written statement which is summarized
below.
Consistent with the intergovernmental
consultation provisions of section 204 of
the UMRA, EPA initiated an outreach
effort with the governmental entities
affected by this rule including State,
local, and Tribal officials. EPA
maintained an ‘‘open door’’ policy for
stakeholders to provide input on key
issues and to help inform EPA’s
understanding of issues, including
impacts to State, local and Tribal
governments. The outreach audience
included State environmental protection
agencies, regional and Tribal air
pollution control agencies, and other
State and local government
organizations. EPA contacted several
States and State and regional
organizations already involved in
greenhouse gas emissions reporting.
EPA also conducted several conference
calls with Tribal organizations. For
example, EPA staff provided
information to tribes through conference
calls with multiple Tribal working
groups and organizations at EPA and
through individual calls with two Tribal
board members of TRI. In addition, EPA
held meeting and conference calls with
groups such as TRI, NACAA, ECOS, and
with State members of RGGI, the
Midwestern GHG Reduction Accord,
and WCI. See the ‘‘Summary of EPA
Outreach Activities for Developing the
Greenhouse Gas Reporting Rule,’’ in
Docket No. EPA–HQ–OAR–2008–0508–
PO 00000
Frm 00158
Fmt 4701
Sfmt 4702
055 for a complete list of organizations
and groups that EPA contacted.
Consistent with section 205 of the
UMRA, EPA has identified and
considered a reasonable number of
regulatory alternatives. EPA carefully
examined regulatory alternatives, and
selected the lowest cost/least
burdensome alternative that EPA deems
adequate to address Congressional
concerns and to provide a consistent,
comprehensive source of information
about emissions of GHGs. EPA has
considered the costs and benefits of the
proposed GHG reporting rule, and has
concluded that the costs will fall mainly
on the private sector (approximately
$131 million), with some costs incurred
by State, local, and Tribal governments
that must report their emissions (less
than $12.4 million) that own and
operate stationary combustion units,
landfills, or natural gas local
distribution companies (LDCs). EPA
estimates that an additional 1,979
facilities owned by state, local, or tribal
governments will incur approximately
$1.7 million in costs during the first
year of the rule to make a reporting
determination and subsequently
determine that their emissions are
below the threshold and thus, they are
not required to report their emissions.
Furthermore, we think it is unlikely that
State, local and Tribal governments
would begin operating large industrial
facilities, similar to those affected by
this rulemaking operated by the private
sector.
Initially, EPA estimates that costs of
complying with the proposed rule will
be widely dispersed throughout many
sectors of the economy. Although EPA
acknowledges that over time changes in
the patterns of economic activity may
mean that GHG generation and thus
reporting costs will change, data are
inadequate for projecting these changes.
Thus, EPA assumes that costs averaged
over the first three years of the program
are typical of ongoing costs of
compliance. EPA estimates that future
compliance costs will total
approximately $145 million per year.
EPA examined the distribution of these
costs between private owners and State,
local, and Tribal governments owning
GHG emitters. In addition, EPA
examined, within the private sector, the
impacts on various industries. In
general, estimated cost per entity
represents less than 0.1% of company
sales in affected industries. These costs
are broadly distributed to a variety of
economic sectors and represent
approximately 0.001 percent of 2007
Gross Domestic Product; overall, EPA
does not believe the proposed rule will
have a significant macroeconomic
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
impact on the national economy.
Therefore, this rule is not subject to the
requirements of section 203 of UMRA
because it contains no regulatory
requirements that might significantly or
uniquely affect small governments.
EPA does not anticipate that
substantial numbers of either public or
private sector entities will incur
significant economic impacts as a result
of this proposed rulemaking. EPA
further expects that benefits of the
proposed rule will include more and
better information for EPA and the
private sector about emissions of GHGs.
This improved information would
enhance EPA’s ability to develop sound
future climate policies, and may
encourage GHG emitters to develop
voluntary plans to reduce their
emissions.
This regulation applies directly to
facilities that supply fuel or chemicals
that when used emit greenhouse gases,
and to facilities that directly emit
greenhouses gases. It does not apply to
governmental entities unless the
government entity owns a facility that
directly emits greenhouse gases above
threshold levels such as a landfill or
large stationary combustion source. In
addition, this rule does not impose any
implementation responsibilities on
State, local or Tribal governments and it
is not expected to increase the cost of
existing regulatory programs managed
by those governments. Thus, the impact
on governments affected by the rule is
expected to be minimal.
E. Executive Order 13132: Federalism
EO 13132, entitled ‘‘Federalism’’ (64
FR 43255, August 10, 1999), requires
EPA to develop an accountable process
to ensure ‘‘meaningful and timely input
by State and local officials in the
development of regulatory policies that
have Federalism implications.’’
‘‘Policies that have Federalism
implications’’ is defined in the EO to
include regulations that have
‘‘substantial direct effects on the States,
on the relationship between the national
government and the States, or on the
distribution of power and
responsibilities among the various
levels of government.’’
This proposed rule does not have
Federalism implications. It will not
have substantial direct effects on the
States, on the relationship between the
national government and the States, or
on the distribution of power and
responsibilities among the various
levels of government, as specified in EO
13132. However, for a more detailed
discussion about how this proposal
relates to existing State programs, please
see Section II of this preamble.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
This regulation applies directly to
facilities that supply fuel or chemicals
that when used emit greenhouse gases
or facilities that directly emit
greenhouses gases. It does not apply to
governmental entities unless the
government entity owns a facility that
directly emits greenhouse gases above
threshold levels such as a landfill or
large stationary combustion source, so
relatively few government facilities
would be affected. This regulation also
does not limit the power of States or
localities to collect GHG data and/or
regulate GHG emissions. Thus, EO
13132 does not apply to this rule.
In the spirit of Executive Order 13132,
and consistent with EPA policy to
promote communications between EPA
and State and local governments, EPA
specifically solicits comments on this
proposed rule from State and local
officials.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This proposed rule is not expected to
have Tribal implications, as specified in
EO 13175 (65 FR 67249, November 9,
2000). This regulation applies directly
to facilities that supply fuel or
chemicals that when used emit
greenhouse gases or facilities that
directly emit greenhouses gases.
Facilities expected to be affected by the
proposed rule are not expected to be
owned by Tribal governments. Thus,
Executive Order 13175 does not apply
to this proposed rule.
Although EO 13175 does not apply to
this proposed rule, EPA sought
opportunities to provide information to
Tribal governments and representatives
during development of the rule. In
consultation with EPA’s American
Indian Environment Office, EPA’s
outreach plan included tribes. EPA
conducted several conference calls with
Tribal organizations. For example, EPA
staff provided information to tribes
through conference calls with multiple
Indian working groups and
organizations at EPA that interact with
tribes and through individual calls with
two Tribal board members of TCR. In
addition, EPA prepared a short article
on the GHG reporting rule that appeared
on the front page a Tribal newsletter—
Tribal Air News—that was distributed
to EPA/OAQPS’s network of Tribal
organizations. EPA gave a presentation
on various climate efforts, including the
mandatory reporting rule, at the
National Tribal Conference on
Environmental Management on June
24–26, 2008. In addition, EPA had
copies of a short information sheet
distributed at a meeting of the National
PO 00000
Frm 00159
Fmt 4701
Sfmt 4702
16605
Tribal Caucus. See the ‘‘Summary of
EPA Outreach Activities for Developing
the GHG reporting rule,’’ in Docket No.
EPA–HQ–OAR–2008–0508–055 for a
complete list of Tribal contacts.
EPA specifically solicits additional
comment on this proposed rule from
Tribal officials.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
EPA interprets EO 13045 (62 FR
19885, April 23, 1997) as applying only
to those regulatory actions that concern
health or safety risks, such that the
analysis required under section 5–501 of
the EO has the potential to influence the
regulation. This action is not subject to
EO 13045 because it does not establish
an environmental standard intended to
mitigate health or safety risks.
H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This proposed rule is not a
‘‘significant energy action’’ as defined in
EO 13211 (66 FR 28355, May 22, 2001)
because it is not likely to have a
significant adverse effect on the supply,
distribution, or use of energy. Further,
we have concluded that this rule is not
likely to have any adverse energy
effects. This proposal relates to
monitoring, reporting and
recordkeeping at facilities that supply
fuel or chemicals that when used emit
greenhouse gases or facilities that
directly emit greenhouses gases and
does not impact energy supply,
distribution or use. Therefore, we
conclude that this rule is not likely to
have any adverse effects on energy
supply, distribution, or use.
I. National Technology Transfer and
Advancement Act
Section 12(d) of the National
Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104–
113 (15 U.S.C. 272 note) directs EPA to
use voluntary consensus standards in its
regulatory activities unless to do so
would be inconsistent with applicable
law or otherwise impractical. Voluntary
consensus standards are technical
standards (e.g., materials specifications,
test methods, sampling procedures, and
business practices) that are developed or
adopted by voluntary consensus
standards bodies. NTTAA directs EPA
to provide Congress, through OMB,
explanations when the Agency decides
not to use available and applicable
voluntary consensus standards.
This proposed rulemaking involves
technical standards. EPA proposes to
use more than 40 voluntary consensus
E:\FR\FM\10APP2.SGM
10APP2
16606
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
standards from six different voluntary
consensus standards bodies: ASTM,
ASME, ISO, Gas Processors Association,
American Gas Association, and
American Petroleum Institute. These
voluntary consensus standards will help
facilities monitor, report, and keep
records of greenhouse gas emissions. No
new test methods were developed for
this proposed rule. Instead, from
existing rules for source categories and
voluntary greenhouse gas programs,
EPA identified existing means of
monitoring, reporting, and keeping
records of greenhouse gas emissions.
The existing methods (voluntary
consensus standards) include a broad
range of measurement techniques,
including many for combustion sources
such as methods to analyze fuel and
measure its heating value; methods to
measure gas or liquid flow; and methods
to gauge and measure petroleum and
petroleum products. The test methods
are incorporated by reference into the
proposed rule and are available as
specified in proposed 40 CFR 98.7.
By incorporating voluntary consensus
standards into this proposed rule, EPA
is both meeting the requirements of the
NTTAA and presenting multiple
options and flexibility for measuring
greenhouse gas emissions.
EPA welcomes comments on this
aspect of the proposed rulemaking and,
specifically, invites the public to
identify potentially-applicable
voluntary consensus standards and to
explain why such standards should be
used in this regulation.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
EO 12898 (59 FR 7629, February 16,
1994) establishes Federal executive
policy on environmental justice. Its
main provision directs Federal agencies,
to the greatest extent practicable and
permitted by law, to make
environmental justice part of their
mission by identifying and addressing,
as appropriate, disproportionately high
and adverse human health or
environmental effects of their programs,
policies, and activities on minority
populations and low-income
populations in the U.S.
EPA has determined that this
proposed rule will not have
disproportionately high and adverse
human health or environmental effects
on minority or low-income populations
because it does not affect the level of
protection provided to human health or
the environment. This proposed rule
does not affect the level of protection
provided to human health or the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
environment because it is a rule
addressing information collection and
reporting procedures.
List of Subjects
40 CFR Part 86
Environmental protection,
Administrative practice and procedure,
Air pollution control, Reporting and
recordkeeping requirements, Motor
vehicle pollution.
40 CFR Part 87
Environmental protection, Air
pollution control, Aircraft,
Incorporation by reference.
40 CFR Part 89
Environmental protection,
Administrative practice and procedure,
Confidential business information,
Imports, Labeling, Motor vehicle
pollution, Reporting and recordkeeping
requirements, Research, Vessels,
Warranty.
40 CFR Part 90
Environmental protection,
Administrative practice and procedure,
Confidential business information,
Imports, Labeling, Reporting and
recordkeeping requirements, Research,
Warranty.
40 CFR Part 94
Environmental protection,
Administrative practice and procedure,
Air pollution control, Confidential
business information, Imports,
Incorporation by reference, Labeling,
Penalties, Vessels, Reporting and
recordkeeping requirements,
Warranties.
40 CFR Part 98
Environmental protection,
Administrative practice and procedure,
Greenhouse gases, Incorporation by
reference, Suppliers, Reporting and
recordkeeping requirements.
Air pollution control, Confidential
business information, Imports,
Incorporation by reference, Labeling,
Penalties, Reporting and recordkeeping
requirements, Warranties.
40 CFR Part 1042
Environmental protection,
Administrative practice and procedure,
Air pollution control, Confidential
business information, Imports,
Incorporation by reference, Labeling,
Penalties, Vessels, Reporting and
recordkeeping requirements,
Warranties.
40 CFR Parts 1045, 1048, 1051, and
1054
Environmental protection,
Administrative practice and procedure,
Air pollution control, Confidential
business information, Imports,
Incorporation by reference, Labeling,
Penalties, Reporting and recordkeeping
requirements, Warranties.
40 CFR Part 1065
Environmental protection,
Administrative practice and procedure,
Incorporation by reference, Reporting
and recordkeeping requirements,
Research.
Dated: March 10, 2009.
Lisa P. Jackson,
Administrator.
For the reasons stated in the
preamble, title 40, chapter I, of the Code
of Federal Regulations is proposed to be
amended as follows:
PART 86—[AMENDED]
1. The authority citation for part 86
continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
Subpart A—[Amended]
2. Section 86.007–23 is amended by
adding paragraph (n) to read as follows:
40 CFR Part 600
§ 86.007–23
Administrative practice and
procedure, Electric power, Fuel
economy, Incorporation by reference,
Labeling, Reporting and recordkeeping
requirements.
*
40 CFR Part 1033
Environmental protection,
Administrative practice and procedure,
Confidential business information,
Incorporation by reference, Labeling,
Penalties, Railroads, Reporting and
recordkeeping requirements.
40 CFR Part 1039
Environmental protection,
Administrative practice and procedure,
PO 00000
Frm 00160
Fmt 4701
Sfmt 4702
Required data.
*
*
*
*
(n) Starting in the 2011 model year for
heavy-duty engines, measure CO2, N2O,
and CH4 with each low-hour
certification test using the procedures
specified in 40 CFR part 1065. Report
these values in your application for
certification. These measurements are
not required for NTE testing. Use the
same units and calculations as for your
other results to report a single weighted
value for CO2, N2O, and CH4 for each
test. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
E:\FR\FM\10APP2.SGM
10APP2
16607
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(3) Round CH4 to the nearest 0.001g/
kW-hr.
3. Section 86.078–3 is amended by
removing the paragraph (a) designation
and adding the abbreviations CH4 and
N2O in alphanumeric order to read as
follows:
§ 86.078–3
Abbreviations.
*
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
Subpart B—[Amended]
4. A new § 86.165–11 is added to read
as follows:
§ 86.165–11
Procedure.
Air Conditioning Idle Test
(a) Applicability. This section
describes procedures for determining air
conditioning-related CO2 emissions
from 2012 and later model year lightduty vehicles, light-duty trucks, and
medium-duty passenger vehicles.
(b) Overview. The test consists of a
brief period to stabilize the vehicle at
idle, followed by a ten-minute period of
idle when CO2 emissions are measured
without any climate control systems
operating; the test concludes with a tenminute period when CO2 emissions are
measured with the air conditioning
system operating. This test is designed
to determine the air conditioningrelated CO2 emission value, in grams
per minute per cubic foot of interior
volume. If engine stalling occurs during
cycle operation, follow the provisions of
§ 86.136–90 to restart the test.
Measurement instruments must meet
the specifications described in 40 CFR
part 1065, subparts C and D.
(c) Test sequence. Before testing,
precondition the vehicle as described in
§ 86.132, then allow the vehicle to idle
for not less than 1 minute and not more
than 5 minutes.
(1) Connect the vehicle exhaust
system to the raw sampling location or
dilution stage according to 40 CFR
1065.130. For dilution systems, dilute
the exhaust as described in 40 CFR
1065.140. Continuous sampling systems
must meet the specifications of 40 CFR
1065.145.
(2) Test the vehicle in a fully warmedup condition. If the vehicle has soaked
for two hours or less since the last
exhaust test element, preconditioning
may consist of a 505, 866, highway,
US06, or SC03 test cycle. For longer
soak periods, precondition the vehicle
using one full Urban Dynamometer
Driving Schedule.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(3) Immediately after the
preconditioning described in paragraph
(c)(1) of this section, turn off any
cooling fans, if present, close the
vehicle’s hood, fully close all the
vehicle’s windows, ensure that all the
vehicle’s climate control systems are set
to full off, start the CO2 sampling
system, and then idle the vehicle for not
less than 1 minute and not more than 5
minutes to achieve normal and stable
idle operation.
(4) Measure and record the
continuous CO2 concentration for 10.0
minutes. Measure the CO2 concentration
continuously using raw or dilute
sampling procedures. Multiply this
concentration by the continuous (raw or
dilute) flow rate at the emission
sampling location to determine the CO2
flow rate. Calculate the constituent’s
cumulative flow rate continuously over
the test interval. This cumulative value
is the total mass of the emitted
constituent.
(5) Within 60 seconds after
completing the measurement described
in paragraph (c)(4) of this section, turn
on the vehicle’s air conditioning system.
Set automatic systems to a temperature
9 °F (5 °C) below the ambient
temperature of the test cell. Set manual
systems to maximum cooling with
recirculation turned off. Continue idling
the vehicle while measuring and
recording the continuous CO2
concentration for 10.0 minutes as
described in paragraph (c)(4) of this
section.
(d) Calculations. (1) For the
measurement with no air conditioning,
calculate the CO2 emissions (in grams
per minute) by dividing the total mass
of CO2 from paragraph (c)(4) of this
section by 10.0.
(2) For the measurement with air
conditioning in operation, calculate the
CO2 emissions (in grams per minute) by
dividing the total mass of CO2 from
paragraph (c)(5) of this section by 10.0.
(3) Calculate the increased CO2
emissions due to air conditioning (in
grams per minute) by subtracting the
results of paragraph (d)(1) of this section
from the results of paragraph (d)(2) of
this section.
(4) Divide the value from paragraph
(d)(3) of this section by the interior
volume of the vehicle to determine the
increase in CO2 emissions in grams per
minute per cubic foot.
(e) Reporting. Include the value
calculated in paragraph (d)(4) of this
section in your application for
certification.
Subpart E—[Amended]
5. Section 86.403–78 is amended by
adding the abbreviations CH4 and N2O
PO 00000
Frm 00161
Fmt 4701
Sfmt 4702
in alphanumeric order to read as
follows:
§ 86.403–78
*
*
Abbreviations.
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
6. Section 86.431–78 is amended by
adding paragraph (e) to read as follows:
§ 86.431–78
Data submission.
*
*
*
*
*
(e) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
zero kilometer certification test (if one is
conducted) and with each test
conducted at the applicable minimum
test distance as defined in § 86.427–78.
Use the procedures specified in 40 CFR
part 1065 as needed to measure N2O,
and CH4. Report these values in your
application for certification. Smallvolume manufacturers (as defined in
§ 86.410–2006(e)) may omit this
requirement. Use the same measurement
methods as for your other results to
report a single value for CO2, N2O, and
CH4. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/km.
(2) Round N2O to the nearest 0.001 g/
km.
(3) Round CH4 to the nearest 0.001g/
km.
Subpart S—[Amended]
7. Section 86.1804–01 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
§ 86.1804–01
*
*
*
Acronyms and abbreviations.
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
8. Section 86.1843–01 is amended by
adding paragraph (i) to read as follows:
§ 86.1843–01 General information
requirements.
*
*
*
*
*
(i) Air conditioning leakage reporting.
Starting in the 2011 model year, the
manufacturer shall calculate and report
a value for the annual leakage of
refrigerant emissions from the air
conditioning system for each model
type as described in 40 CFR 1064.201.
The manufacturer shall also report the
type of refrigerant and the refrigerant
capacity for each air conditioning
E:\FR\FM\10APP2.SGM
10APP2
16608
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
system for each model type. The
manufacturer shall calculate and report
these items for each combination of
vehicle model type (as defined in 40
CFR 600.002) and air conditioning
system produced. However, calculation
and reporting of these items for multiple
air conditioning systems for a given
model type is not necessary if air
conditioning systems are identical with
respect to the characteristics identified
in paragraphs (i)(1) through (8) of this
section and they meet the quantitative
criteria identified in paragraph (i)(9) of
this section. Consider all the following
criteria to determine whether to
calculate separate leakage rates for
different air conditioning systems.
(1) Compressor type (e.g., belt driven
or electric).
(2) Number and type of rigid pipes
and method of connecting sections of
rigid pipes.
(3) Number and type of flexible hose
and method of connecting sections of
flexible hose. Consider two hoses to be
of a different type if they use different
materials or if they have a different
configuration of layers for reducing
permeation.
(4) Number of high-side service ports.
(5) Number of low-side service ports.
(6) Number and type of switches,
transducers, and expansion valves.
(7) Number and type of refrigerant
control devices.
(8) Number and type of heat
exchangers, mufflers, receiver/driers,
and accumulators.
(9) The following quantitative criteria
(based on nominal values) define
operating characteristics for including
air conditioning systems together:
(i) Refrigerant mass (rated capacity) of
larger system divided by refrigerant
mass of smaller system at or below 1.1.
(ii) Total length of rigid pipe in the
longer system divided by total length of
rigid pipe in the shorter system at or
below 1.1.
(iii) Total length of flexible hose in
the longer system divided by total
length of flexible hose in the shorter
system at or below 1.1.
9. Section 86.1844–01 is amended by
adding paragraph (j) to read as follows:
§ 86.1844–01 Information requirements:
Application for certification and submittal of
information upon request.
*
*
*
*
*
(j) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
certification test on an emission data
vehicle. Do not apply deterioration
factors to the results. Use the procedures
specified in 40 CFR part 1065 as needed
to measure N2O, and CH4. Report these
values in your application for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
certification. Use the same measurement
methods as for your other results to
report a single value for CO2, N2O, and
CH4 for each test. Round the final values
as follows:
(1) Round CO2 to the nearest 1 g/mi.
(2) Round N2O to the nearest 0.001 g/
mi.
(3) Round CH4 to the nearest 0.001g/
mi.
PART 87—[AMENDED]
10. The authority citation for part 87
is revised to read as follows:
Authority: 42 U.S.C. 7401–7671q.
11. Section 87.2 is amended by
adding the abbreviations CH4 and CO2
in alphanumeric order to read as
follows:
*
*
Acronyms and abbreviations.
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
Subpart B—[Amended]
15. Section 89.115 is amended by
revising paragraph (d)(9) to read as
follows:
§ 89.115
Application for certificate.
*
Subpart A—[Amended]
§ 87.2
§ 89.3
Acronyms and abbreviations.
*
*
*
*
CH4 methane.
*
*
*
*
*
CO2 carbon dioxide.
*
*
*
*
*
12. Section 87.64 is revised to read as
follows:
*
*
*
*
(d) * * *
(9) All test data obtained by the
manufacturer on each test engine,
including CO2, N2O, and CH4 as
specified in § 89.407(d)(1);
*
*
*
*
*
Subpart E—[Amended]
16. Section 89.407 is amended by
revising paragraph (d)(1) to read as
follows:
§ 89.407
Engine dynamometer test run.
(a) The system and procedures for
sampling and measurement of gaseous
emissions shall be as specified by
Appendices 3 and 5 to ICAO Annex 16
(incorporated by reference in § 87.8).
(b) Starting in the 2011 model year,
measure CH4 with each certification
test. Use good engineering judgment to
determine CH4 emissions using a
nonmethane cutter or gas
chromatograph as described in 40 CFR
1065.265 and 1065.267. Report CH4 and
CO2 values along with your emission
levels of regulated pollutants. Round the
final values as follows:
(1) Round CO2 to the nearest 1 g/
kilonewton rO.
(2) Round CH4 to the nearest 0.01g/g/
kilonewton rO.
*
*
*
*
(d) * * *
(1) Measure HC, CO, CO2, and NOX
concentrations in the exhaust sample.
Starting in the 2011 model year, also
measure N2O, and CH4 with each lowhour certification test using the
procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers (as defined in 40 CFR
1039.801) may omit N2O, and CH4
measurements. Use the same units and
modal calculations as for your other
results to report a single weighted value
for CO2, N2O, and CH4. Round the final
values as follows:
(i) Round CO2 to the nearest 1 g/kWhr.
(ii) Round N2O to the nearest 0.001 g/
kW-hr.
(iii) Round CH4 to the nearest 0.001g/
kW-hr.
*
*
*
*
*
PART 89—[AMENDED]
PART 90—[AMENDED]
13. The authority citation for part 89
continues to read as follows:
17. The authority citation for part 90
continues to read as follows:
§ 87.64 Sampling and analytical
procedures for measuring gaseous exhaust
emissions.
Authority: 42 U.S.C. 7401–7671q.
*
Authority: 42 U.S.C. 7401–7671q.
Subpart A—[Amended]
Subpart A—[Amended]
14. Section 89.3 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
18. Section 90.5 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
PO 00000
Frm 00162
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 90.5
*
Acronyms and abbreviations.
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
Subpart B—[Amended]
22. Section 94.104 is amended by
adding paragraph (e) to read as follows:
Subpart B—[Amended]
§ 94.104 Test procedures for Category 2
marine engines.
19. Section 90.107 is amended by
revising paragraph (d)(8) to read as
follows:
§ 90.107
*
*
*
*
*
(e) Measure CO2 as described in 40
CFR 92.129 through the 2010 model
year. Starting in the 2011 model year,
measure CO2, N2O, and CH4 as specified
in 40 CFR 1042.235.
Application for certification.
*
*
*
*
*
(d) * * *
(8) All test data obtained by the
manufacturer on each test engine,
including CO2, N2O, and CH4 as
specified in § 90.409(c)(1);
*
*
*
*
*
§ 94.109
Subpart C—[Amended]
20. Section 90.409 is amended by
revising paragraph (c)(1) to read as
follows:
24. Section 94.203 is amended by
revising paragraph (d)(10) to read as
follows:
Engine dynamometer test run.
*
*
*
*
*
(c) * * *
(1) Measure HC, CO, CO2, and NOX
concentrations in the exhaust sample.
Starting in the 2011 model year, also
measure N2O, and CH4 with each lowhour certification test using the
procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit N2O, and CH4
measurements. Use the same units and
modal calculations as for your other
results to report a single weighted value
for CO2, N2O, and CH4. Round the final
values as follows:
(i) Round CO2 to the nearest 1 g/kWhr.
(ii) Round N2O to the nearest 0.001 g/
kW-hr.
(iii) Round CH4 to the nearest 0.001g/
kW-hr.
*
*
*
*
*
PART 94—[AMENDED]
21. The authority citation for part 94
continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
Subpart A—[Amended]
22. Section 94.3 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
§ 94.3
Abbreviations.
*
*
*
*
*
*
*
*
*
*
VerDate Nov<24>2008
15:41 Apr 09, 2009
[Amended]
23. Section 94.109 is amended by
adding paragraph (d) to read as follows:
Subpart E—[Amended]
§ 90.409
Subpart B [Reserved]
CH4 methane.
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
*
Jkt 217001
§ 94.203
Application for certification.
*
*
*
*
*
(d) * * *
(10) All test data obtained by the
manufacturer on each test engine,
including CO2, N2O, and CH4 as
specified in 40 CFR 89.407(d)(1) for
Category 1 engines, § 94.104(e) for
Category 2 engines, and § 94.109(d) for
Category 3 engines. Small-volume
manufacturers may omit the
requirement to measure and report N2O,
and CH4.
*
*
*
*
*
25. Add part 98 to read as follows:
PART 98—MANDATORY
GREENHOUSE GAS REPORTING
Sec.
Subpart A—General Provisions
98.1
98.2
98.3
Purpose and scope.
Do I need to report?
What are the general monitoring,
reporting, recordkeeping and verification
requirements of this part?
98.4 Authorization and responsibilities of
the designated representative.
98.5 How do I submit my report?
98.6 What definitions do I need to
understand?
98.7 What standardized methods are
incorporated by reference into this part?
98.8 What are the compliance and
enforcement provisions of this part?
Table A–1 of Subpart A—Global Warming
Potentials (100-Year Time Horizon)
Table A–2 of Subpart A—Units of Measure
Conversions
PO 00000
Frm 00163
Fmt 4701
Sfmt 4702
16609
Subpart C—General Stationary Fuel
Combustion Sources
98.30 Definition of the source category.
98.31 Reporting threshold.
98.32 GHGs to report.
98.33 Calculating GHG emissions.
98.34 Monitoring and QA/QC
requirements.
98.35 Procedures for estimating missing
data.
98.36 Data reporting requirements.
98.37 Records that must be retained.
98.38 Definitions.
Table C–1 of Subpart C—Default CO2
Emission Factors and High Heat Values
for Various Types of Fuel
Table C–2 of Subpart C—Default CO2
Emission Factors for the Combustion of
Alternative Fuels
Table C–3 of Subpart C—Default CH4 and
N2O Emission Factors for Various Types
of Fuel
Subpart D—Electricity Generation
98.40 Definition of the source category.
98.41 Reporting threshold.
98.42 GHGs to report.
98.43 Calculating GHG emissions.
98.44 Monitoring and QA/QC requirements
98.45 Procedures for estimating missing
data.
98.46 Data reporting requirements.
98.47 Records that must be retained.
98.48 Definitions.
Subpart E—Adipic Acid Production
98.50 Definition of source category.
98.51 Reporting threshold.
98.52 GHGs to report.
98.53 Calculating GHG emissions.
98.54 Monitoring and QA/QC requirements
98.55 Procedures for estimating missing
data.
98.56 Data reporting requirements.
98.57 Records that must be retained.
98.58 Definitions.
Subpart F—Aluminum Production
98.60 Definition of the source category.
98.61 Reporting threshold.
98.62 GHGs to report.
98.63 Calculating GHG emissions.
98.64 Monitoring and QA/QC
requirements.
98.65 Procedures for estimating missing
data.
98.66 Data reporting requirements.
98.67 Records that must be retained.
98.68 Definitions.
Subpart G—Ammonia Manufacturing
98.70 Definition of source category.
98.71 Reporting threshold.
98.72 GHGs to report.
98.73 Calculating GHG emissions.
98.74 Monitoring and QA/QC
requirements.
98.75 Procedures for estimating missing
data.
98.76 Data reporting requirements.
98.77 Records that must be retained.
98.78 Definitions.
Subpart H—Cement Production
98.80 Definition of the source category.
E:\FR\FM\10APP2.SGM
10APP2
16610
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
98.142 GHGs to report.
98.143 Calculating GHG emissions.
98.144 Monitoring and QA/QC
requirements.
98.145 Procedures for estimating missing
data.
98.146 Data reporting requirements.
98.147 Records that must be retained.
98.148 Definitions.
Table N–1 of Subpart N—CO2 Emission
Factors for Carbonate-Based Raw
Materials
98.81 Reporting threshold.
98.82 GHGs to report.
98.83 Calculating GHG emissions.
98.84 Monitoring and QA/QC
requirements.
98.85 Procedures for estimating missing
data.
98.86 Data reporting requirements.
98.87 Records that must be retained.
98.88 Definitions.
Subpart I—Electronics Manufacturing
98.90 Definition of the source category.
98.91 Reporting threshold.
98.92 GHGs to report.
98.93 Calculating GHG emissions.
98.94 Monitoring and QA/QC
requirements.
98.95 Procedures for estimating missing
data.
98.96 Data reporting requirements.
98.97 Records that must be retained.
98.98 Definitions.
Table I–1 of Subpart I—F–GHGs Typically
Used by the Electronics Industry
Table I–2 of Subpart I—Default Emission
Factors for Semiconductor and MEMs
Manufacturing
Table I–3 of Subpart I—Default Emission
Factors for LCD Manufacturing
Table I–4 of Subpart I—Default Emission
Factors for PV Manufacturing
Subpart O—HCFC–22 Production and HFC–
23 Destruction
98.150 Definition of the source category.
98.151 Reporting threshold.
98.152 GHGs to report.
98.153 Calculating GHG emissions.
Table O–1 of Subpart O—Emission Factors
for Equipment Leaks
98.154 Monitoring and QA/QC
requirements.
98.155 Procedures for estimating missing
data.
98.156 Data reporting requirements.
98.157 Records that must be retained.
98.158 Definitions.
Subpart J—Ethanol Production
98.100 Definition of the source category.
98.101 Reporting threshold.
98.102 GHGs to report.
98.103 Definitions.
Subpart K—Ferroalloy Production
98.110 Definition of the source category.
98.111 Reporting threshold.
98.112 GHGs to report.
98.113 Calculating GHG emissions.
98.114 Monitoring and QA/QC
requirements.
98.115 Procedures for estimating missing
data.
98.116 Data reporting requirements.
98.117 Records that must be retained.
98.118 Definitions.
Table K–1 of Subpart K—Electric Arc
Furnace (EAF) CH4 Emission Factors
Subpart L—Fluorinated Greenhouse Gas
Production
98.120 Definition of the source category.
98.121 Reporting threshold.
98.122 GHGs to report.
98.123 Calculating GHG emissions.
98.124 Monitoring and QA/QC
requirements.
98.125 Procedures for estimating missing
data.
98.126 Data reporting requirements.
98.127 Records that must be retained.
98.128 Definitions.
Subpart M—Food Processing
98.130 Definition of the source category.
98.131 Reporting threshold.
98.132 GHGs to report.
98.133 Definitions.
Subpart N—Glass Production
98.140 Definition of the source category.
98.141 Reporting threshold.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Subpart P—Hydrogen Production
98.160 Definition of the source category.
98.161 Reporting threshold.
98.162 GHGs to report.
98.163 Calculating GHG emissions.
98.164 Monitoring and QA/QC
requirements.
98.165 Procedures for estimating missing
data.
98.166 Data reporting requirements.
98.167 Records that must be retained.
98.168 Definitions.
Subpart Q—Iron and Steel Production
98.170 Definition of the source category.
98.171 Reporting threshold.
98.172 GHGs to report.
98.173 Calculating GHG emissions.
98.174 Monitoring and QA/QC
requirements.
98.175 Procedures for estimating missing
data.
98.176 Data reporting requirements.
98.177 Records that must be retained.
98.178 Definitions.
Subpart R—Lead Production
98.180 Definition of the source category.
98.181 Reporting threshold.
98.182 GHGs to report.
98.184 Monitoring and QA/QC
requirements.
98.185 Procedures for estimating missing
data.
98.186 Data Reporting Procedures.
98.187 Records that must be retained.
98.188 Definitions.
Subpart S—Lime Manufacturing
98.190 Definition of the source category.
98.191 Reporting threshold.
98.192 GHGs to report.
98.193 Calculating GHG emissions.
98.194 Monitoring and QA/QC
requirements.
98.195 Procedures for estimating missing
data.
98.196 Data reporting requirements.
PO 00000
Frm 00164
Fmt 4701
Sfmt 4702
98.197 Records that must be retained.
98.198 Definitions.
Table S–1 of Subpart S—Basic Parameters for
the Calculation of Emission Factors for
Lime Production
Subpart T—Magnesium Production
98.200 Definition of source category.
98.201 Reporting threshold.
98.202 GHGs to report.
98.203 Calculating GHG emissions.
98.204 Monitoring and QA/QC
requirements.
98.205 Procedures for estimating missing
data.
98.206 Data reporting requirements.
98.207 Records that must be retained.
98.208 Definitions.
Subpart U—Miscellaneous Uses of
Carbonate
98.210 Definition of the source category.
98.211 Reporting threshold.
98.212 GHGs to report.
98.213 Calculating GHG emissions.
98.214 Monitoring and QA/QC
requirements.
98.215 Procedures for estimating missing
data.
98.216 Data reporting requirements.
98.217 Records that must be retained.
98.218 Definitions.
Table U–1 of Subpart U—CO2 Emission
Factors for Common Carbonates
Subpart V—Nitric Acid Production
98.220 Definition of source category.
98.221 Reporting threshold.
98.222 GHGs to report.
98.223 Calculating GHG emissions.
98.224 Monitoring and QA/QC
requirements.
98.225 Procedures for estimating missing
data.
98.226 Data reporting requirements.
98.227 Records that must be retained.
98.228 Definitions.
Subpart W—Oil and Natural Gas Systems
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC
requirements.
98.235 Procedures for estimating missing
data.
98.236 Data reporting requirements.
98.236 Records that must be retained.
98.237 Definitions.
Subpart X—Petrochemical Production
98.240 Definition of the source category.
98.241 Reporting threshold.
98.242 GHGs to report.
98.243 Calculating GHG emissions.
98.244 Monitoring and QA/QC
requirements.
98.245 Procedures for estimating missing
data.
98.246 Data reporting requirements.
98.247 Records that must be retained.
98.248 Definitions.
Subpart Y—Petroleum Refineries
98.250 Definition of source category.
98.251 Reporting threshold.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
98.252 GHGs to report.
98.253 Calculating GHG emissions.
98.254 Monitoring and QA/QC
requirements.
98.255 Procedures for estimating missing
data.
98.256 Data reporting requirements.
98.257 Records that must be retained.
98.258 Definitions.
Subpart Z—Phosphoric Acid Production
98.260 Definition of the source category.
98.261 Reporting threshold.
98.262 GHGs to report.
98.263 Calculating GHG emissions.
98.264 Monitoring and QA/QC
requirements.
98.265 Procedures for estimating missing
data.
98.266 Data reporting requirements.
98.267 Records that must be retained.
98.268 Definitions.
Subpart AA—Pulp and Paper Manufacturing
98.270 Definition of source category.
98.271 Reporting threshold.
98.272 GHGs to report.
98.273 Calculating GHG emissions.
98.274 Monitoring and QA/QC
requirements.
98.275 Procedures for estimating missing
data.
98.276 Data reporting requirements.
98.277 Records that must be retained.
98.278 Definitions.
Table AA–1 of Subpart AA—Kraft Pulping
Liquor Emissions Factors for BiomassBased CO2, CH4, and N2O
Table AA–2 of Subpart AA—Kraft Lime Kiln
and Calciner Emissions Factors for Fossil
Fuel-Based CO2, CH4, and N2O
Subpart BB—Silicon Carbide Production
98.280 Definition of the source category.
98.281 Reporting threshold.
98.283 Calculating GHG emissions.
98.284 Monitoring and QA/QC
requirements.
98.285 Procedures for estimating missing
data.
98.286 Data reporting requirements.
98.287 Records that must be retained.
98.288 Definitions.
Subpart CC—Soda Ash Manufacturing
98.290 Definition of the source category.
98.291 Reporting threshold.
98.292 GHGs to report.
98.293 Calculating GHG emissions.
98.294 Monitoring and QA/QC
requirements.
98.295 Procedures for estimating missing
data.
98.296 Data reporting requirements.
98.297 Records that must be retained.
98.298 Definitions.
Subpart DD—Sulfur Hexafluoride (SF6)
From Electrical Equipment
98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC
requirements.
98.305 Procedures for estimating missing
data.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
98.306
98.307
98.308
Data reporting requirements.
Records that must be retained.
Definitions.
Subpart EE—Titanium Dioxide Production
98.310 Definition of the source category.
98.311 Reporting threshold.
98.312 GHGs to report.
98.313 Calculating GHG emissions.
98.314 Monitoring and QA/QC
requirements.
98.315 Procedures for estimating missing
data.
98.316 Data reporting requirements.
98.317 Records that must be retained.
98.318 Definitions.
Subpart FF—Underground Coal Mines
98.320 Definition of the source category.
98.321 Reporting threshold.
98.322 GHGs to report.
98.323 Calculating GHG emissions.
98.324 Monitoring and QA/QC
requirements.
98.325 Procedures for estimating missing
data.
98.326 Data reporting requirements.
98.327 Records that must be retained.
98.328 Definitions.
Subpart GG—Zinc Production
98.330 Definition of the source category.
98.331 Reporting threshold.
98.332 GHGs to report.
98.333 Calculating GHG emissions.
98.334 Monitoring and QA/QC
requirements.
98.335 Procedures for estimating missing
data.
98.336 Data reporting requirements.
98.337 Records that must be retained.
98.338 Definitions.
Subpart HH—Landfills
98.340 Definition of the source category.
98.341 Reporting threshold.
98.343 Calculating GHG emissions.
98.344 Monitoring and QA/QC
requirements.
98.345 Procedures for estimating missing
data.
98.346 Data reporting requirements.
98.347 Records that must be retained.
98.348 Definitions.
Table HH–1 of Subpart HH—Emissions
Factors, Oxidation Factors and Methods
Table HH–2 of Subpart HH—U.S. Per Capita
Waste Disposal Rates
Subpart II—Wastewater Treatment
98.350 Definition of source category.
98.351 Reporting threshold.
98.352 GHGs to report.
98.353 Calculating GHG emissions.
98.354 Monitoring and QA/QC
requirements.
98.355 Procedures for estimating missing
data.
98.356 Data reporting requirements.
98.357 Records that must be retained.
98.358 Definitions.
Table II–1 of Subpart II—Emission Factors
Subpart JJ—Manure Management
98.360 Definition of the source category.
98.361 Reporting threshold.
98.362 GHGs to report.
PO 00000
Frm 00165
Fmt 4701
Sfmt 4702
16611
98.363 Calculating GHG emissions.
98.364 Monitoring and QA/QC
requirements.
98.365 Procedures for estimating missing
data.
98.366 Data reporting requirements.
98.367 Records that must be retained.
98.368 Definitions.
Table JJ–1 of Subpart JJ—Waste
Characteristics Data
Table JJ–2 of Subpart JJ—Methane
Conversion Factors
Table JJ–3 of Subpart JJ—Collection
Efficiencies of Anaerobic Digesters
Table JJ–4 of Subpart JJ—Nitrous Oxide
Emission Factors (kg N2O-N/kg Kjdl N)
Subpart KK—Suppliers of Coal
98.370 Definition of the source category.
98.371 Reporting threshold.
98.372 GHGs to report.
98.373 Calculating GHG emissions.
98.374 Monitoring and QA/QC
requirements.
98.375 Procedures for estimating missing
data.
98.376 Data reporting requirements.
98.377 Records that must be retained.
98.378 Definitions.
Table KK–1 of Subpart KK—Default Carbon
Content of Coal for Method 3 (CO2 lbs/
MMBtu1)
Subpart LL—Suppliers of Coal-based Liquid
Fuels
98.380 Definition of the source category.
98.381 Reporting threshold.
98.382 GHGs to report.
98.383 Calculating GHG emissions.
98.384 Monitoring and QA/QC
requirements.
98.385 Procedures for estimating missing
data.
98.386 Data reporting requirements.
98.387 Records that must be retained.
98.388 Definitions.
Subpart MM—Suppliers of Petroleum
Products
98.390 Definition of the source category.
98.391 Reporting threshold.
98.392 GHGs to report.
98.393 Calculating GHG emissions.
98.394 Monitoring and QA/QC
requirements.
98.395 Procedures for estimating missing
data.
98.396 Data reporting requirements.
98.397 Records that must be retained.
98.398 Definitions.
Table MM–1 of Subpart MM—Default CO2
Factors for Petroleum Products 1,2
Table MM–2 of Subpart MM—Default CO2
Factors for Natural Gas Liquids
Table MM–3 of Subpart MM—Default CO2
Factors for Biomass Products and
Feedstock
Subpart NN—Suppliers of Natural Gas and
Natural Gas Liquids
98.400 Definition of the source category.
98.401 Reporting threshold.
98.402 GHGs to report.
98.403 Calculating GHG emissions.
98.404 Monitoring and QA/QC
requirements.
E:\FR\FM\10APP2.SGM
10APP2
16612
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
98.405 Procedures for estimating missing
data.
98.406 Data reporting requirements.
98.407 Records that must be retained.
98.408 Definitions.
Table NN–1 of Subpart NN—Default Factors
for Calculation Methodology 1 of This
Subpart
Table NN–2 of Subpart NN—Lookup Default
Values for Calculation Methodology 2 of
This Subpart
Subpart OO—Suppliers of Industrial
Greenhouse Gases
98.410 Definition of the source category.
98.411 Reporting threshold.
98.412 GHGs to report.
98.413 Calculating GHG emissions.
98.414 Monitoring and QA/QC
requirements.
98.415 Procedures for estimating missing
data.
98.416 Data reporting requirements.
98.417 Records that must be retained.
98.418 Definitions.
Subpart PP—Suppliers of Carbon Dioxide
98.420 Definition of the source category.
98.421 Reporting threshold.
98.422 GHGs to report.
98.423 Calculating GHG emissions.
98.424 Monitoring and QA/QC
requirements.
98.425 Procedures for estimating missing
data.
98.426 Data reporting requirements.
98.427 Records that must be retained.
98.428 Definitions.
Authority: 42 U.S.C. 7401, et seq.
Subpart A—General Provisions
§ 98.1
Purpose and scope.
(a) This part establishes mandatory
greenhouse gas (GHG) emissions
reporting requirements for certain
facilities that directly emit GHG as well
as for fossil fuel suppliers and industrial
GHG suppliers.
(b) Owners and operators of facilities
and suppliers that are subject to this
part must follow the requirements of
subpart A and all applicable subparts of
this part. If a conflict exists between a
provision in subpart A and any other
applicable subpart, the requirements of
the subparts B through PP of this part
shall take precedence.
§ 98.2
Do I need to report?
(a) The GHG emissions reporting
requirements, and related monitoring,
recordkeeping, and verification
requirements, of this part apply to the
owners and operators of any facility that
meets the requirements of either
paragraph (a)(1), (a)(2), or (a)(3) of this
section; and any supplier that meets the
requirements of paragraph (a)(4) of this
section:
(1) A facility that contains any of the
source categories listed in this
paragraph in any calendar year starting
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
in 2010. For these facilities, the GHG
emission report must cover all sources
in any source category for which
calculation methodologies are provided
in subparts B through JJ of this part.
(i) Electricity generating facilities that
are subject to the Acid Rain Program, or
that contain electric generating units
that collectively emit 25,000 metric tons
CO2e or more per year.
(ii) Adipic acid production.
(iii) Aluminum production.
(iv) Ammonia manufacturing.
(v) Cement production.
(vi) Electronics—Semiconductor,
microelectricomechanical system
(MEMS), and liquid crystal display
(LCD) manufacturing facilities with an
annual production capacity that exceeds
any of the thresholds listed in this
paragraph.
(A) Semiconductors: 1,080 m2 silicon.
(B) MEMS: 1,020 m2 silicon.
(C) LCD: 235,700 m2 LCD.
(vii) Electric power systems that
include electrical equipment with a
total nameplate capacity that exceeds
17,820 lbs (7,838 kg) of SF6 or
perfluorocarbons (PFCs).
(viii) HCFC–22 production.
(ix) HFC–23 destruction processes
that are not collocated with a HCFC–22
production facility and that destroy
more than 2.14 metric tons of HFC–23
per year.
(x) Lime manufacturing.
(xi) Nitric acid production.
(xii) Petrochemical production.
(xiii) Petroleum refineries.
(xiv) Phosphoric acid production.
(xv) Silicon carbide production.
(xvi) Soda ash production.
(xvii) Titanium dioxide production.
(xviii) Underground coal mines that
are subject to quarterly or more frequent
sampling by MSHA of ventilation
systems.
(xix) Municipal landfills that generate
CH4 in amounts equivalent to 25,000
metric tons CO2e or more per year.
(xx) Manure management systems that
emit CH4 and N2O in amounts
equivalent to 25,000 metric tons CO2e or
more per year.
(2) Any facility that emits 25,000
metric tons CO2e or more per year in
combined emissions from stationary
fuel combustion units, miscellaneous
uses of carbonate, and all source
categories that are listed in this
paragraph (a)(2) and that are located at
the facility in any calendar year starting
in 2010. For these facilities, the GHG
emission report must cover all source
categories for which calculation
methodologies are provided in subparts
B through JJ of this part.
(i) Electricity generation.
(ii) Electronics—photovoltaic
manufacturing.
PO 00000
Frm 00166
Fmt 4701
Sfmt 4702
(iii) Ethanol production.
(iv) Ferroalloy production.
(v) Fluorinated greenhouse gas
production.
(vi) Food processing.
(vii) Glass production.
(viii) Hydrogen production.
(ix) Iron and steel production.
(x) Lead production.
(xi) Magnesium production.
(xii) Oil and natural gas systems.
(xiii) Pulp and Paper Manufacturing.
(xiv) Zinc production.
(xv) Industrial landfills.
(xvi) Wastewater treatment.
(3) Any facility that in any calendar
year starting in 2010 meets all three of
the conditions listed in this paragraph
(a)(3). For these facilities, the GHG
emission report must cover emissions
from stationary fuel combustion sources
only. For 2010 only, the facilities may
submit an abbreviated emissions report
according to § 98.3(d).
(i) The facility does not contain any
source category designated in
paragraphs (a)(1) and (2) of this section.
(ii) The aggregate maximum rated heat
input capacity of the stationary fuel
combustion units at the facility is 30
mmBtu/hr or greater.
(iii) The facility emits 25,000 metric
tons CO2e or more per year from all
stationary fuel combustion sources.
(4) Any supplier of any of the
products listed in this paragraph (a)(4)
in any calendar year starting in 2010.
For these suppliers, the GHG emissions
report must cover all applicable
products for which calculation
methodologies are provided in subparts
KK through PP of this part.
(i) Coal.
(ii) Coal-based liquid fuels.
(iii) Petroleum products.
(iv) Natural gas and natural gas
liquids.
(v) Industrial greenhouse gases, as
specified in either paragraph (a)(4)(v)(A)
or (B) of this section:
(A) All producers of industrial
greenhouse gases.
(B) Importers of industrial greenhouse
gases with total bulk imports that
exceed 25,000 metric tons CO2e per
year.
(C) Exporters of industrial greenhouse
gases with total bulk exports that exceed
25,000 metric tons CO2e per year.
(vi) Carbon dioxide, as specified in
either paragraph (a)(4)(vi)(A) or (B) of
this section.
(A) All producers of carbon dioxide.
(B) Importers of CO2 or a combination
of CO2 and other industrial GHGs with
total bulk imports that exceed 25,000
metric tons CO2e per year.
(C) Exporters of CO2 or a combination
of CO2 and other industrial GHGs with
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
n
CO 2 e = ∑ GHG i x GWPi
(Eq. A-1)
i =1
Where:
CO2e = Carbon dioxide equivalent, metric
tons/year.
GHGi = Mass emissions of each greenhouse
gas emitted, metric tons/year.
GWPi = Global warming potential for each
greenhouse gas from Table A–1 of this
subpart.
n = The number of greenhouse gases emitted.
(5) For purpose of determining if an
emission threshold has been exceeded,
capture of CO2 for transfer off site must
not be considered.
(c) To calculate GHG emissions for
comparison to the 25,000 metric ton
CO2e/year emission threshold for
stationary fuel combustion under
paragraph (a)(3) of this section, the
owner or operator shall calculate CO2,
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
CH4, N2O emissions from all stationary
combustion units using the methods
specified in paragraph (b)(2) of this
section. Then, convert the emissions of
each GHG to metric tons CO2e per year
using Equation A–1 of this section, and
sum the emissions for all units at the
facility.
(d) To calculate GHG quantities for
comparison to the 25,000 metric ton
CO2e per year threshold for importers
and exporters of industrial greenhouse
gases under paragraph (a)(4) of this
section, the owner or operator shall
calculate the total annual CO2e of all the
industrial GHGs that the company
imported and the total annual CO2e of
all the industrial GHGs that the
company exported during the reporting
year, as described in paragraphs (d)(1)
through (d)(3) of this section.
(1) Calculate the mass in metric tons
per year of CO2, N2O, and each
fluorinated GHG (as defined in § 98.6)
imported and the mass in metric tons
per year of CO2, N2O, and fluorinated
GHG exported during the year. The
masses shall be calculated using the
methodologies specified in subpart OO
of this part.
(2) Convert the mass of each GHG
imported and each GHG exported from
paragraph (d)(1) of this section to metric
tons of CO2e using Equation A–1 of
§ 98.3.
(3) Sum the total annual metric tons
of CO2e in paragraph (d)(2) of this
section for all imported GHGs. Sum the
total annual metric tons of CO2e in
paragraph (d)(2) of this section for all
exported GHGs.
(e) If a capacity or generation
reporting threshold in paragraph (a)(1)
of this section applies, the owner or
operator shall review the appropriate
records to determine whether the
threshold has been exceeded.
(f) Except as provided in paragraph (g)
of this section, the owners and operators
of a facility or supplier that does not
meet the applicability requirements of
paragraph (a) of this section are not
required to submit an emission report
for the facility or supplier. Such owners
and operators must reevaluate the
applicability to this part to the facility
or supplier (which reevaluation must
include the revising of any relevant
emissions calculations or other
calculations) whenever there is any
change to the facility or supplier that
could cause the facility or supplier to
meet the applicability requirements of
paragraph (a) of this section. Such
changes include but are not limited to
process modifications, increases in
operating hours, increases in
production, changes in fuel or raw
PO 00000
Frm 00167
Fmt 4701
Sfmt 4702
material use, addition of equipment,
and facility expansion.
(g) Once a facility or supplier is
subject to the requirements of this part,
the owners and operators of the facility
or supply operation must continue for
each year thereafter to comply with all
requirements of this part, including the
requirement to submit GHG emission
reports, even if the facility or supplier
does not meet the applicability
requirements in paragraph (a) of this
section in a future year. If a GHG
emission source in a future year through
change of ownership becomes part of a
different facility that has not previously
met, and does not in that future year
meet, the applicability requirements of
paragraph (a) of this section; the owner
or operator shall comply with the
requirements of this part only with
regard to that source, including the
requirement to submit GHG emission
reports.
(h) Table A–2 of this subpart provides
a conversion table for some of the
common units of measure used in part
98.
§ 98.3 What are the general monitoring,
reporting, recordkeeping and verification
requirements of this part?
The owner or operator of a facility or
supplier that is subject to the
requirements of this part must submit
GHG emissions reports to the
Administrator, as specified in
paragraphs (a) through (g) of this
section.
(a) General. You must collect
emissions data, calculate GHG
emissions, and follow the procedures
for quality assurance, missing data,
recordkeeping, and reporting that are
specified in each relevant subpart of this
part.
(b) Schedule. Unless otherwise
specified in subparts B through PP, you
must submit an annual GHG emissions
report no later than March 31 of each
calendar year for GHG emissions in the
previous calendar year.
(1) For existing facilities that
commenced operation before January 1,
2010, you must report emissions for
calendar year 2010 and each subsequent
calendar year.
(2) For new facilities that commence
operation on or after January 1, 2010,
you must report emissions for the first
calendar year in which the facility
operates, beginning with the first
operating month and ending on
December 31 of that year. Each
subsequent annual report must cover
emissions for the calendar year,
beginning on January 1 and ending on
December 31.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.000</GPH>
total bulk exports that exceed 25,000
metric tons CO2e per year.
(b) To calculate GHG emissions for
comparison to the 25,000 metric ton
CO2e per year emission threshold in
paragraph (a)(2) of this section, the
owner or operator shall calculate annual
CO2e emissions, as described in
paragraphs (b)(1) through (4) of this
section.
(1) Estimate the annual emissions of
CO2, CH4, N2O, and fluorinated GHG (as
defined in § 98.6) in metric tons from
stationary fuel combustion units,
miscellaneous uses of carbonate, and
any applicable source category listed in
paragraph § 98.2(a)(2). The GHG
emissions shall be calculated using the
methodologies specified in each
applicable subpart. For this calculation,
facilities with industrial landfills must
use the CH4 generation calculation
methodology in subpart HH of this part.
(2) For stationary combustion units,
calculate the annual CO2 emissions in
metric tons using any appropriate
method specified in § 98.33(a). Calculate
the annual CH4 and N2O emissions from
the stationary combustion sources in
metric tons using Equation C–9 in
§ 98.33(c). Carbon dioxide emissions
from the combustion of biogenic fuels
shall be excluded from the calculations.
In using Equations C–2a and C–9 in
§ 98.33, the high heat value for all types
of fuel shall be determined monthly.
(3) For miscellaneous uses of
carbonate, calculate the annual CO2
emissions in metric tons using the
procedures specified in subpart U of
this part.
(4) Sum the emissions estimates from
paragraphs (b)(1), (2), and (3) of this
section for each GHG and calculate
metric tons of CO2e using Equation A–
1.
16613
16614
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(3) For any facility or supplier that
becomes subject to this rule because of
a physical or operational change that is
made after January 1, 2010, you must
report emissions for the first calendar
year in which the change occurs,
beginning with the first month of the
change and ending on December 31 of
that year. Each subsequent annual
report must cover emissions for the
calendar year, beginning on January 1
and ending on December 31.
(c) Content of the annual report.
Except as provided in paragraph (d) of
this section, each annual GHG
emissions report shall contain the
following information:
(1) Facility name or supplier name (as
appropriate), street address, physical
address, and Federal Registry System
identification number.
(2) Year covered by the report.
(3) Date of submittal.
(4) Annual emissions of CO2, CH4,
N2O, and each fluorinated GHG.
Emissions must be calculated assuming
no capture of CO2 and reported at the
following levels:
(i) Total facility emissions aggregated
from all applicable source categories in
subparts C through JJ of this part and
expressed in metric tons of CO2e
calculated using Equation A–1 of this
subpart.
(ii) Total emissions aggregated from
all applicable supply categories in
subparts KK through PP of this part and
expressed in metric tons of CO2e
calculated using Equation A–1 of this
subpart.
(iii) Emissions from each applicable
source category or supply category in
subparts C through PP of this part,
expressed in metric tons of each GHG.
(iv) Emissions and other data for
individual units, processes, activities,
and operations as specified for each
source category in the ‘‘Data reporting
requirements’’ section of each
applicable subpart of this part.
(5) Total electricity generated onsite
in kilowatt hours.
(6) Total pounds of synthetic fertilizer
produced at the facility and total
nitrogen contained in that fertilizer.
(7) Total annual mass of CO2 captured
in metric tons.
(8) A signed and dated certification
statement provided by the designated
representative of the owner or operator,
according to the requirements of
§ 98.4(e)(1).
(d) Abbreviated emissions report. In
lieu of the report required by paragraph
(c) of this section, the owner or operator
of an existing facility that is in operation
on January 1, 2010 and that is subject
to § 98.2(a)(3) may submit an
abbreviated GHG emissions report for
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
the facility for emissions in 2010. The
abbreviated report must be submitted by
March 31, 2011. An owner or operator
that submits an abbreviated report for a
facility in 2011 must submit a full GHG
emissions report according to the
requirements of paragraph (c) of this
section for each calendar year thereafter.
The abbreviated facility report must
include the following information:
(1) Facility name, street address,
physical address, and Federal Registry
System identification number.
(2) The year covered by the report.
(3) Date of submittal.
(4) Total facility GHG emissions
aggregated for all stationary fuel
combustion units calculated according
to any appropriate method specified in
§ 98.33(a) and expressed in metric tons
of CO2, CH4, N2O, and CO2e. If Equation
C–2a or C–9 of subpart C are selected,
the high heat value for all types of fuel
shall be determined monthly.
(5) A signed and dated certification
statement provided by the designated
representative of the owner or operator,
according to the requirements of
§ 98.4(e)(1).
(e) Emission Calculations. In
preparing the GHG emissions report,
you must use the emissions calculation
protocols specified in the relevant
subparts, except as specified in
paragraph (d) of this section.
(f) Verification. To verify the
completeness and accuracy of reported
GHG emissions, the Administrator may
review the certification statements
described in paragraphs (c)(8) and (d)(5)
of this section and any other credible
evidence, in conjunction with a
comprehensive review of the emissions
reports and periodic audits of selected
reporting facilities. Nothing in this
section prohibits the Administrator from
using additional information to verify
the completeness and accuracy of the
reports.
(g) Recordkeeping. An owner or
operator that is required to report GHG
emissions under this part must keep
records as specified in this paragraph.
You must retain all required records for
at least 5 years. The records shall be
kept in an electronic or hard-copy
format (as appropriate) and recorded in
a form that is suitable for expeditious
inspection and review. Upon request by
EPA, the records required under this
section must be made available to the
Administrator. For records that are
electronically generated or maintained,
the equipment or software necessary to
read the records shall be made available,
or, if requested by EPA, electronic
records shall be converted to paper
documents. You must retain the
following records, in addition to those
PO 00000
Frm 00168
Fmt 4701
Sfmt 4702
records prescribed in each applicable
subpart of this part:
(1) A list of all units, operations,
processes, and activities for which GHG
emission were calculated.
(2) The data used to calculate the
GHG emissions for each unit, operation,
process, and activity, categorized by fuel
or material type. The results of all
required fuel analyses for high heat
value and carbon content, the results of
all required certification and quality
assurance tests of continuous
monitoring systems and fuel flow
meters if applicable, and analytical
results for the development of sitespecific emissions factors.
(3) Documentation of the process used
to collect the necessary data for the GHG
emissions calculations.
(4) The GHG emissions calculations
and methods used.
(5) All emission factors used for the
GHG emissions calculations.
(6) Any facility operating data or
process information used for the GHG
emission calculations.
(7) Names and documentation of key
facility personnel involved in
calculating and reporting the GHG
emissions.
(8) The annual GHG emissions
reports.
(9) A log book, documenting
procedural changes (if any) to the GHG
emissions accounting methods and
changes (if any) to the instrumentation
critical to GHG emissions calculations.
(10) Missing data computations.
(11) A written quality assurance
performance plan (QAPP). Upon request
from regulatory authorities, the owner
or operator shall make all information
that is collected in conformance with
the QAPP available for review during an
audit. Electronic storage of the
information in the QAPP is permissible,
provided that the information can be
made available in hard copy upon
request during an audit. At a minimum,
the QAPP plan shall include (or refer to
separate documents that contain) a
detailed description of the procedures
that are used for the following activities:
(i) Maintenance and repair of all
continuous monitoring systems, flow
meters, and other instrumentation used
to provide data for the GHG emissions
reported under this part. A maintenance
log shall be kept.
(ii) Calibrations and other quality
assurance tests performed on the
continuous monitoring systems, flow
meters, and other instrumentation used
to provide data for the GHG emissions
reported under this part.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.4 Authorization and responsibilities of
the designated representative.
(a) General. Except as provided under
paragraph (f) of this section, each owner
or operator that is subject to this part,
shall have one and only one designated
representative responsible for certifying
and submitting GHG emissions reports
and any other submissions to the
Administrator under this part.
(b) Authorization of a designated
representative. The designated
representative of the facility shall be
selected by an agreement binding on the
owners and operators and shall act in
accordance with the certification
statements in paragraph (i)(4) of this
section. The designated representative
must be an individual having
responsibility for the overall operation
of the facility or activity such as the
position of the plant manager, operator
of a well or a well field, superintendent,
position of equivalent responsibility, or
an individual or position having overall
responsibility for enviromental matters
for the company.
(c) Responsibility of the designated
representative. Upon receipt by the
Administrator of a complete certificate
of representation under this section, the
designated representative of the facility
shall represent and, by his or her
representations, actions, inactions, or
submissions, legally bind each owner
and operator in all matters pertaining to
this part, notwithstanding any
agreement between the designated
representative and such owners and
operators. The owners and operators
shall be bound by any decision or order
issued to the designated representative
by the Administrator or a court.
(d) Timing. No GHG emissions report
or other submissions under this part
will be accepted until the Administrator
has received a complete certificate of
representation under this section for a
designated representative of the owner
or operator.
(e) Certification of the GHG emissions
report. Each GHG emission report and
any other submission under this part
shall be submitted, signed, and certified
by the designated representative in
accordance with 40 CFR 3.10.
(1) Each such submission shall
include the following certification
statement by the designated
representative: ‘‘I am authorized to
make this submission on behalf of the
owners and operators of the facility (or
supply operation, as appropriate) for
which the submission is made. I certify
under penalty of law that I have
personally examined, and am familiar
with, the statements and information
submitted in this document and all its
attachments. Based on my inquiry of
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
those individuals with primary
responsibility for obtaining the
information, I certify that the statements
and information are to the best of my
knowledge and belief true, accurate, and
complete. I am aware that there are
significant penalties for submitting false
statements and information or omitting
required statements and information,
including the possibility of fine or
imprisonment.’’
(2) The Administrator will accept a
GHG emission report or other
submission under this part only if the
submission is signed and certified in
accordance with paragraph (e)(1) of this
section.
(f) Alternate designated
representative. A certificate of
representation under this section may
designate an alternate designated
representative, who may act on behalf of
the designated representative. The
agreement by which the alternate
designated representative is selected
shall include a procedure for
authorizing the alternate designated
representative to act in lieu of the
designated representative.
(1) Upon receipt by the Administrator
of a complete certificate of
representation under this section, any
representation, action, inaction, or
submission by the alternate designated
representative shall be deemed to be a
representation, action, inaction, or
submission by the designated
representative.
(2) Except in this section, whenever
the term ‘‘designated representative’’ is
used, the term shall be construed to
include the designated representative or
any alternate designated representative.
(g) Changing a designated
representative or alternate designated
representative. The designated
representative (or alternate designated
representative) may be changed at any
time upon receipt by the Administrator
of a superseding complete certificate of
representation under this section.
Notwithstanding any such change, all
representations, actions, inactions, and
submissions by the previous designated
representative (or alternate designated
representative) before the time and date
when the Administrator receives the
superseding certificate of representation
shall be binding on the new designated
representative and the owners and
operators.
(h) Changes in owners and operators.
In the event a new owner or operator is
not included in the list of owners and
operators in the certificate of
representation under this section, such
new owner or operator shall be deemed
to be subject to and bound by the
certificate of representation, the
PO 00000
Frm 00169
Fmt 4701
Sfmt 4702
16615
representations, actions, inactions, and
submissions of the designated
representative and any alternate
designated representative, as if the new
owner or operator were included in
such list. Within 30 days following any
change in the owners and operators,
including the addition of a new owner
or operator, the designated
representative or any alternate
designated representative shall submit a
revision to the certificate of
representation under this section
amending the list of owners and
operators to include the change.
(i) Certificate of representation. A
complete certificate of representation for
a designated representative or an
alternate designated representative shall
include the following elements in a
format prescribed by the Administrator:
(1) Identification of the facility or
supply operation for which the
certificate of representation is
submitted.
(2) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of the designated representative and any
alternate designated representative.
(3) A list of the owners and operators
of the facility or supply operation.
(4) The following certification
statements by the designated
representative and any alternate
designated representative:
(i) ‘‘I certify that I was selected as the
designated representative or alternate
designated representative, as applicable,
by an agreement binding on the owners
and operators that are subject to the
requirements of 40 CFR 98.3.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under the
Mandatory Greenhouse Gas Reporting
Program on behalf of the owners and
operators that are subject to the
requirements of 40 CFR 98.3 and that
each such owner and operator shall be
fully bound by my representations,
actions, inactions, or submissions.’’
(iii) ‘‘I certify that the owners and
operators that are subject to the
requirements of 40 CFR 98.3 shall be
bound by any order issued to me by the
Administrator or a court regarding the
source or unit.’’
(iv) ‘‘Where there are multiple holders
of a legal or equitable title to, or a
leasehold interest in, a facility (or
supply operation as appropriate) that is
subject to the requirements of 40 CFR
98.3, I certify that I have given a written
notice of my selection as the ‘designated
representative’ or ‘alternate designated
representative’, as applicable, and of the
agreement by which I was selected to
E:\FR\FM\10APP2.SGM
10APP2
16616
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
each owner and operator that is subject
to the requirements of 40 CFR 98.3.’’
(5) The signature of the designated
representative and any alternate
designated representative and the dates
signed.
(j) Documents of Agreement. Unless
otherwise required by the
Administrator, documents of agreement
referred to in the certificate of
representation shall not be submitted to
the Administrator. The Administrator
shall not be under any obligation to
review or evaluate the sufficiency of
such documents, if submitted.
(k) Binding nature of the certificate of
representation. Once a complete
certificate of representation under this
section has been submitted and
received, the Administrator will rely on
the certificate of representation unless
and until a superseding complete
certificate of representation under this
section is received by the Administrator.
(l) Objections concerning a designated
representative. (1) Except as provided in
paragraph (g) of this section, no
objection or other communication
submitted to the Administrator
concerning the authorization, or any
representation, action, inaction, or
submission, of the designated
representative or alternate designated
representative shall affect any
representation, action, inaction, or
submission of the designated
representative or alternate designated
representative, or the finality of any
decision or order by the Administrator
under the Mandatory Greenhouse Gas
Reporting Program.
(2) The Administrator will not
adjudicate any private legal dispute
concerning the authorization or any
representation, action, inaction, or
submission of any designated
representative or alternate designated
representative.
§ 98.5
How do I submit my report?
Each GHG emissions report for a
facility or supplier must be submitted
electronically on behalf of the owners
and operators of that facility or supplier
by their designated representative, in a
format specified by the Administrator.
§ 98.6 What definitions do I need to
understand?
All terms used in this part shall have
the same meaning given in the Clean Air
Act and in this section.
Abandoned (closed) mines mean
mines that are no longer operational
(per MSHA definition).
Absorbent circulation pump means a
pump commonly powered by natural
gas pressure that circulates the
absorbent liquid between the absorbent
regenerator and natural gas contactor.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Accuracy of a measurement at a
specified level (e.g., one percent of full
scale) means that the mean of repeat
measurements made by a device or
technique has a 95 percent chance of
falling within the range bounded by the
true value plus or minus the specified
level.
Acid gas means hydrogen sulfide
(H2S) and carbon dioxide (CO2)
contaminants that are separated from
sour natural gas by an acid gas removal
process.
Acid gas removal unit (AGR) means a
process unit that separates hydrogen
sulfide and/or carbon dioxide from sour
natural gas using liquid or solid
absorbents, such as liquid absorbents,
solid adsorbents, or membrane
separators.
Acid gas removal vent stack fugitive
emissions mean the acid gas (typically
CO2 and H2S) separated from the acid
gas absorbing medium (most commonly
an amine solution) and released with
methane and other light hydrocarbons
to the atmosphere or a flare.
Acid Rain Program means the
program established under title IV of the
Clean Air Act, and implemented under
parts 72 through 78 of this chapter for
the reduction of sulfur dioxide and
nitrogen oxides emissions.
Actual conditions mean temperature,
pressure and volume at measurement
conditions of natural gas.
Actuation means, for the purposes of
this rule, an event in which a natural
gas pneumatically driven valve is
opened and/or closed by release of
natural gas pressure to the atmosphere.
Administrator means the
Administrator of the United States
Environmental Protection Agency or the
Administrator’s authorized
representative.
AGA means the American Gas
Association
Air injected flare means a flare in
which air is blown into the base of a
flare stack to induce complete
combustion of low Btu natural gas (i.e.,
high non-combustible component
content).
Alkali bypass means a duct between
the feed end of the kiln and the
preheater tower through which a
portion of the kiln exit gas stream is
withdrawn and quickly cooled by air or
water to avoid excessive buildup of
alkali, chloride and/or sulfur on the raw
feed. This may also be referred to as the
‘‘kiln exhaust gas bypass.’’
Anaerobic digester means the
equipment designed and operated for
waste stabilization by the microbial
reduction of complex organic
compounds to CO2 and CH4, which is
captured and flared or used as a fuel.
PO 00000
Frm 00170
Fmt 4701
Sfmt 4702
Anode effect is a process upset
condition of an aluminum electrolysis
cell caused by too little alumina
dissolved in the electrolyte. The anode
effect begins when the voltage rises
rapidly and exceeds a threshold voltage,
typically 8 volts.
Anode Effect Minutes Per Cell Day (24
hours) are the total minutes during
which an electrolysis cell voltage is
above the threshold voltage, typically 8
volts.
ANSI means the American National
Standards Institute.
Anti-static wrap means wrap used to
assist the process of ensuring that all
fugitive emissions from a single source
are captured and directed to a
measurement instrument.
API means the American Petroleum
Institute.
Argon-oxygen decarburization (AOD)
vessel means any closed-bottom,
refractory-lined converter vessel with
submerged tuyeres through which
gaseous mixtures containing argon and
oxygen or nitrogen may be blown into
molten steel for further refining to
reduce the carbon content of the steel.
ASME means the American Society of
Mechanical Engineers.
ASTM means the American Society of
Testing and Materials.
B0 means the maximum CH4
producing capacity of a waste stream, kg
CH4/kg COD.
Backpressure means impeding the
natural atmospheric release of fugitive
emissions by enclosing the release with
a lower capacity sampling device and
altering natural flow.
Basic oxygen furnace means any
refractory-lined vessel in which highpurity oxygen is blown under pressure
through a bath of molten iron, scrap
metal, and fluxes to produce steel.
Biodiesel means any liquid biofuel
suitable as a diesel fuel substitute or a
diesel fuel additive or extender.
Biodiesel fuels are usually made from
agricultural oils or from animal tallow.
Biogenic CO2 means carbon dioxide
emissions generated as the result of
biomass combustion.
Biomass means non-fossilized and
biodegradable organic material
originating from plants, animals and
micro-organisms, including products,
by-products, residues and waste from
agriculture, forestry and related
industries as well as the non-fossilized
and biodegradable organic fractions of
industrial and municipal wastes,
including gases and liquids recovered
from the decomposition of nonfossilized and biodegradable organic
material.
Blast furnace means a furnace that is
located at an integrated iron and steel
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
plant and is used for the production of
molten iron from iron ore pellets and
other iron bearing materials.
Bleed rate means the rate at which
natural gas flows continuously or
intermittently from a process
measurement instrument to a valve
actuator controller where it is vented
(bleeds) to the atmosphere.
Blendstocks are naphthas used for
blending or compounding into finished
motor gasoline. These include RBOB
(reformulated gasoline for oxygenate
blending), CBOB (conventional gasoline
for oxygebate blending), and GTAB
(gasoline treated as blendstock).
Blowdown means manual or
automatic opening of valves to relieve
pressure and or release natural gas from
but not limited to process vessels,
compressors, storage vessels or
pipelines by venting natural gas to the
atmosphere or a flare. This practice is
often implemented prior to shutdown or
maintenance.
Blowdown vent stack fugitive
emissions mean natural gas released due
to maintenance and/or blowdown
operations including but not limited to
compressor blowdown and Emergency
Shut-Down system testing.
Boil-off gas means natural gas that
vaporizes from liquefied natural gas in
storage tanks.
British Thermal Unit or Btu means the
quantity of heat required to raise the
temperature of one pound of water by
one degree Fahrenheit at about 39.2
degrees Fahrenheit.
Bulk, with respect to industrial GHG
suppliers, means the transfer of a
product inside containers, including but
not limited to tanks, cylinders, drums,
and pressure vessels.
Butane (C4H10) or n-Butane means the
normally gaseous straight-chain or
branch-chain hydrocarbon extracted
from natural gas or refinery gas streams
and is designated in ASTM
Specification D1835 and Gas Processors
Association Specifications for
commercial butane. Not included in this
definition is isobutene, which normally
is used for feedstock.
Butylene (C2H8) is an olefinic
hydrocarbon recovered from refinery
processes and used as a feedstock.
By-product coke oven battery means a
group of ovens connected by common
walls, where coal undergoes destructive
distillation under positive pressure to
produce coke and coke oven gas from
which by-products are recovered.
By-product formation is the quantity
of fluorinated GHGs created during the
etching or chamber cleaning processes
in an electronics manufacturing process.
C2+ means the NGL fraction
consisting of hydrocarbon molecules
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
ethane and heavier. The characteristics
for this fraction, as reported in Table
MM–2, are derived from the mixture of
31 percent ethane and 29 percent
propane as reported in Table MM–1,
and 41 percent C4+. These proportions
are determined from an example API
E&PTankCalc run on 34°API crude oil
from a separator temperature of 100 °F
and pressure of 40 psig.
C4+ means the NGL fraction
consisting of hydrocarbon molecules
butane and heavier. The characteristics
for this fraction, as reported in Table
MM–2, are derived from the mixture of
39 percent ‘‘pentanes plus’’ and 61
percent butane as reported in Table
MM–1. These proportions are
determined from an example API
E&PTankCalc run on 34°API crude oil
from a separator temperature of 100 °F
and pressure of 40 psig.
C5+ is pentane plus in the specific
chemical composition that underlies the
default factors in Table MM–1.
C6+ means NGL fraction consisting of
hydrocarbon molecules hexane and
heavier. The characteristics for this
fraction, as reported in Table MM–2, are
derived from the assumption that
‘‘pentane plus’’, as reported in Table
MM–1, consists of a mixture of 53
percent C6+ and 47 percent pentane.
These proportions are determined from
an example API E&PTankCalc run on
34°API crude oil from a separator
temperature of 100 °F and pressure of 40
psig.
Calibrated bag means a flexible, nonelastic bag of a calibrated volume that
can be quickly affixed to a fugitive
emitting source such that the fugitive
emissions inflate the bag to its
calibrated volume.
Carbon black oil means a heavy
aromatic oil that may be derived either
as a by-product of petroleum refining or
metallurgical coke production. Carbon
black oil consists mainly of unsaturated
hydrocarbons, predominately higher
than C14.
Carbon dioxide equivalent or CO2e
means the number of metric tons of CO2
emissions with the same global warming
potential as one metric ton of another
primary greenhouse gas.
Carbon dioxide production well
means any hole drilled in the earth to
extract a carbon dioxide stream from a
geologic formation or group of
formations which contain deposits of
carbon dioxide.
Carbon dioxide production well
facility means one or more carbon
dioxide production wells that are
located on one or more contiguous or
adjacent properties, which are under the
control of the same entity. Carbon
dioxide production wells located on
PO 00000
Frm 00171
Fmt 4701
Sfmt 4702
16617
different oil and gas leases, mineral fee
tracts, lease tracts, subsurface or surface
unit areas, surface fee tracts, surface
lease tracts, or separate surface sites,
whether or not connected by a road,
waterway, power line, or pipeline, shall
be considered part of the same CO2
production well facility.
Carbon dioxide stream means carbon
dioxide that has been captured from an
emission source (e.g., a power plant or
other industrial facility) or extracted
from a carbon dioxide production well
plus incidental associated substances
either derived from the source materials
and the capture process or extracted
with the carbon dioxide.
Carbon share means the weight
percentage of carbon in any product.
Carbonate means compounds
containing the radical CO3¥2. Upon
calcination, the carbonate radical
decomposes to evolve carbon dioxide
(CO2). Common carbonates consumed in
the mineral industry include calcium
carbonate (CaCO3) or calcite;
magnesium carbonate (MgCO3) or
magnesite; and calcium-magnesium
carbonate (CaMg(CO3)2) or dolomite.
Carbonate-based mineral means any
of the following minerals used in the
manufacture of glass: calcium carbonate
(CaCO3), calcium magnesium carbonate
(CaMg(CO3)2), and sodium carbonate
(Na2CO3).
Carbonate-based mineral mass
fraction means the following: for
limestone, the mass fraction of CaCO3 in
the limestone; for dolomite, the mass
fraction of CaMg(CO3)2 in the dolomite;
and for soda ash, the mass fraction of
Na2CO3 in the soda ash.
Carbonate-based raw material means
any of the following materials used in
the manufacture of glass: limestone,
dolomite, and soda ash.
Carrier gas means the gas with which
cover gas is mixed to transport and
dilute the cover gas thus maximizing its
efficient use. Carrier gases typically
include CO2, N2, and/or dry air.
Catalytic cracking unit means a
refinery process unit in which
petroleum derivatives are continuously
charged and hydrocarbon molecules in
the presence of a catalyst are fractured
into smaller molecules, or react with a
contact material suspended in a
fluidized bed to improve feedstock
quality for additional processing and the
catalyst or contact material is
continuously regenerated by burning off
coke and other deposits. Catalytic
cracking units include both fluidized
bed systems, which are referred to as
fluid catalytic cracking units (FCCU),
and moving bed systems, which are also
referred to as thermal catalytic cracking
units. The unit includes the riser,
E:\FR\FM\10APP2.SGM
10APP2
16618
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
reactor, regenerator, air blowers, spent
catalyst or contact material stripper,
catalyst or contact material recovery
equipment, and regenerator equipment
for controlling air pollutant emissions
and for heat recovery.
Cattle and swine deep bedding means
as manure accumulates, bedding is
continually added to absorb moisture
over a production cycle and possibly for
as long as 6 to 12 months. This manure
management system also is known as a
bedded pack manure management
system and may be combined with a dry
lot or pasture.
CBOB or conventional gasoline for
oxygenate blending means a petroleum
product which, when blended with a
specified type and percentage of
oxygenate, meets the definition of
conventional gasoline.
Centrifugal compressor means any
equipment that increases the pressure of
a process natural gas by centrifugal
action, employing rotating movement of
the driven shaft.
Centrifugal compressor dry seals
mean a series of rings that are located
around the compressor shaft where it
exits the compressor case and that
operate mechanically under the
opposing forces to prevent natural gas
from escaping to the atmosphere.
Centrifugal compressor dry seals
fugitive emissions mean natural gas
released from a dry seal vent pipe and/
or the seal face around the rotating shaft
where it exits one or both ends of the
compressor case.
Centrifugal compressor wet seals
mean a series of rings around the
compressor shaft where it exits the
compressor case, that use oil circulated
under high pressure between the rings
to prevent natural gas from escaping to
the atmosphere.
Centrifugal compressor wet seals
fugitive emissions mean natural gas
released from the seal face around the
rotating shaft where it exits one or both
ends of the compressor case PLUS the
natural gas absorbed in the circulating
seal oil and vented to the atmosphere
from a seal oil degassing vessel or sump
before the oil is re-circulated, or from a
seal oil containment vessel vent.
Certified standards means calibration
gases certified by the manufacturer of
the calibration gases to be accurate to
within 2 percent of the value on the
label or calibration gases.
CH4 means methane.
Chemical recovery combustion unit
means a combustion device, such as a
recovery furnace or fluidized-bed
reactor where spent pulping liquor from
sulfite or semi-chemical pulping
processes is burned to recover pulping
chemicals.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Chemical recovery furnace means an
enclosed combustion device where
concentrated spent liquor produced by
the kraft or soda pulping process is
burned to recover pulping chemicals
and produce steam. Includes any
recovery furnace that burns spent
pulping liquor produced from both the
kraft and soda pulping processes.
Chloride process means a production
process where titanium dioxide is
produced using calcined petroleum
coke and chlorine as raw materials.
Close-range means, for the purposes
of this rule, safely accessible within the
operator’s arm’s reach from the ground
or stationary platforms.
CO2 means carbon dioxide.
Coal means all solid fuels classified as
anthracite, bituminous, sub-bituminous,
or lignite by the American Society for
Testing and Materials Designation
ASTM D388–05 ‘‘Standard
Classification of Coals by Rank’’ (as
incorporated by reference in § 98.7).
COD means the chemical oxygen
demand as determined using methods
specified pursuant to 40 CFR Part 136.
Coke (petroleum) means a solid
residue consisting mainly of carbon
which results from the cracking of
petroleum hydrocarbons in processes
such as coking and fluid coking. This
includes catalyst coke deposited on a
catalyst during the refining process
which must be burned off in order to
regenerate the catalyst.
Coke burn-off means the coke
removed from the surface of a catalyst
by combustion during catalyst
regeneration. Coke burn-off also means
the coke combusted in fluid coking unit
burner.
Cokemaking means the production of
coke from coal in either a by-product
coke oven battery or a non-recovery
coke oven battery.
Cold and steady emissions mean a
nearly constant and steady emissions
stream that is low enough in
temperature (i.e., less than 140 degrees
Fahrenheit) to be safely directly
measured by a person.
Commercial Applications means any
use including but not limited to: Food
and beverage, industrial and municipal
water/wastewater treatment, metal
fabrication, including welding and
cutting, greenhouse uses for plant
growth, fumigants (e.g., grain storage)
and herbicides, pulp and paper,
cleaning and solvent use, fire fighting,
transportation and storage of explosives,
enhanced oil and natural gas recovery,
long-term storage (sequestration), or
research and development.
Completely destroyed means
destroyed with a destruction efficiency
of 99.99 percent or greater.
PO 00000
Frm 00172
Fmt 4701
Sfmt 4702
Completely recaptured means 99.99
percent or greater of each GHG is
removed from a process stream.
Component, for the purposes of
subpart W only, means but is not
limited to each metal to metal joint or
seal of non-welded connection
separated by a compression gasket,
screwed thread (with or without thread
sealing compound), metal to metal
compression, or fluid barrier through
which natural gas or liquid can escape
to the atmosphere.
Compressor means any machine for
raising the pressure of a natural gas by
drawing in low pressure natural gas and
discharging significantly higher
pressure natural gas (i.e., compression
ratio higher than 1.5).
Compressor fugitive emissions mean
natural gas emissions from all
components in close physical proximity
to compressors where mechanical and
thermal cycles may cause elevated
emission rates, including but not
limited to open-ended blowdown vent
stacks, piping and tubing connectors
and flanges, pressure relief valves,
pneumatic starter open-ended lines,
instrument connections, cylinder valve
covers, and fuel valves.
Condensate means hydrocarbon and
other liquid separated from natural gas
that condenses due to changes in the
temperature, pressure, or both, and
remains liquid at storage conditions,
includes both water and hydrocarbon
liquids.
Connector means but is not limited to
flanged, screwed, or other joined fittings
used to connect pipe line segments,
tubing, pipe components (such as
elbows, reducers, ‘‘T’s’’ or valves) or a
pipe line and a piece of equipment or
an instrument to a pipe, tube or piece
of equipment. A common connector is
a flange. Joined fittings welded
completely around the circumference of
the interface are not considered
connectors for the purpose of this
regulation.
Container glass means glass made of
soda-lime recipe, clear or colored,
which is pressed and/or blown into
bottles, jars, ampoules, and other
products listed in North American
Industry Classification System 327213
(NAICS 327213).
Continuous emission monitoring
system or CEMS means the total
equipment required to sample, analyze,
measure, and provide, by means of
readings recorded at least once every 15
minutes, a permanent record of gas
concentrations, pollutant emission rates,
or gas volumetric flow rates from
stationary sources.
Continuous glass melting furnace
means a glass melting furnace that
E:\FR\FM\10APP2.SGM
10APP2
operates continuously except during
periods of maintenance, malfunction,
control device installation,
reconstruction, or rebuilding.
Control method means any equipment
used for recovering and/or oxidizing air
emissions of methane. Such equipment
includes, but is not limited to, vapor
recovery systems, absorbers, carbon
dioxide adsorbers, condensers,
incinerators, flares, catalytic oxidizers,
boilers, and process heaters.
Conventional gasoline means any
gasoline which has not been certified
under § 80.40.
Cover gas means SF6, HFC–134a,
fluorinated ketone (FK 5–1–12) or other
gas used to protect the surface of molten
magnesium from rapid oxidation and
burning in the presence of air. The
molten magnesium may be the surface
of a casting or ingot production
operation or the surface of a crucible of
molten magnesium that is the source of
the casting operation.
Crude oil means any of the naturally
occurring liquids and semi-solids found
in rock formations composed of
complex mixtures of hydrocarbons
ranging from one to hundreds of carbon
atoms in straight and branched chains
and rings.
Daily spread means manure is
routinely removed from a confinement
facility and is applied to cropland or
pasture within 24 hours of excretion.
Degasification systems mean wells
drilled from the surface or boreholes
drilled inside the mine that remove
large volumes of CH4 before, during, or
after mining. Pre-mining degasification
systems refer to drainage wells drilled
through a coal seam or seams and cased
to pre-drain the methane prior to
mining. The wells are normally placed
in operation 2 to 7 years ahead of
mining. Degasification systems also
include ‘‘gob wells’’ which recover
methane from the longwall face area
during and after mining.
Degradable organic carbon (DOC)
means the fraction of the total mass of
a waste material that can be biologically
degraded.
Dehydrator means, for the purposes of
this rule, a device in which a liquid
absorbent (including but not limited to
desiccant, ethylene glycol, diethylene
glycol, or triethylene glycol) directly
contacts a natural gas stream to absorb
water vapor.
Dehydrator vent stack fugitive
emissions means natural gas released
from a natural gas dehydrator system
absorbent (typically glycol) reboiler or
regenerator, including stripping natural
gas and motive natural gas used in
absorbent circulation pumps.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Delayed coking unit means one or
more refinery process units in which
high molecular weight petroleum
derivatives are thermally cracked and
petroleum coke is produced in a series
of closed, batch system reactors.
De-methanizer means the natural gas
processing unit that separates methane
rich residue gas from the heavier
hydrocarbons (ethane, propane, butane,
pentane-plus) in feed natural gas stream.
Density means the mass contained in
a given unit volume (mass/volume).
Destruction means, with respect to
underground coal mines, the
combustion of methane in any on-site or
off-site combustion technology.
Destroyed methane includes, but is not
limited to, methane combusted by
flaring, methane destroyed by thermal
oxidation, methane combusted for use
in on-site energy or heat production
technologies, methane that is conveyed
through pipelines (including natural gas
pipelines) for off-site combustion, and
methane that is collected for any other
on-site or off-site use as a fuel.
Destruction means, with respect to
fluorinated GHGs, the expiration of a
fluorinated GHG to the destruction
efficiency actually achieved. Such
destruction does not result in a
commercially useful end product.
Destruction Efficiency means the
efficiency with which a destruction
device reduces the GWP-weighted mass
of greenhouse gases fed into the device,
considering the GWP-weighted masses
of both the greenhouse gases fed into the
device and those exhausted from the
device. The Destruction Efficiency is
expressed in the following Equation A–
2:
DE = 1 −
tCO2 eOUT
tCO2 eIN
(Eq. A-2)
Where:
DE = Destruction Efficiency
tCO2eIN = The GWP-weighted mass of GHGs
fed into the destruction device
tCO2eOUT = The GWP-weighted mass of
GHGs exhausted from the destruction
device, including GHGs formed during
the destruction process
Destruction efficiency, or flaring
destruction efficiency, refers to the
fraction of the gas that leaves the flare
partially or fully oxidized
Destruction or removal efficiency
(DRE) is the efficiency of a control
device to destroy or remove F–GHG and
N2O. The DRE is equal to one minus the
ratio of the mass of all relevant GHG
exiting the emission control device to
the mass of GHG entering the emission
control device.
PO 00000
Frm 00173
Fmt 4701
Sfmt 4702
16619
Diesel fuel means a low sulfur fuel oil
of grades 1BD or 2BD, as defined by the
American Society for Testing and
Materials standard ASTM D975–91,
‘‘Standard Specification for Diesel Fuel
Oils’’ (as incorporated by reference in
§ 98.7), grades 1–GT or 2–GT, as defined
by ASTM D2880–90a, ‘‘Standard
Specification for Gas Turbine Fuel Oils’’
(as incorporated by reference in § 98.7),
or fuel oil numbers 1 or 2, as defined by
ASTM D396–90a, ‘‘Standard
Specification for Fuel Oils’’ (as
incorporated by reference in § 98.7).
Diesel fuel No. 1 has a distillation
temperature of 550 °F at the 90 percent
recovery point and conforms to ASTM
D975–08 (2007) Standard Specification
for Diesel Fuel Oils. It is used in high
speed diesel engines such as city buses.
Compared to fuel oil No. 1 it has a
higher octane number, a lower sulfur
content, and a higher flash point. It is
blended with diesel No. 2 in the colder
regions of the country to facility cold
starts.
Diesel fuel No. 2 has a distillation
temperature of 500 °F at the 10 percent
recovery point and 640 °F at the 90
percent recovery point and is defined in
ASTM D975. It is used in high speed
diesel engines, such as locomotives,
trucks and automobiles. Currently, there
are three categories of diesel fuel No. 2
defined by sulfur content: High sulfur
(>0.05%/wgt), low sulfur (<0.05%/wgt),
and ultra low sulfur (<0.0015%/wgt).
Ultra low sulfur is used for on road
vehicles.
Diesel fuel No. 4, made by blending
diesel fuel and residual fuel and
conforming to ASTM D975, is used for
low and medium speed diesel engines.
Digesters are systems where animal
excreta are collected and anaerobically
digested in a large containment vessel or
covered lagoon. Digesters are designed
and operated for waste stabilization by
the microbial reduction of complex
organic compounds to CO2 and CH4,
which is captured and may be flared or
used as fuel. There are multiple types of
anaerobic digestion systems, including
covered lagoon, complete mix, plug
flow, and fixed film digesters.
Direct liquefaction means the
conversion of coal directly into liquids,
rather than passing through an
intermediate gaseous state.
Direct reduction furnace means a high
temperature furnace typically fired with
natural gas to produce solid iron from
iron ore or iron ore pellets and coke,
coal, or other carbonaceous materials.
Distillate fuel oil means a
classification for one of the petroleum
fractions produced in conventional
distillation operations and from crackers
and hydrotreating process units. The
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.001</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
16620
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
generic term distillate fuel oil includes
both diesel fuels (Diesel Fuels No. 1, No.
2, and No. 4) and fuel oils (Fuel oil No.
1, No. 2, and No. 4). Fuel oils are used
primarily for space heating, in industrial
and commercial boilers and furnaces
and for electric power generation. Diesel
fuels are used in on-highway vehicles as
well as in off highway engines, such as
locomotives, marine engines,
agricultural and construction
equipment.
DOCf means the fraction of DOC that
actually decomposes under the
(presumably anaerobic) conditions
within the landfill.
Dry lot means a paved or unpaved
open confinement area without any
significant vegetative cover where
accumulating manure may be removed
periodically.
Electric arc furnace (EAF) means a
furnace that produces molten alloy
metal and heats the charge materials
with electric arcs from carbon
electrodes.
Electric arc furnace steelmaking
means the production of carbon, alloy,
or specialty steels using an EAF. This
definition excludes EAFs at steel
foundries and EAFs used to produce
nonferrous metals.
Electrical equipment means any item
used for the generation, conversion,
transmission, distribution or utilization
of electric energy, such as machines,
transformers, apparatus, measuring
instruments, or protective devices, that
contains sulfur hexafluoride (SF6) or
perfluorocarbons (PFCs) (including but
not limited to gas-insulated switchgear
substations (GIS), gas circuit breakers
(GCB), and power transformers).
Electricity generating unit or EGU
means any unit that combusts solid,
liquid, or gaseous fuel and is physically
connected to a generator to produce
electricity.
Electrothermic furnace means a
furnace that heats the charged materials
with electric arcs from carbon
electrodes.
Emergency generator means a
stationary internal combustion engine
that serves solely as a secondary source
of mechanical or electrical power
whenever the primary energy supply is
disrupted or discontinued during power
outages or natural disasters that are
beyond the control of the owner or
operator of a facility. Emergency engines
operate only during emergency
situations or for standard performance
testing procedures as required by law or
by the engine manufacturer. The hours
of operation per calendar year for such
standard performance testing shall not
exceed 100 hours. An engine that serves
as a back-up power source under
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
conditions of load shedding, peak
shaving, power interruptions pursuant
to an interruptible power service
agreement, or scheduled facility
maintenance shall not be considered an
emergency engine.
Engineering estimation means an
estimate of fugitive emissions based on
engineering principles applied to
measured and/or approximated physical
parameters such as dimensions of
containment, actual pressures, actual
temperatures, and compositions.
Equipment means but is not limited to
each pump, compressor, pipe, pressure
relief device, sampling connection
system, open-ended valve or line, valve,
connector, surge control vessel, tank,
vessel, and instrumentation system in
natural gas or liquid service; and any
control devices or systems referenced by
this subpart.
Equipment chambers means the total
natural gas-containing volume within
any equipment and between the
equipment isolation valves.
Ethane (C2H6) is a colorless paraffinic
gas that boils at temperatures of
¥127.48 °F. It is extracted from natural
gas and from refinery gas streams.
Ethane is a major feedstock for the
petrochemical industry.
Ethylene (C2H4) is an olefinic
hydrocarbon received from refinery
processes or petrochemical processes.
Ethylene is used as a petrochemical
feedstock for numerous chemical
applications and the production of
consumer goods.
Ex refinery gate means the point at
which a refined or semi-refined product
leaves the refinery.
Experimental furnace means a glass
melting furnace with the sole purpose of
operating to evaluate glass melting
processes, technologies, or glass
products. An experimental furnace does
not produce glass that is sold (except for
further research and development
purposes) or that is used as a raw
material for non-experimental furnaces.
Export means to transport a product
from inside the United States to persons
outside the United States, excluding
United States military bases and ships
for on-board use.
Exporter means any person, company,
or organization of record that contracts
to transfer a product from the United
States to another country or that
transfers products to an affiliate in
another country, excluding transfers to
United States military bases and ships
for on-board use.
Extracted means production of carbon
dioxide from carbon dioxide production
wells.
Facility means any physical property,
plant, building, structure, source, or
PO 00000
Frm 00174
Fmt 4701
Sfmt 4702
stationary equipment located on one or
more contiguous or adjacent properties
in actual physical contact or separated
solely by a public roadway or other
public right-of-way and under common
ownership or common control, that
emits or may emit any greenhouse gas.
Operators of military installations may
classify such installations as more than
a single facility based on distinct and
independent functional groupings
within contiguous military properties.
Feed means the prepared and mixed
materials, which include but are not
limited to materials such as limestone,
clay, shale, sand, iron ore, mill scale,
cement kiln dust and flyash, that are fed
to the kiln. Feed does not include the
fuels used in the kiln to produce heat to
form the clinker product.
Feedstock means raw material inputs
to a process that are transformed by
reaction, oxidation, or other chemical or
physical methods into products and byproducts. Supplemental fuel burned to
provide heat or thermal energy is not a
feedstock.
Finished aviation gasoline means a
complex mixture of volatile
hydrocarbons, with or without
additives, suitably blended to be used in
aviation reciprocating engines.
Specifications can be found in ASTM
Specification D910–07a (2002) and
Military Specification MIL–G–5572.
Finished motor gasoline means a
complex mixture of volatile
hydrocarbons, with or without
additives, suitably blended to be used in
spark ignition engines. Motor gasoline,
defined in ASTM Specifications D4814–
08a (2001) or Federal Specification VV–
G–1690C, has a boiling range of 122 ° to
158 °F at the 10 percent recovery point
to 365 ° to 374 °F at the 90 percent
recovery rate. Motor gasoline includes,
conventional gasoline, reformulated
gasoline, and all types of oxygenated
gasoline. Gasoline also has seasonal
variations in an effort to control ozone
levels. This is achieved by lowering the
Reid Vapor Pressure (RVP) of gasoline
during the summer driving season.
Depending on the region of the country
the RVP is lowered to below 9.0 psi or
7.8 psi. The RVP may be further lowered
by state regulations.
Fischer-Tropsch process means a
catalyzed chemical reaction in which
synthesis gas, a mixture of carbon
monoxide and hydrogen, is converted
into liquid hydrocarbons of various
forms.
Flare means a combustion device,
whether at ground level or elevated, that
uses an open flame to burn combustible
gases with combustion air provided by
uncontrolled ambient air around the
flame.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Flare combustion efficiency means the
fraction of natural gas, on a volume or
mole basis, that is combusted at the flare
burner tip, assumed 95 percent for nonaspirated field flares and 98 percent for
steam or air asperated flares.
Flare stack means a device used to
provide a safe means of combustible
natural gas disposal from routine
operations, upsets, or emergencies via
combustion of the natural gas in an
open, normally elevated flame.
Flare stack fugitive emissions means
the CH4 and CO2 content of that portion
of natural gas (typically 5 percent in
non-aspirated field flares and 2 percent
in steam or air asperated flares) that
passes through flares un-combusted and
the total CO2 emissions of that portion
of the natural gas that is combusted.
Flat glass means glass made of sodalime recipe and produced into
continuous flat sheets and other
products listed in NAICS 327211.
Fluid coking unit means one or more
refinery process units in which high
molecular weight petroleum derivatives
are thermally cracked and petroleum
coke is continuously produced in a
fluidized bed system. The fluid coking
unit includes equipment for controlling
air pollutant emissions and for heat
recovery on the fluid coking burner
exhaust vent. There are two basic types
of fluid coking units: a traditional fluid
coking unit in which only a small
portion of the coke produced in the unit
is burned to fuel the unit and the fluid
coking burner exhaust vent is directed
to the atmosphere (after processing in a
CO boiler or other air pollutant control
equipment) and a flexicoking unit in
which an auxiliary burner is used to
partially combust a significant portion
of the produced petroleum coke to
generate a low value fuel gas that is
used as fuel in other combustion
sources at the refinery.
Fluorinated greenhouse gas means
sulfur hexafluoride (SF6), nitrogen
trifluoride (NF3), and any fluorocarbon
except for controlled substances as
defined at 40 CFR Part 82 Subpart A. In
addition to SF6 and NF3, ‘‘fluorinated
GHG’’ includes but is not limited to any
hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated
linear, branched or cyclic alkane, ether,
tertiary amine or aminoether, any
perfluoropolyether, and any
hydrofluoropolyether.
Fossil fuel means natural gas,
petroleum, coal, or any form of solid,
liquid, or gaseous fuel derived from
such material for purpose of creating
useful heat.
Fuel means solid, liquid or gaseous
combustible material.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Fuel ethanol (C2H5OH) is an
anhydrous alcohol made either
chemically from ethylene or biologically
from the fermentation of sugars from
carbohydrates found in agricultural
products. It is used as a gasoline octane
enhancer and as an oxygenate
blendstock.
Fuel gas (still gas) means gas
generated at a petroleum refinery,
petrochemical plant, or similar
industrial process unit, and that is
combusted separately or in any
combination with any type of gas.
Fuel gas system means a system of
compressors, piping, knock-out pots,
mix drums, and, if necessary, units used
to remove sulfur contaminants from the
fuel gas (e.g., amine scrubbers) that
collects fuel gas from one or more
sources for treatment, as necessary, and
transport to a stationary combustion
unit. A fuel gas system may have an
overpressure vent to a flare but the
primary purpose for a fuel gas system is
to provide fuel to the various
combustion units at the refinery or
petrochemical plant.
Fuel oil No. 1 has a distillation
temperature of 400 °F at the 10 percent
recovery point and 550 °F at the 90
percent recovery point and is used
primarily as fuel for portable outdoor
stoves and heaters. It is defined in
ASTM D396–08 (2007) Standard
Specification for Fuel Oils.
Fuel oil No. 2 has a distillation
temperature of 400 °F at the 10 percent
recovery point and 640 °F at the 90
percent recovery point and is defined in
ASTM D396. It is used primarily for
residential heating and for moderate
capacity commercial and industrial
burner units.
Fuel oil No. 4 is a distillate fuel oil
made by blending distillate fuel oil and
residual fuel oil and conforms to ASTM
D396 or Federal Specification VV–F–
815C. and is used extensively in
industrial plants and commercial burner
installations that are not equipped with
preheating facilities.
Fugitive emissions means
unintentional equipment emissions of
methane and/or carbon dioxide
containing natural gas or hydrocarbon
gas (not including combustion flue gas)
from emissions sources including, but
not limited to, open ended lines,
equipment connections or seals to the
atmosphere. Fugitive emissions also
mean CO2 emissions resulting from
combustion of natural gas in flares.
Fugitive emissions detection means
the process of identifying emissions
from equipment, components, and other
point sources.
Fugitive emissions detection
instruments mean any device or
PO 00000
Frm 00175
Fmt 4701
Sfmt 4702
16621
instrument that has been approved for
fugitive emissions detection in this rule,
namely infrared fugitive emissions
detection instruments, OVAs, and
TVAs.
Gas collection system or landfill gas
collection system means a system of
pipes used to collect landfill gas from
different locations in the landfill to a
single location for treatment (thermal
destruction) or use. Landfill gas
collection systems may also include
knock-out or separator drums and/or a
compressor.
Gas conditions mean the actual
temperature, volume, and pressure of a
gas sample.
Gas-fired unit means a stationary
combustion unit that derives more than
50 percent of its annual heat input from
the combustion of gaseous fuels, and the
remainder of its annual heat input from
the combustion of fuel oil or other
liquid fuels.
Gas monitor means an instrument that
continuously measures the
concentration of a particular gaseous
species in the effluent of a stationary
source.
Gas utilization is the quantity of GHG
gas consumed (and therefore not
available for emission) during the
etching and/or chamber cleaning
processes.
Gaseous fuel means a material that is
in the gaseous state at standard
atmospheric temperature and pressure
conditions and that is combusted to
produce heat and/or energy.
Gasification means the conversion of
a solid material into a gas.
Gathering and boosting station means
a station used to gather natural gas from
well or field pipelines for delivery to a
natural gas processing facility or central
point. Stations may also provide
compression, dehydration, and/or
treating services.
Glass melting furnace means a unit
comprising a refractory-lined vessel in
which raw materials are charged and
melted at high temperature to produce
molten glass.
Global warming potential or GWP
means the ratio of the time-integrated
radiative forcing from the instantaneous
release of one kilogram (kg) of a trace
substance relative to that of one kg of a
reference gas, i.e., CO2.
GPA means the Gas Processors
Association.
Greenhouse gas or GHG means carbon
dioxide (CO2), methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs),
chlorofluorocarbons (CFCs),
perfluorocarbons (PFCs), and other
fluorinated greenhouse gases as defined
in this section.
E:\FR\FM\10APP2.SGM
10APP2
16622
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Heat Transfer Fluids are F–GHGs that
are liquid at room temperature, have
appreciable vapor pressures, and are
used for temperature control during
certain processes in electronic
manufacturing. Heat transfer fluids used
in the electronics sector include
perfluoropolyethers, perfluoroalkanes,
perfluoroethers, tertiary
perfluoroamines, and perfluorocyclic
ethers.
Heel means the amount of gas that
remains in a shipping container after it
is discharged or off-loaded (that is no
more than ten percent of the volume of
the container).
High heat value or HHV means the
high or gross heat content of the fuel
with the heat of vaporization included.
The water is assumed to be in a liquid
state.
High volume sampler means an
atmospheric emissions measurement
device that captures emissions from a
source in a calibrated air intake and
uses dual hydrocarbon sensors and
other devices to measure the flow rate
and combustible hydrocarbon
concentrations of the fugitive emission
such that the quantity of emissions is
determined.
Hydrofluorocarbons or HFCs means a
class of GHGs primarily used as
refrigerants, consisting of hydrogen,
fluorine, and carbon.
Import means, with respect to
fluorinated GHGs and nitrous oxide, to
land on, bring into, or introduce into,
any place subject to the jurisdiction of
the United States whether or not such
landing, bringing, or introduction
constitutes an importation within the
meaning of the customs laws of the
United States, with the following
exemptions:
(1) Off-loading used or excess
fluorinated GHGs or nitrous oxide of
U.S. origin from a ship during servicing,
(2) Bringing fluorinated GHGs or
nitrous oxide into the U.S. from Mexico
where the fluorinated GHGs or nitrous
oxide had been admitted into Mexico in
bond and were of U.S. origin, and
(3) Bringing fluorinated GHGs or
nitrous oxide into the U.S. when
transported in a consignment of
personal or household effects or in a
similar non-commercial situation
normally exempted from U.S. Customs
attention.
Importer means any person, company,
or organization of record that for any
reason brings a product into the United
States from a foreign country. An
importer includes the person, company,
or organization primarily liable for the
payment of any duties on the
merchandise or an authorized agent
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
acting on their behalf. The term also
includes, as appropriate:
(1) The consignee.
(2) The importer of record.
(3) The actual owner.
(4) The transferee, if the right to draw
merchandise in a bonded warehouse has
been transferred.
Indurating furnace means a furnace
where unfired taconite pellets, called
green balls, are hardened at high
temperatures to produce fired pellets for
use in a blast furnace. Types of
indurating furnaces include straight gate
and grate kiln furnaces.
Infrared remote fugitive emissions
detection instrument means an
instrument that detects infrared light in
the narrow wavelength range absorbed
by light hydrocarbons including
methane, and presents a signal (sound,
digital or visual image) indicating the
presence of methane and other light
hydrocarbon vapor emissions in the
atmosphere. For the purpose of this
rule, it must detect the presence of
methane.
In-line kiln/raw mill means a system
in a portland cement production process
where a dry kiln system is integrated
with the raw mill so that all or a portion
of the kiln exhaust gases are used to
perform the drying operation of the raw
mill, with no auxiliary heat source used.
In this system the kiln is capable of
operating without the raw mill
operating, but the raw mill cannot
operate without the kiln gases, and
consequently, the raw mill does not
generate a separate exhaust gas stream.
Integrated process means a process
that produces a petrochemical as well as
one or more other chemicals that are
part of other source categories under
this part. An example of an integrated
process is the production of both
hydrogen for sale (i.e., a merchant
hydrogen facility) and methanol from
synthesis gas created by steam
reforming of methane.
Interstate pipeline means a natural gas
pipeline designated as interstate
pipelines under the Natural Gas Act, 15
U.S.C. 717a.
Intrastate pipeline means a natural
gas pipeline not subject to the
jurisdiction of the Federal Energy
Regulatory Commission as described in
15 U.S.C. 3301.
Isobutane (C4H10) is a normally
gaseous branch chain hydrocarbon
extracted from natural gas or refinery
gas streams. A colorless paraffinic gas
that boils at 10.9 °F, it is used as a
feedstock in refineries.
Kerosene-type jet fuel means a
kerosene-based product used in
commercial and military turbojet and
turboprop aircraft. The product has a
PO 00000
Frm 00176
Fmt 4701
Sfmt 4702
maximum distillation temperature of
400 °F at the 10 percent recovery point
and a final maximum boiling point of
572 °F. It meets ASTM Specification
D1655–08a (2001) and Military
Specification MIL–T–5624P and MIL–
T–83133D (JP–5 and JP–8).
Kiln means a device, including any
associated preheater or precalciner
devices, that produces clinker by
heating limestone and other materials
for subsequent production of portland
cement.
Kiln exhaust gas bypass means alkali
bypass.
Landfill means an area of land or an
excavation in which wastes are placed
for permanent disposal and that is not
a land application unit, surface
impoundment, injection well, or waste
pile as those terms are defined under
§ 257.2 of this chapter.
Landfill gas means gas produced as a
result of anaerobic decomposition of
waste materials in the landfill. Landfill
gas generally contains 40 to 60 percent
methane on a dry basis, typically less
than 1 percent non-methane organic
chemicals, and the remainder being
carbon dioxide.
Lime is the generic term for a variety
of chemical compounds that are
produced by the calcination of
limestone or dolomite. These products
include but are not limited to calcium
oxide, high-calcium quicklime, calcium
hydroxide, hydrated lime, dolomitic
quicklime, and dolomitic hydrate.
Liquefied natural gas (LNG) means
natural gas (primarily methane) that has
been liquefied by reducing its
temperature to ¥260 degrees Fahrenheit
at atmospheric pressure.
Liquefied natural gas import and
export facilities mean onshore and/or
offshore facilities that send out exported
or receive imported liquefied natural
gas, store it in storage tanks, re-gasify it,
and deliver re-gasified natural gas to
natural gas transmission or distribution
systems. The facilities include tanker
unloading equipment, liquefied natural
gas transportation pipelines, pumps,
compressors to liquefy boil-off-gas, recondensers, and vaporization units for
re-gasification of the liquefied natural
gas.
Liquefied natural gas storage facilities
means an onshore facility that stores
liquefied natural gas in above ground
storage vessels. The facility may include
equipment for liquefying natural gas,
compressors to liquefy boil-off-gas, recondensers, and vaporization units for
re-gasification of the liquefied natural
gas.
Liquid/Slurry means manure is stored
as excreted or with some minimal
addition of water to facilitate handling
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
and is stored in either tanks or earthen
ponds, usually for periods less than one
year.
LNG import and export facility
fugitive emissions mean natural gas
releases from valves, connectors, storage
tanks, flanges, open-ended lines,
pressure relief valves, boil-off-gas
recovery, send outs (pumps and
vaporizers), packing and gaskets. This
does not include fugitive emissions
from equipment and equipment
components reported elsewhere for this
rule.
LNG storage station fugitive emissions
mean natural gas releases from valves,
connectors, flanges, open-ended lines,
storage tanks, pressure relief valves,
liquefaction process units, packing and
gaskets. This does not include fugitive
emissions from equipment and
equipment components reported
elsewhere for this rule.
Lubricants include all grades of
lubricating oils, from spindle oil to
cylinder oil to those used in greases.
Petroleum lubricants may be produced
from distillates or residues.
Makeup chemicals means carbonate
chemicals (e.g., sodium and calcium
carbonates) that are added to the
chemical recovery areas of chemical
pulp mills to replace chemicals lost in
the process.
Mass-balance approach means a
method for estimating emissions of
fluorinated greenhouse gases from use
in equipment that can be applied to
aggregates of units (for example by
system). In this approach, annual
emissions are the difference between the
quantity of gas consumed in the year
and the quantity of gas used to fill the
net increase in equipment capacity or to
replace destroyed gas.
Maximum rated heat input capacity
means the hourly heat input to a unit (in
mmBtu/hr), when it combusts the
maximum amount of fuel per hour that
it is capable of combusting on a steady
state basis, as of the initial installation
of the unit, as specified by the
manufacturer.
Maximum rated input capacity means
the maximum amount of municipal
solid waste per day (in tons/day) that a
unit is capable of combusting on a
steady state basis as of the initial
installation of the unit as specified by
the manufacturer of the unit.
Mcf means thousand cubic feet.
Meter means a device that measures
gas flow rate from a fugitive emissions
source or through a conduit by detecting
a condition (pressure drop, spin
induction, temperature loss, electronic
signal) that varies in proportion to flow
rate or measures gas velocity in a
manner that can calculate flow rate.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Methane conversion factor means the
extent to which the CH4 producing
capacity (Bo) is realized in each type of
treatment and discharge pathway and
system. Thus, it is an indication of the
degree to which the system is anaerobic.
Methane correction factor means an
adjustment factor applied to the
methane generation rate to account for
portions of the landfill that remain
aerobic. The methane correction factor
can be considered the fraction of the
total landfill waste volume that is
ultimately disposed of in an anaerobic
state. Managed landfills that have soil or
other cover materials have a methane
correction factor of 1.
Miscellaneous products include all
petroleum products not classified
elsewhere. It includes petrolatum lube
refining by-products (aromatic extracts
and tars) absorption oils, ram-jet fuel,
petroleum rocket fuels, synthetic natural
gas feedstocks, and specialty oils.
MMBtu means million British thermal
units.
Municipal solid waste landfill or
MSW landfill means an entire disposal
facility in a contiguous geographical
space where household waste is placed
in or on land. An MSW landfill may
also receive other types of RCRA
Subtitle D wastes (§ 257.2 of this
chapter) such as commercial solid
waste, nonhazardous sludge,
conditionally exempt small quantity
generator waste, and industrial solid
waste. Portions of an MSW landfill may
be separated by access roads. An MSW
landfill may be publicly or privately
owned.
Municipal solid waste or MSW means
solid phase household, commercial/
retail, and/or institutional waste, such
as, but not limited to, yard waste and
refuse.
N2O means nitrous oxide.
NAESB is the North American Energy
Standards Board.
Nameplate capacity means the full
and proper charge of gas specified by
the equipment manufacturer to achieve
the equipment’s specified performance.
The nameplate capacity is typically
indicated on the equipment’s
nameplate; it is not necessarily the
actual charge, which may be influenced
by leakage and other emissions.
Naphtha-type jet fuel means a fuel in
the heavy naphtha boiling range having
an average gravity of 52.8 API and
meeting Military Specification MIL–T–
5624L (Grade JP–4). It is used primarily
for military turbojet and turboprop
aircraft because it has a lower freeze
point than other aviation fuels and
meets engine requirements at high
altitudes and speeds.
PO 00000
Frm 00177
Fmt 4701
Sfmt 4702
16623
Natural gas means a naturally
occurring mixture of hydrocarbon and
non-hydrocarbon gases found in
geologic formations beneath the earth’s
surface, of which its constituents
include, but are not limited to, methane,
heavier hydrocarbons and carbon
dioxide. Natural gas may be field quality
(which varies widely) or pipeline
quality. For the purposes of this subpart,
the definition of natural gas includes
similarly constituted fuels such as field
production gas, process gas, and fuel
gas.
Natural gas driven pneumatic manual
valve actuator device means valve
control devices that use pressurized
natural gas to provide the energy
required for an operator to manually
open, close, or throttle a liquid or gas
stream. Typical manual control
applications include, but are not limited
to, equipment isolation valves, tank
drain valves, pipeline valves.
Natural gas driven pneumatic manual
valve actuator device fugitive emissions
means natural gas released due to
manual actuation of natural gas
pneumatic valve actuation devices,
including, but not limited to, natural gas
diaphragm and pneumatic-hydraulic
valve actuators.
Natural gas driven pneumatic pump
means a pump that uses pressurized
natural gas to move a piston or
diaphragm, which pumps liquids on the
opposite side of the piston or
diaphragm.
Natural gas driven pneumatic pump
fugitive emissions means natural gas
released from pumps that are powered
or assisted by pressurized natural gas.
Natural gas driven pneumatic valve
bleed device means valve control
devices that use pressurized natural gas
to transmit a process measurement
signal to a valve actuator to
automatically control the valve opening.
Typical bleeding process control
applications include, but are not limited
to, pressure, temperature, liquid level,
and flow rate regulation.
Natural gas driven pneumatic valve
bleed devices fugitive emissions means
the continuous or intermittant release of
natural gas from automatic process
control loops including the natural gas
pressure signal flowing from a process
measurement instrument (e.g. liquid
level, pressure, temperature) to a
process control instrument which
activates a process control valve
actuator.
Natural gas liquids (NGL) means
those hydrocarbons in natural gas that
are separated from the gas as liquids
through the process of absorption,
condensation, adsorption, or other
methods in gas processing or cycling
E:\FR\FM\10APP2.SGM
10APP2
16624
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
plants. Generally, such liquids consist
of primarily ethane, propane, butane,
and isobutane, primarily pentanes
produced from natural gas at lease
separators and field facilities. For the
purposes of subpart NN only, natural
gas liquids does not include lease
condensate. Bulk NGLs refers to
mixtures of NGLs that are sold or
delivered as undifferentiated product
from natural gas processing plants.
Natural gas processing facilities are
engaged in the extraction of natural gas
liquids from produced natural gas;
fractionation of mixed natural gas
liquids to natural gas products; and
removal of carbon dioxide, sulfur
compounds, nitrogen, helium, water,
and other contaminants. Natural gas
processing facilities also encompass
gathering and boosting stations that
include equipment to phase-separate
natural gas liquids from natural gas,
dehydrate the natural gas, and transport
the natural gas to transmission pipelines
or to a processing facility.
Natural gas products means products
produced for consumers from natural
gas processing facilities including, but
not limited to, ethane, propane, butane,
iso-butane, and pentanes-plus.
Natural gas transmission compression
facility means any permanent
combination of compressors that move
natural gas at increased pressure from
production fields or natural gas
processing facilities, in transmission
pipelines, to natural gas distribution
pipelines, or into storage facilities. In
addition, transmission compressor
stations may include equipment for
liquids separation, natural gas
dehydration, and storage of water and
hydrocarbon liquids.
NIST means the United States
National Institute of Standards and
Technology.
Nitric acid production line means a
series of reactors and absorbers used to
produce nitric acid.
Nitrogen excreted is the nitrogen that
is excreted by livestock in manure and
urine.
Non-crude feedstocks means natural
gas liquids, hydrogen and other
hydrocarbons, and petroleum products
that are input into the atmospheric
distillation column or other processing
units in a refinery
Non-pneumatic pump means any
pump that is not pneumatically
powered with pressurized gas of any
type, such as natural gas, air, or
nitrogen.
Non-pneumatic pump fugitive
emissions means natural gas released
through connectors and flanges of
electric motor or engine driven pumps.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Non-recovery coke oven battery means
a group of ovens connected by common
walls and operated as a unit, where coal
undergoes destructive distillation under
negative pressure to produce coke, and
which is designed for the combustion of
the coke oven gas from which byproducts are not recovered.
Non-steam aspirated flare means a
flare where natural gas burns at the tip
with natural induction of air (and
relatively lower combustion efficiency
as may be evidenced by smoke
formation).
Offshore means tidal-affected borders
of the U.S. lands, both state and Federal,
adjacent to oceans, bays, lakes or other
normally standing water.
Offshore petroleum and natural gas
production facilities means any platform
structure, floating in the ocean or lake,
fixed on ocean or lake bed, or located
on artificial islands in the ocean or lake,
that houses equipment to extract
hydrocarbons from ocean floor and
transports it to storage or transport
vessels or onshore. In addition, offshore
production facilities may include
equipment for separation of liquids from
natural gas components, dehydration of
natural gas, extraction of H2S and CO2
from natural gas, crude oil and
condensate storage tanks, both on the
platform structure and floating storage
tanks connected to the platform
structure by a pipeline, and
compression or pumping of
hydrocarbons to vessels or onshore. The
facilities under consideration are
located in both State administered
waters and Mineral Management
Services administered Federal waters.
Offshore platform pipeline fugitive
emissions means natural gas above the
water line released from piping
connectors, pipe wall ruptures and
holes in natural gas and crude oil
pipeline surfaces on offshore production
facilities.
Oil/water separator means equipment
used to routinely handle oily-water
streams, including gravity separators or
ponds and air flotation systems.
Oil-fired unit means a stationary
combustion unit that derives more than
50 percent of its annual heat input from
the combustion of fuel oil, and the
remainder of its annual heat input from
the combustion of natural gas or other
gaseous fuels.
Open-ended line fugitive emissions
means natural gas released from pipes
or valves open on one end to the
atmosphere that are intended to
periodically vent or drain natural gas to
the atmosphere but may also leak
process gas or liquid through
incomplete valve closure including
valve seat obstructions or damage.
PO 00000
Frm 00178
Fmt 4701
Sfmt 4702
Open-ended valve or Lines (OELs)
means any valve, except pressure relief
valves, having one side of the valve seat
in contact with process fluid and one
side open to atmosphere, either directly
or through open piping.
Operating hours means the duration
of time in which a process or process
unit is utilized; this excludes shutdown,
maintenance, and standby.
Operating pressure means the
containment pressure that characterizes
the normal state of gas and/or liquid
inside a particular process, pipeline,
vessel or tank.
Operator means any person who
operates or supervises a facility or
supply operation.
Organic monitoring device means an
instrument used to indicate the
concentration level of organic
compounds exiting a control device
based on a detection principle such as
IR, photoionization, or thermal
conductivity.
Organic vapor analyzer (OVA) means
an organic monitoring device that uses
a flame ionization detector to measure
the concentrations in air of combustible
organic vapors from 9 to 10,000 parts
per million sucked into the probe.
Owner means any person who has
legal or equitable title to, has a
leasehold interest in, or control of a
facility or supply operation.
Oxygenated gasoline means gasoline
which contains a measurable amount of
oxygenate.
Oxygenates means substances which,
when added to gasoline increase the
oxygen content of the gasoline. Common
oxygenates are ethanol CH3-CH2OH,
Methyl Tertiary Butl Ether (CH3)3COCH3
(MTBE), Ethyl Tertial Butl Ether
(CH3)3COC2H (ETBE), Tertiary Amyl
Methyl Ether (CH3)(2C2H5) COCH3
(TAME), Diisopropyl Ether
(CH3)2CHOCH(CH3)2 (DIPE), and
Methanol CH3OH. Lawful use of any of
the substances or any combination of
these substances requires that they be
‘‘substantially similar’’ under section
211(f)(1) of the Clean Air Act.
Pasture/Range/Paddock means the
manure from pasture and range grazing
animals is allowed to lie as deposited,
and is not managed.
Pentanes plus is a mixture of
hydrocarbons, mostly pentanes and
heavier, extracted from natural gas.
Pentanes plus includes isopentane,
natural gasoline, and plant condensate.
Perfluorocarbons or PFCs means a
class of greenhouse gases consisting on
the molecular level of carbon and
fluorine.
Petrochemical means methanol,
acrylonitrile, ethylene, ethylene oxide,
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
ethylene dichloride, and any form of
carbon black.
Petrochemical feedstocks means
feedstocks derived from petroleum for
the manufacture of chemicals, synthetic
rubber, and a variety of plastics. This
category is usually divided into naphtha
less than 401 °F and other oils greater
than 401 °F.
Petroleum means oil removed from
the earth and the oil derived from tar
sands and shale.
Petroleum coke means a black solid
residue, obtained mainly by cracking
and carbonizing of petroleum derived
feedstocks, vacuum bottoms, tar and
pitches in processes such as delayed
coking or fluid coking. It consists
mainly of carbon (90 to 95 percent) and
has low ash content. It is used as a
feedstock in coke ovens for the steel
industry, for heating purposes, for
electrode manufacture and for
production of chemicals.
Petroleum product means all refined
and semi-refined products that are
produced at a refinery by processing
crude oil and other petroleum-based
feedstocks, including petroleum
products derived from co-processing
biomass and petroleum feedstock
together. Petroleum products may be
combusted for energy use, or they may
be used either for non-energy processes
or as non-energy products. The
definition of petroleum product for
importers and exporters excludes
asphalt and road oil, lubricants, waxes,
plastics, and plastics products.
Platform fugitive emissions means
natural gas released from equipment
and equipment components including
valves, pressure relief valves,
connectors, tube fittings, open-ended
lines, ports, and hatches. This does not
include fugitive emissions from
equipment and components reported
elsewhere for this rule.
Portable means designed and capable
of being carried or moved from one
location to another. Indications of
portability include but are not limited to
wheels, skids, carrying handles, dolly,
trailer, or platform. Equipment is not
portable if:
(1) The equipment is attached to a
foundation.
(2) The equipment or a replacement
resides at the same location for more
than 12 consecutive months.
(3) The equipment is located at a
seasonal facility and operates during the
full annual operating period of the
seasonal facility, remains at the facility
for at least two years, and operates at
that facility for at least three months
each year.
(4) The equipment is moved from one
location to another in an attempt to
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
circumvent the portable residence time
requirements of this definition.
Post-coal mining activities means the
storage, processing, and transport of
extracted coal.
Poultry manure with litter is similar to
cattle and swine deep bedding except
usually not combined with a dry lot or
pasture. Typically used for all poultry
breeder flocks and for the production of
meat type chickens (broiler) and other
fowl.
Poultry manure without litter systems
may manage manure in a liquid form,
similar to open pits in enclosed animal
confinement facilities. These systems
may alternatively be designed and
operated to dry manure as it
accumulates. The latter is known as a
high-rise manure management system
and is a form of passive windrow
manure composting when designed and
operated properly.
Precision of a measurement at a
specified level (e.g., one percent of full
scale) means that 95 percent of repeat
measurements made by a device or
technique fall within the range bounded
by the mean of the measurements plus
or minus the specified level.
Pressed and blown glass means glass
which is pressed, blown, or both, into
products such as light bulbs, glass fiber,
technical glass, and other products
listed in NAICS 327212.
Pressure relief device or pressure
relief valve or pressure safety valve
means a safety device used to prevent
operating pressures from exceeding the
maximum allowable working pressure
of the process equipment. A common
pressure relief device includes, but is
not limited to, a spring-loaded pressure
relief valve. Devices that are actuated
either by a pressure of less than or equal
to 2.5 psig or by a vacuum are not
pressure relief devices.
Primary product means the product of
a process that is produced in greater
mass quantity than any other product of
the process.
Process emissions means the
emissions from industrial processes
(e.g., cement production, ammonia
production) involving chemical or
physical transformations other than fuel
combustion. For example, the
calcination of carbonates in a kiln
during cement production or the
oxidation of methane in an ammonia
process results in the release of process
CO2 emissions to the atmosphere.
Emissions from fuel combustion to
provide process heat are not part of
process emissions, whether the
combustion is internal or external to the
process equipment.
Process Type, for purposes of
electronics manufacturing, means the
PO 00000
Frm 00179
Fmt 4701
Sfmt 4702
16625
kind of electronics manufacturing
process, i.e., etching, cleaning, or
chemical vapor deposition using N2O.
Process gas means any gas generated
by an industrial process such as
petroleum refining.
Processing facility fugitive emissions
means natural gas released from all
components including valves, flanges,
connectors, open-ended lines, pump
seals, ESD (emergency shut-down)
system fugitive emissions, packing and
gaskets in natural gas processing
facilities. This does not include fugitive
emissions from equipment and
components reported elsewhere for this
rule, such as compressor fugitive
emissions; acid gas removal, blowdown,
wet seal oil degassing, and dehydrator
vents; and flare stacks.
Production process unit means
equipment used to capture a carbon
dioxide stream.
Propane means the normally gaseous
paraffinic compound (C3H8), which
includes all products covered by
Natural Gas Policy Act Specifications
for commercial and HD–5 propane and
ASTM Specification D 1835. It excludes
feedstock propanes, which are propanes
not classified as consumer grade
propanes, including the propane portion
of any natural gas liquid mixes, i.e.,
butane-propane mix.
Propylene (C3H6) is an olefinic
hydrocarbon recovered from refinery
processes or petrochemical processes.
Pulp Mill Lime kiln means the
combustion units (e.g., rotary lime kiln
or fluidized bed calciner) used at a kraft
or soda pulp mill to calcine lime mud,
which consists primarily of calcium
carbonate, into quicklime, which is
calcium oxide.
Pump seals means any seal on a pump
drive shaft used to keep methane and/
or carbon dioxide containing light
liquids from escaping the inside of a
pump case to the atmosphere.
Pump seal fugitive emissions means
natural gas released from the seal face
between the pump internal chamber and
the atmosphere.
Pushing means the process of
removing the coke from the coke oven
at the end of the coking cycle. Pushing
begins when coke first begins to fall
from the oven into the quench car and
ends when the quench car enters the
quench tower.
Raw mill means a ball and tube mill,
vertical roller mill or other size
reduction equipment, that is not part of
an in-line kiln/raw mill, used to grind
feed to the appropriate size. Moisture
may be added or removed from the feed
during the grinding operation. If the raw
mill is used to remove moisture from
feed materials, it is also, by definition,
E:\FR\FM\10APP2.SGM
10APP2
16626
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
a raw material dryer. The raw mill also
includes the air separator associated
with the raw mill.
RBOB (reformulated gasoline for
oxygenate blending) means a petroleum
product which, when blended with a
specified type and percentage of
oxygenate, meets the definition of
reformulated gasoline.
Reciprocating compressor means a
piece of equipment that increases the
pressure of a process natural gas by
positive displacement, employing linear
movement of a shaft driving a piston in
a cylinder.
Reciprocating compressor rod packing
means a series of flexible rings in
machined metal cups that fit around the
reciprocating compressor piston rod to
create a seal limiting the amount of
compressed natural gas that escapes to
the atmosphere.
Reciprocating compressor rod packing
fugitive emissions means natural gas
released from a connected tubing vent
and/or around a piston rod where it
passes through the rod packing case. It
also includes emissions from uncovered
distance piece, rod packing flange (on
each cylinder), any packing vents, cover
plates (on each cylinder), and the
crankcase breather cap.
Re-condenser means heat exchangers
that cool compressed boil-off gas to a
temperature that will condense natural
gas to a liquid.
Refined petroleum product means
petroleum products produced from the
processing of crude oil, lease
condensate, natural gas and other
hydrocarbon compounds
Refinery fuel gas (still gas) means any
gas generated at a petroleum refinery, or
any gas generated by a refinery process
unit, that is combusted separately or in
any combination with any type of gas or
used as a chemical feedstock.
Reformulated gasoline means any
gasoline whose formulation has been
certified under 40 CFR 80.40, and which
meets each of the standards and
requirements prescribed under 40 CFR
80.41.
Re-gasification means the process of
vaporizing liquefied natural gas to
gaseous phase natural gas.
Research and development process
unit means a process unit whose
purpose is to conduct research and
development for new processes and
products and is not engaged in the
manufacture of products for commercial
sale, except in a de minimis manner.
Residual fuel oil means a
classification for the heavier fuel oils,
No. 5 and No. 6. No. 5 is also known
as Navy Special and is used in steam
powered vessels in government service
and inshore power plants. No.6 includes
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Bunker C and is used for the production
of electric power, space heating, vessel
bunkering and various industrial
purposes.
Residue gas means natural gas from
which natural gas processing facilities
liquid products and, in some cases, nonhydrocarbon components have been
extracted.
Rotameter means a flow meter in
which gas flow rate upward through a
tapered tube lifts a ‘‘float bob’’ to an
elevation related to the gas flow rate
indicated by etched calibrations on the
wall of the tapered tube.
Rotary lime kiln means a unit with an
inclined rotating drum that is used to
produce a lime product from limestone
by calcination.
Semi-refined petroleum product
means all oils requiring further
processing. Included in this category are
unfinished oils which are produced by
the partial refining of crude oil and
include the following: naphthas and
lighter oils; kerosene and light gas oils;
heavy gas oils; and residuum, and all
products that require further processing
or the addition of blendstocks.
Sensor means a device that measures
a physical quantity/quality or the
change in a physical quantity/quality,
such as temperature, pressure, flow rate,
pH, or liquid level.
SF6 means sulfur hexafluoride.
Shutdown means the cessation of
operation of an emission source for any
purpose.
Silicon carbide means an artificial
abrasive produced from silica sand or
quartz and petroleum coke.
Simulation software means a
calibrated, empirical computer program
that uses physical parameters and
scientific laws to numerically simulate
the performance variables of a physical
process, outputting such parameters as
emission rates from which methane
emissions can be estimated.
Sinter process means a process that
produces a fused aggregate of fine ironbearing materials suited for use in a
blast furnace. The sinter machine is
composed of a continuous traveling
grate that conveys a bed of ore fines and
other finely divided iron-bearing
material and fuel (typically coke
breeze), a burner at the feed end of the
grate for ignition, and a series of
downdraft windboxes along the length
of the strand to support downdraft
combustion and heat sufficient to
produce a fused sinter product.
Site means any combination of one or
more graded pad sites, gravel pad sites,
foundations, platforms, or the
immediate physical location upon
which equipment is physically located.
PO 00000
Frm 00180
Fmt 4701
Sfmt 4702
Smelting furnace means a furnace in
which lead-bearing materials, carboncontaining reducing agents, and fluxes
are melted together to form a molten
mass of material containing lead and
slag.
Solid storage is the storage of manure,
typically for a period of several months,
in unconfined piles or stacks. Manure is
able to be stacked due to the presence
of a sufficient amount of bedding
material or loss of moisture by
evaporation.
Sour natural gas means natural gas
that contains significant concentrations
of hydrogen sulfide and/or carbon
dioxide that exceed the concentrations
specified for commercially saleable
natural gas delivered from transmission
and distribution pipelines.
Special naphthas means all finished
products with the naphtha boiling range
(290° to 470 °F) that are used as paint
thinners, cleaners or solvents.
Spent liquor solids means the dry
weight of the solids in the spent 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 semichemical pulp facilities.
Standard conditions or standard
temperature and pressure (STP) means
60 degrees Fahrenheit and 14.7 pounds
per square inch absolute.
Standby means for an equipment to be
in a state ready for operation, but not
operating.
Steam aspirated flare means steam
injected into the flare burner tip to
induce air mixing with the hydrocarbon
fuel to promote more complete
combustion as indicated by lack of
smoke formation.
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.
Storage station fugitive emissions
means natural gas released from all
components including valves, flanges,
connectors, open-ended lines, pump
seals, ESD (emergency shut-down)
system emissions, packing and gaskets
in natural gas storage station. This does
not include fugitive emissions from
equipment and equipment components
reported elsewhere for this rule.
Storage tank means other vessel that
is designed to contain an accumulation
of crude oil, condensate, intermediate
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
hydrocarbon liquids, or produced water
and that is constructed entirely of nonearthen materials (e.g., wood, concrete,
steel, plastic) that provide structural
support.
Storage tank fugitive emissions means
natural gas vented when it flashes out
of liquids; this occurs when liquids are
transferred from higher pressure and
temperature conditions upstream, plus
working losses from liquid level
increases and decreases during filling
and draining and standing losses
(breathing losses) from diurnal
temperature changes and barometric
pressure changes expanding and
contracting the vapor volume of a tank.
Storage wellhead fugitive emissions
means natural gas released from storage
station wellhead components including
but not limited to valves, OELs,
connectors, flanges, and tube fittings.
Sub-surface or subsurface facility
means for the purposes of this rule, a
natural gas facility, such as a pipeline
and metering and regulation station in
a closed vault below the land surface of
the Earth.
Sulfur recovery plant means all
process units which recover sulfur or
produce sulfuric acid from hydrogen
sulfide (H2S) and/or sulfur dioxide
(SO2) 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
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.
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.
Tanker unloading means pumping of
liquid hydrocarbon (e.g., crude oil,
LNG) from an ocean-going tanker or
barge to shore storage tanks.
Toxic vapor analyzer (TVA) means an
organic monitoring device that uses a
flame ionization detector and
photoionization detector to measure the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
concentrations in air of combustible
organic vapors from 9 parts per million
and exceeding 10,000 parts per million
sucked into the probe.
Trace concentrations means
concentrations of less than 0.1 percent
by mass of the process stream.
Trained technician means a person
who has completed a vendor provided
or equivalent training program and
demonstrated proficiency to use specific
equipment for its intended purpose,
such as high volume sampler for the
purposes of this rule.
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.
Transmission compressor station
fugitive emissions means natural gas
released from all components including
but not limited to valves, flanges,
connectors, open-ended lines, pump
seals, ESD (emergency shut-down)
system emissions, packing and gaskets
in natural gas transmission compressor
stations. This does not include fugitive
emissions from equipment and
equipment components reported
elsewhere for this rule, such as
compressor fugitive emissions.
Transmission pipeline means high
pressure cross country pipeline
transporting saleable quality natural gas
from production or natural gas
processing to natural gas distribution
pressure let-down, metering, regulating
stations where the natural gas is
typically odorized before delivery to
customers.
Trona means the raw material
(mineral) used to manufacture soda ash;
hydrated sodium bicarbonate carbonate
(NaCO3.NaHCO3.2H2O).
Turbine meter means a flow meter in
which a gas or liquid flow rate through
the calibrated tube spins a turbine from
which the spin rate is detected and
calibrated to measure the fluid flow rate.
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
PO 00000
Frm 00181
Fmt 4701
Sfmt 4702
16627
complete combustion of a sample of an
organic material.
Uncovered anaerobic lagoons are a
type of liquid storage system designed
and operated to combine waste
stabilization and storage. Lagoon
supernatant is usually used to remove
manure from the associated
confinement facilities to the lagoon.
Anaerobic lagoons are designed with
varying lengths of storage (up to a year
or greater), depending on the climate
region, the volatile solids loading rate,
and other operational factors. The water
from the lagoon may be recycled as
flush water or used to irrigate and
fertilize fields.
Underground natural gas storage
facility means a subsurface facility,
including but not limited to depleted
gas or oil reservoirs and salt dome
caverns, utilized for storing natural gas
that has been transferred from its
original location for the primary
purpose of load balancing, which is the
process of equalizing the receipt and
delivery of natural gas. Processes and
operations that may be located at a
natural gas underground storage facility
include, but are not limited to,
compression, dehydration and flow
measurement. The storage facility also
includes all the wellheads connected to
the compression units located at the
facility.
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 subpart, 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.
Vapor recovery system means any
equipment located at the source of
potential gas emissions to the
atmosphere or to a flare, that is
composed of piping, connections, and,
if necessary, flow-inducing devices; and
that is used for routing the gas back into
the process as a product and/or fuel.
Vaporization unit means a process
unit that performs controlled heat input
to vaporize liquefied natural gas to
supply transmission and distribution
pipelines, or consumers with natural
gas.
E:\FR\FM\10APP2.SGM
10APP2
16628
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Ventilation system means a system
deployed within a mine to ensure that
CH4 levels remain within safe
concentrations.
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 feedstocks are non-crude
feedstocks that have been contaminated,
downgraded, or no longer meet the
specifications of the product category or
end-use for which they were intended.
Waste feedstocks include but are not
limited to: Used plastics, used engine
oils, used dry cleaning solvents, and
trans-mix (mix of products at the
interface in delivery pipelines).
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.
Wellhead means the piping, casing,
tubing and connected valves protruding
above the Earth’s surface for an oil and/
or natural gas well. The wellhead ends
where the flow line connects to a
wellhead valve.
Wet natural gas means natural gas in
which water vapor exceeds the
concentration specified for
commercially saleable natural gas
delivered from transmission and
distribution pipelines. This input
stream to a natural gas dehydrator is
referred to as ‘‘wet gas’’.
Wool fiberglass means fibrous glass of
random texture, including fiberglass
insulation, and other products listed in
NAICS 327993.
You means the 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 zincbearing 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 for use in this
part and are incorporated as they
existed on the date of approval of this
part.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(a) The following materials are
available for purchase from the
following addresses: American Society
for Testing and Material (ASTM), 100
Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, Pennsylvania
19428–B2959; and the University
Microfilms International, 300 North
Zeeb Road, Ann Arbor, Michigan 48106:
(1) ASTM D240–02, (Reapproved
2007), Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter.
(2) ASTM D388–05, Standard
Classification of Coals by Rank.
(3) ASTM D396–08, Standard
Specification for Fuel Oils.
(4) ASTM D975–08, Standard
Specification for Diesel Fuel Oils.
(5) ASTM D1250–07, Standard Guide
for Use of the Petroleum Measurement
Tables.
(6) ASTM D1826–94 (Reapproved
2003), Standard Test Method for
Calorific (Heating) Value of Gases in
Natural Gas Range by Continuous
Recording Calorimeter.
(7) ASTM Specification D1835–05
(2005).
(8) ASTM D1945–03 (Reapproved
2006), Standard Test Method for
Analysis of Natural Gas by Gas
Chromatography.
(9) ASTM D1946–90 (Reapproved
2006), Standard Practice for Analysis of
Reformed Gas by Gas Chromatography.
(10) ASTM D2013–07, Standard
Practice of Preparing Coal Samples for
Analysis.
(11) ASTM D2234/D2234M–07,
Standard Practice for Collection of a
Gross Sample of Coal.
(12) ASTM D2502–04 (Reapproved
2002), Standard Test Method for
Estimation of Molecular Weight
(Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements.
(13) ASTM D2503–92 (Reapproved
2007), Standard Test Method for
Relative Molecular Mass (Relative
Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor
Pressure.
(14) ASTM D2880–03, Standard
Specification for Gas Turbine Fuel Oils.
(15) ASTM D3176–89 (Reapproved
2002), Standard Practice for Ultimate
Analysis of Coal and Coke.
(16) 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.
(17) ASTM D3588–98 (Reapproved
2003), Standard Practice for Calculating
Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels.
(18) ASTM Specification D3699–07,
Standard Specification for Kerosene.
PO 00000
Frm 00182
Fmt 4701
Sfmt 4702
(19) ASTM D4057–06, Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products.
(20) ASTM D4809–06, Standard Test
Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method).
(21) ASTM Specification D4814–08a,
Standard Specification for Automotive
Spark-Ignition Engine Fuel.
(22) ASTM D4891–89 (Reapproved
2006), Standard Test Method for
Heating Value of Gases in Natural Gas
Range by Stoichiometric Combustion.
(23) ASTM D5291–02 (Reapproved
2007), Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants.
(24) ASTM D5373–08, Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke.
(25) ASTM D5865–07a, Standard Test
Method for Gross Calorific Value of Coal
and Coke.
(26) ASTM D6316–04, Standard Test
Method for the Determination of Total,
Combustible and Carbonate Carbon in
Solid Residues from Coal and Coke.
(27) ASTM D6866–06a, Standard Test
Methods for Determining the Biobased
Content of Natural Range Materials
Using Radiocarbon and Isotope Ratio
Mass Spectrometry Analysis.
(28) ASTM E1019–03, Standard Test
Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel
and in Iron, Nickel, and Cobalt Alloys.
(29) ASTM E1915–07a, Standard Test
Methods for Analysis of Metal Bearing
Ores and Related Materials by
Combustion Infrared-Absorption
Spectrometry.
(30) ASTM CS–104 (1985), Carbon
Steel of Medium Carbon Content.
(31) ASTM D 7459–08, Standard
Practice for Collection of Integrated
Samples for the Speciation of Biomass
(Biogenic) and Fossil-Derived Carbon
Dioxide Emitted from Stationary
Emissions Sources.
(32) ASTM D6060–96(2001) Standard
Practice for Sampling of Process Vents
With a Portable Gas Chromatograph.
(33) ASTM D 2502–88(2004)e1
Standard Test Method for Ethylene,
Other Hydrocarbons, and Carbon
Dioxide in High-Purity Ethylene by Gas
Chromatography.
(34) ASTM C25–06 Standard Test
Method for Chemical Analysis of
Limestone, quicklime, and Hydrated
Lime.
(35) UOP539–97 Refinery Gas
Analysis by Gas Chromatography.
(b) The following materials are
available for purchase from the
American Society of Mechanical
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Engineers (ASME), 22 Law Drive, P.O.
Box 2900, Fairfield, NJ 07007–2900:
(1) ASME MFC–3M–2004,
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi.
(2) ASME MFC–4M–1986 (Reaffirmed
1997), Measurement of Gas Flow by
Turbine Meters.
(3) ASME-MFC–5M–1985,
(Reaffirmed 1994), Measurement of
Liquid Flow in Closed Conduits Using
Transit-Time Ultrasonic Flowmeters.
(4) ASME MFC–6M–1998,
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters.
(5) ASME MFC–7M–1987 (Reaffirmed
1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles.
(6) ASME MFC–9M–1988 (Reaffirmed
2001), Measurement of Liquid Flow in
Closed Conduits by Weighing Method.
(c) The following materials are
available for purchase from the
American National Standards Institute
(ANSI), 25 West 43rd Street, Fourth
Floor, New York, New York 10036:
(1) ISO 8316: 1987 Measurement of
Liquid Flow in Closed Conduits—
Method by Collection of the Liquid in
a Volumetric Tank.
(2) 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).
(3) 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).
(d) The following materials are
available for purchase from the
following address: Gas Processors
Association (GPA), 6526 East 60th
Street, Tulsa, Oklahoma 74143:
(1) GPA Standard 2172–96,
Calculation of Gross Heating Value,
Relative Density and Compressibility
Factor for Natural Gas Mixtures from
Compositional Analysis.
(2) GPA Standard 2261–00, Analysis
for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography.
(e) The following American Gas
Association materials are available for
purchase from the following address: ILI
Infodisk, 610 Winters Avenue, Paramus,
New Jersey 07652:
(1) American Gas Association Report
No. 3: Orifice Metering of Natural Gas,
Part 1: General Equations and
Uncertainty Guidelines (1990), Part 2:
Specification and Installation
Requirements (1990).
(2) American Gas Association
Transmission Measurement Committee
Report No. 7: Measurement of Gas by
Turbine Meters (2006).
(f) The following materials are
available for purchase from the
following address: American Petroleum
Institute, Publications Department, 1220
L Street, NW., Washington, DC 20005–
4070:
(1) American Petroleum Institute
(API) Manual of Petroleum
Measurement Standards, Chapter 3—
Tank Gauging:
(i) Section 1A, Standard Practice for
the Manual Gauging of Petroleum and
Petroleum Products, Second Edition,
August 2005.
(ii) Section 1B—Standard Practice for
Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by
Automatic Tank Gauging, Second
Edition June 2001 (Reaffirmed, October
2006).
(iii) Section 3—Standard Practice for
Level Measurement of Liquid
Hydrocarbons in Stationary Pressurized
Storage Tanks by Automatic Tank
Gauging, First Edition June 1996
(Reaffirmed, October 2006).
16629
(2) Shop Testing of Automatic Liquid
Level Gages, Bulletin 2509 B, December
1961 (Reaffirmed August 1987, October
1992).
(3) American Petroleum Institute
(API) Manual of Petroleum
Measurement Standards, Chapter 4—
Proving Systems:
(i) Section 2—Displacement Provers,
Third Edition, September 2003.
(ii) Section 5—Master-Meter Provers,
Second Edition, May 2000 (Reaffirmed,
August 2005).
(4) American Petroleum Institute
(API) Manual of Petroleum
Measurement Standards, Chapter 22—
Testing Protocol, Section 2—Differential
Pressure Flow Measurement Devices,
First Edition, August 2005.
(g) The following material is available
for purchase from the following address:
American Society of Heating,
Refrigerating and Air-Conditioning
Engineers, Inc., 1791 Tullie Circle, NE.,
Atlanta, Georgia 30329.
(1) ASHRAE 41.8–1989: Standard
Methods of Measurement of Flow of
Liquids in Pipes Using Orifice
Flowmeters.
§ 98.8 What are the compliance and
enforcement provisions of this part?
Any violation of the requirements of
this part shall be a violation of the Clean
Air Act. 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
emission, and failure to calculate GHG
emissions following the methodologies
specified in this part. Each day of a
violation constitutes a separate
violation.
TABLE A–1 OF SUBPART A—GLOBAL WARMING POTENTIALS (100-YEAR TIME HORIZON)
Name
CAS No.
Carbon dioxide ..............................................................
Methane ........................................................................
Nitrous oxide .................................................................
HFC-23 ..........................................................................
HFC-32 ..........................................................................
HFC-41 ..........................................................................
HFC-125 ........................................................................
HFC-134 ........................................................................
HFC-134a ......................................................................
HFC-143 ........................................................................
HFC-143a ......................................................................
HFC-152 ........................................................................
HFC-152a ......................................................................
HFC-161 ........................................................................
HFC-227ea ....................................................................
HFC-236cb ....................................................................
HFC-236ea ....................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
124–38–9
74–82–8
10024–97–2
75–46–7
75–10–5
593–53–3
354–33–6
359–35–3
811–97–2
430–66–0
420–46–2
624–72–6
75–37–6
353–36–6
431–89–0
677–56–5
431–63–0
Frm 00183
Fmt 4701
Chemical formula
CO2 ...............................................................................
CH4 ...............................................................................
N2O ...............................................................................
CHF3 .............................................................................
CH2F2 ...........................................................................
CH3F .............................................................................
C2HF5 ...........................................................................
C2H2F4 ..........................................................................
CH2FCF3 ......................................................................
C2H3F3 ..........................................................................
C2H3F3 ..........................................................................
CH2FCH2F ....................................................................
CH3CHF2 ......................................................................
CH3CH2F ......................................................................
C3HF7 ...........................................................................
CH2FCF2CF3 ................................................................
CHF2CHFCF3 ...............................................................
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Global warming potential
(100 yr.)
1
21
310
11,700
650
150
2,800
1,000
1,300
300
3,800
53
140
12
2,900
1,340
1,370
16630
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE A–1 OF SUBPART A—GLOBAL WARMING POTENTIALS (100-YEAR TIME HORIZON)—Continued
Global warming potential
(100 yr.)
Name
CAS No.
Chemical formula
HFC-236fa .....................................................................
HFC-245ca ....................................................................
HFC-245fa .....................................................................
HFC-365mfc ..................................................................
HFC-43-10mee .............................................................
Sulfur hexafluoride ........................................................
Trifluoromethyl sulphur pentafluoride ...........................
Nitrogen trifluoride .........................................................
PFC-14 (Perfluoromethane) ..........................................
PFC-116 (Perfluoroethane) ...........................................
PFC-218 (Perfluoropropane) ........................................
Perfluorocyclopropane ..................................................
PFC-3-1-10 (Perfluorobutane) ......................................
Perfluorocyclobutane ....................................................
PFC-4-1-12 (Perfluoropentane) ....................................
PFC-5-1-14 (Perfluorohexane) .....................................
PFC-9-1-18 ...................................................................
HCFE-235da2 (Isoflurane) ............................................
HFE-43-10pccc (H-Galden 1040x) ...............................
HFE-125 ........................................................................
HFE-134 ........................................................................
HFE-143a ......................................................................
HFE-227ea ....................................................................
HFE-236ca12 (HG-10) ..................................................
HFE-236ea2 (Desflurane) .............................................
HFE-236fa .....................................................................
HFE-245cb2 ..................................................................
HFE-245fa1 ...................................................................
HFE-245fa2 ...................................................................
HFE-254cb2 ..................................................................
HFE-263fb2 ...................................................................
HFE-329mcc2 ...............................................................
HFE-338mcf2 ................................................................
HFE-338pcc13 (HG-01) ................................................
HFE-347mcc3 ...............................................................
HFE-347mcf2 ................................................................
HFE-347pcf2 .................................................................
HFE-356mec3 ...............................................................
HFE-356pcc3 ................................................................
HFE-356pcf2 .................................................................
HFE-356pcf3 .................................................................
HFE-365mcf3 ................................................................
HFE-374pc2 ..................................................................
HFE-449sl (HFE-7100) Chemical blend .......................
690–39–1
679–86–7
460–73–1
406–58–6
138495–42–8
2551–62–4
373–80–8
7783–54–2
75–73–0
76–16–4
76–19–7
931–91–9
355–25–9
115–25–3
678–26–2
355–42–0
306–94–5
26675–46–7
NA
3822–68–2
1691–17–4
421–14–7
2356–62–9
NA
57041–67–5
20193–67–3
22410–44–2
NA
1885–48–9
425–88–7
460–43–5
67490–36–2
156–05–3
NA
28523–86–6
NA
406–78–0
382–34–3
NA
NA
35042–99–0
NA
512–51–6
163702–07–6
163702–08–7
163702–05–4
163702–06–5
28523–86–6
13171–18–1
26103–08–2
NA
NA
NA
NA
NA
C3H2F6 ..........................................................................
C3H3F5 ..........................................................................
CHF2CH2CF3 ................................................................
CH3CF2CH2CF3 ............................................................
CF3CFHCFHCF2CF3 ....................................................
SF6 ...............................................................................
SF5CF3 .........................................................................
NF3 ...............................................................................
CF4 ...............................................................................
C2F6 ..............................................................................
C3F8 ..............................................................................
c-C3F6 ...........................................................................
C4F10 ............................................................................
c-C4F8 ...........................................................................
C5F12 ............................................................................
C6F14 ............................................................................
C10F18 ...........................................................................
CHF2OCHClCF3 ...........................................................
CHF2OCF2OC2F4OCHF2 ..............................................
CHF2OCF3 ....................................................................
CHF2OCHF2 .................................................................
CH3OCF3 ......................................................................
CF3CHFOCF3 ...............................................................
CHF2OCF2OCHF2 ........................................................
CHF2OCHFCF3 ............................................................
CF3CH2OCF3 ................................................................
CH3OCF2CF3 ................................................................
CHF2CH2OCF3 .............................................................
CHF2OCH2CF3 .............................................................
CH3OCF2CHF2 .............................................................
CF3CH2OCH3 ...............................................................
CF3CF2OCF2CHF2 .......................................................
CF3CF2OCH2CF3 .........................................................
CHF2OCF2CF2OCHF2 ..................................................
CH3OCF2CF2CF3 .........................................................
CF3CF2OCH2CHF2 .......................................................
CHF2CF2OCH2CF3 .......................................................
CH3OCF2CHFCF3 ........................................................
CH3OCF2CF2CHF2 .......................................................
CHF2CH2OCF2CHF2 ....................................................
CHF2OCH2CF2CHF2 ....................................................
CF3CF2CH2OCH3 .........................................................
CH3CH2OCF2CHF2 ......................................................
C4F9OCH3 ....................................................................
(CF3)2CFCF2OCH3.
C4F9OC2H5 ...................................................................
(CF3)2CFCF2OC2H5.
CH2FOCH(CF3)2 ...........................................................
(CF3)2CHOCH3 .............................................................
CHF2OCH(CF3)2 ...........................................................
-(CF2)4CH(OH)- ............................................................
CH3OCF(CF3)2 .............................................................
(CF3)2CHOH .................................................................
CF3CF2CH2OH .............................................................
CF3OCF(CF3)CF2OCF2OCF3 .......................................
HFE-569sf2 (HFE-7200) Chemical blend .....................
Sevoflurane ...................................................................
NA .................................................................................
NA .................................................................................
NA .................................................................................
NA .................................................................................
NA .................................................................................
NA .................................................................................
PFPMIE .........................................................................
NA = not available.
TABLE A–2 OF SUBPART A—UNITS OF MEASURE CONVERSIONS
To convert from
To
Kilograms (kg) ..................................................................
Pounds (lbs) .....................................................................
Pounds (lbs) .....................................................................
Short tons .........................................................................
Short tons .........................................................................
Metric tons ........................................................................
Metric tons ........................................................................
Cubic meters (m3) ............................................................
Pounds (lbs) .....................................................................
Kilograms (kg) ..................................................................
Metric tons .......................................................................
Pounds (lbs) .....................................................................
Metric tons .......................................................................
Short tons .........................................................................
Kilograms (kg) ..................................................................
Cubic feet (ft3) ..................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00184
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
Multiply by
10APP2
2.20462.
0.45359.
4.53592 × 10¥4.
2,000.
0.90718.
1.10231.
1,000.
35.31467.
6,300
560
1,030
794
1,300
23,900
17,700
17,200
6,500
9,200
7,000
17,340
7,000
8,700
7,500
7,400
7,500
350
1,870
14,900
6,320
756
1,540
2,800
989
487
708
286
659
359
11
919
552
1,500
575
374
580
101
110
265
502
11
557
297
59
345
27
380
73
343
195
42
10,300
16631
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE A–2 OF SUBPART A—UNITS OF MEASURE CONVERSIONS—Continued
To convert from
To
Multiply by
Cubic feet (ft3) ..................................................................
Gallons (liquid, US) ..........................................................
Liters (l) ............................................................................
Barrels of Liquid Fuel (bbl) ..............................................
Cubic meters (m3) ............................................................
Barrels of Liquid Fuel (bbl) ..............................................
Gallons (liquid, US) ..........................................................
Gallons (liquid, US) ..........................................................
Liters (l) ............................................................................
Feet (ft) .............................................................................
Meters (m) ........................................................................
Miles (mi) ..........................................................................
Kilometers (km) ................................................................
Square feet (ft2) ...............................................................
Square meters (m2) .........................................................
Square miles (mi2) ...........................................................
Degrees Celsius (°C) .......................................................
Degrees Fahrenheit (°F) ..................................................
Degrees Celsius (°C) .......................................................
Kelvin (K) ..........................................................................
Joules ...............................................................................
Btu ....................................................................................
Pascals (Pa) .....................................................................
Inches of Mercury (inHg) .................................................
Pounds per square inch (psi) ...........................................
Cubic meters (m3) ............................................................
Liters (l) ............................................................................
Gallons (liquid, US) ..........................................................
Cubic meters (m3) ............................................................
Barrels of Liquid Fuel (bbl) ..............................................
Gallons (liquid, US) ..........................................................
Barrels of Liquid Fuel (bbl) ..............................................
Cubic meters (m3) ............................................................
Cubic meters (m3) ............................................................
Meters (m) ........................................................................
Feet (ft) ............................................................................
Kilometers (km) ................................................................
Miles (mi) .........................................................................
Acres ................................................................................
Acres ................................................................................
Square kilometers (km2) ..................................................
Degrees Fahrenheit (°F) ..................................................
Degrees Celsius (°C) .......................................................
Kelvin (K) .........................................................................
Degrees Rankine (°R) ......................................................
Btu ....................................................................................
MMBtu ..............................................................................
Inches of Mercury (in Hg) ................................................
Pounds per square inch (psi) ..........................................
Inches of Mercury (in Hg) ................................................
Subpart B—[Reserved]
by a state or local air pollution control
agency.
Subpart C—General Stationary Fuel
Combustion Sources
§ 98.31
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,
combustion turbines, engines,
incinerators, and process heaters.
(b) This source category does not
include portable equipment or
generating units designated as
emergency generators in a permit issued
§ 98.32
GHGs to report.
You must report CO2, CH4, and N2O
mass emissions from each stationary
fuel combustion unit.
§ 98.33
Calculating GHG emissions.
The owner or operator shall use the
methodologies in this section to
calculate the GHG emissions from
stationary fuel combustion sources,
except for electricity generating units
that are subject to the Acid Rain
Program. The GHG emissions
CO2 = 1 x 10−3 ∗ Fuel ∗ HHV ∗ EF
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 (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
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. C-1)
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.
(2) Tier 2 Calculation Methodology.
Calculate the annual CO2 mass
emissions for a particular type of fuel
PO 00000
Frm 00185
Fmt 4701
Sfmt 4702
calculation methods for Acid Rain
Program units are addressed in subpart
D of this part.
(a) CO2 emissions from fuel
combustion. For each stationary fuel
combustion unit, the owner or operator
shall use the four-tiered approach in
this paragraph, subject to the
conditions, requirements, and
restrictions set forth in paragraph (b) of
this section.
(1) Tier 1 Calculation Methodology.
Calculate the annual CO2 mass
emissions for a particular type of fuel
combusted in a unit, by substituting a
fuel-specific default CO2 emission factor
(from Table C–1 of this subpart), a
default high heating value (from Table
C–1 of this subpart), and the annual fuel
consumption (from company records
kept as provided in this rule) into the
Equation C–1 of this section:
combusted in a unit, by substituting
measured high heat values, a default
CO2 emission factor (from Table C–1 or
Table C–2 of this subpart), and the
quantity of fuel combusted (from
company records kept as provided in
this rule) into the following equations:
(i) Equation C–2a of this section
applies to any type of fuel, except for
municipal solid waste (MSW):
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.002</GPH>
§ 98.30
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains one or more stationary
combustion sources and the facility
meets the requirements of either
§ 98.2(a)(1), (2), or (3).
0.028317.
3.78541.
0.26417.
0.15891.
6.289.
42.
0.023810.
0.0037854.
0.001.
0.3048.
3.28084.
1.60934.
0.62137.
2.29568 × 10¥5.
2.47105 × 10¥4.
2.58999.
°C = (5/9) × (°F¥32).
°F = (9/5) × °C + 32.
K = °C + 273.15.
1.8.
9.47817 × 10¥4.
1 × 10¥6.
2.95334 × 10¥4.
0.49110.
2.03625.
16632
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
n
CO2 = ∑1 x 10−3 ( Fuel ) p ∗ ( HHV ) p ∗ EF
(Eq. C-2a)
p =1
p = Measurement period (month).
(HHV)p = High heat value of the fuel for the
measurement period (mmBtu per mass or
volume).
EF = Fuel-specific default CO2 emission
factor, from Table C–1 or C–2 of this
subpart (kg CO2/mmBtu).
1 x 10¥3 = Conversion factor from kilograms
to metric tons.
CO2 = 1 x 10−3 ( Steam) ( B) ( EF )
(Fuel)n = Mass of the solid fuel combusted in
month ‘‘n’’ (metric tons).
P = Measurement period (month).
(CC)n = Carbon content of the solid fuel, from
the fuel analysis results for month ‘‘n’’
p =1
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific liquid fuel
(metric tons).
N = Number of required carbon content
determinations for the year.
(Eq. C-4)
(Fuel)n = Volume of the liquid fuel
combusted in month ‘‘n’’ (gallons).
P = Measurement period (month).
(CC)n = Carbon content of the liquid fuel,
from the fuel analysis results for month
‘‘n’’ (kg C per gallon of fuel).
n
CO2 = ∑
p =1
Jkt 217001
44
∗ (Fuel ) n ∗ (CC ) n ∗ 0.001
12
44
MW
∗ (Fuel ) n ∗ (CC ) n ∗
∗ 0.001
12
MVC
N = Number of required carbon content and
molecular weight determinations for the
year.
PO 00000
Frm 00186
Fmt 4701
Sfmt 4702
(ii) For a liquid fuel, use Equation
C–4 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)
(Fuel)n = Volume of the gaseous fuel
combusted on day ‘‘n’’ or in month ‘‘n’’,
as applicable (scf).
P = Measurement period (month or day, as
applicable).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.007</GPH>
n
CO2 = ∑
(percent by weight, expressed as a
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to
carbon.
EP10AP09.006</GPH>
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific solid fuel
(metric tons).
N = Number of required carbon content
determinations for the year.
(Eq. C-3)
EP10AP09.005</GPH>
p =1
44
∗ (Fuel ) n ∗ (CC ) n
12
EP10AP09.004</GPH>
n
15:41 Apr 09, 2009
the amount of fuel combusted is
obtained from company records kept as
provided in this rule. For liquid and
gaseous fuels, the volume of fuel
combusted is measured directly, using
fuel flow meters (including gas billing
meters). For fuel oil, tank drop
measurements may also be used.
(i) For a solid fuel, use Equation
C–3 of this section:
(3) Tier 3 Calculation Methodology.
Calculate the annual CO2 mass
emissions for a particular type of fuel
combusted in a unit, by substituting
measurements of fuel carbon content,
molecular weight (gaseous fuels, only),
and the quantity of fuel combusted into
the following Equations. For solid fuels,
CO2 = ∑
VerDate Nov<24>2008
(Eq. C-2b)
1 x 10¥3 = Conversion factor from kilograms
to metric tons.
Where:
CO2 = Annual CO2 mass emissions from
MSW combustion (metric tons).
Steam = Total mass of steam generated by
MSW 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 = Default CO2 emission factor for MSW,
from Table C–3 of this subpart (kg CO2/
mmBtu).
Where:
CO2 = Annual CO2 mass emissions from
combustion of the specific gaseous fuel
(metric tons).
(ii) In Equation C–2a of this section,
the value of ‘‘n’’ depends upon the
frequency at which high heat value
(HHV) measurements are required under
§ 98.34(c). For example, for natural gas,
which requires monthly sampling and
analysis, n = 6 if the unit combusts
natural gas in only 6 months of the year.
(iii) For MSW combustion, use
Equation C–2b of this section:
EP10AP09.003</GPH>
Where:
CO2 = Annual CO2 mass emissions for a
specific fuel type (metric tons).
n = Number of required heat content
measurements for the year.
(Fuel)p = Mass or volume of the fuel
combusted during the measurement
period ‘‘p’’ (express mass in short tons
for solid fuel, volume in standard cubic
feet for gaseous fuel, and volume in
gallons for liquid fuel).
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
CO2 = 5.18 x 10−7 ∗ CCO 2 ∗ Q
Where:
CO2 = CO2 mass emission rate (metric tons/
hr).
CCO2 = Hourly average CO2 concentration (%
CO2).
Q = Hourly average stack gas volumetric flow
rate (scfh).
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
(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 part
75 of this chapter, if the effluent gas
stream monitored by the CEMS consists
solely of combustion products and if
only fuels that are listed in Table 1 in
section 3.3.5 of appendix F to 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 part 75 of this
chapter, as applicable. If Equation F–
14b is used, the hourly moisture
percentage in the stack gas shall be
either 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.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. C-6)
5.18 x 10¥7 = Conversion factor (tons/scf-%
CO2).
(iii) If the CO2 concentration is
measured on a dry basis, a correction for
the stack gas moisture content is
required. The owner or operator shall
either continuously monitor the stack
gas moisture content as described in
⎛ 100 − % H 2 O ⎞
*
CO2 = CO2 ⎜
⎟
100
⎝
⎠
Frm 00187
Fmt 4701
Sfmt 4702
§ 75.11(b)(2) of this chapter or, for
certain types of fuel, use a default
moisture percentage from § 75.11(b)(1)
of this chapter. For each unit operating
hour, a moisture correction must be
applied to Equation C–6 of this section
as follows:
(Eq. C-7)
(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 the entire
calendar year.
(vii) If both biogenic fuel and fossil
fuel are combusted during the year,
determine the biogenic CO2 mass
emissions separately, as described in
paragraph (e) of this section.
(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 may be used for any type
of fuel combusted in a unit with a
maximum rated heat input capacity of
250 mmBtu/hr or less, provided that:
PO 00000
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)(1)(iv)(D) 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:
(i) An applicable default CO2
emission factor and an applicable
default high heat value for the fuel are
specified in Table C–1 of this subpart.
(ii) The owner or operator does not
perform, or receive from the entity
supplying the fuel, the results of fuel
sampling and analysis on a monthly (or
more frequent) basis that includes
measurements of the HHV. If the owner
or operator performs such fuel sampling
and analysis or receives such fuel
sampling and analysis results, the Tier
1 Calculation Methodology shall not be
used, and the Tier 2, Tier 3, or Tier 4
Calculation Methodology shall be used
instead.
(2) The Tier 1 Calculation
Methodology may also be used to
calculate the biogenic CO2 emissions
from a unit of any size that combusts
wood, wood waste, or other solid
biomass-derived fuels, except when the
Tier 4 Calculation Methodology is used
to quantify the total CO2 mass
emissions. If the Tier 4 Calculation
Methodology is used, the biogenic CO2
emissions shall be calculated according
to paragraph (e) of this section.
(3) The Tier 2 Calculation
Methodology may be used for any type
of fuel combusted in any unit with a
maximum rated heat input capacity of
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.009</GPH>
(iv) In applying Equation C–5 of this
section to natural gas combustion, the
CO2 mass emissions are calculated only
for those months in which natural gas
is combusted during the reporting year.
For the combustion of other gaseous
fuels (e.g., refinery gas or process gas),
the CO2 mass emissions are calculated
only for those days on which the
gaseous fuel is combusted during the
reporting year. For example, if the unit
combusts process gas on 250 of the 365
days in the year, then n = 250 in
Equation C–5 of this section.
(4) Tier 4 Calculation Methodology.
Calculate the annual CO2 mass
emissions from all fuels combusted in a
unit, by using quality-assured data from
EP10AP09.008</GPH>
(CC)n = Average carbon content of the
gaseous fuel, from the fuel analysis
results for the day or month, as
applicable (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel,
from fuel analysis (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
16633
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(E) The installed CEMS include a gas
monitor of any kind, a stack gas
volumetric flow rate monitor, or both
and the monitors have been certified in
accordance with the requirements of
part 75 of this chapter, part 60 of this
chapter, or an applicable State
continuous monitoring program.
(F) The installed gas and/or stack gas
volumetric flow rate monitors are
required, by an applicable Federal or
State regulation or the unit’s operating
permit, to undergo periodic quality
assurance testing in accordance with
appendix B to part 75 of this chapter,
appendix F to 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
tons of MSW per day or less, if the unit:
(A) Has both a stack gas volumetric
flow rate monitor and a CO2
concentration monitor.
(B) The unit meets the other
conditions specified in paragraphs
(b)(5)(ii)(B) and (C) of this section.
(C) The CO2 and stack gas volumetric
flow rate monitors meet the conditions
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
the fuel, derived from the electronic data
report required under § 75.64 of this
chapter (mmBtu).
(Eq. C-8)
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C–3 of this subpart (kg
CH4 or N2O per mmBtu).
1 x 10¥3 = Conversion factor from kg to
metric tons.
(2) For all other units, use the
applicable equations and procedures in
paragraphs (c)(2) through (4) of this
CH 4 or N 2 O = 1 x 10−3 ∗ Fuel ∗ HHV ∗ EF
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,
from company records (mass or volume
per year).
section to calculate the annual CH4 and
N2O emissions.
(i) If a default high heat value for a
particular fuel is specified in Table C–
1 of this subpart and if the HHV is not
measured or provided by the entity
supplying the fuel on a monthly (or
more frequent) basis throughout the
year, use Equation C–9 of this section:
(Eq. C-9)
HHV = Default high heat value of the fuel
from Table C–1 of this subpart (mmBtu
per mass or volume).
EF = Fuel-specific default emission factor for
CH4 or N2O, from Table C–3 of this
subpart (kg CH4 or N2O per mmBtu).
1 x 10¥3 = Conversion factor from kilograms
to metric tons.
(ii) If the high heat value of a
particular fuel (except for municipal
solid waste) is measured on a monthly
(or more frequent) basis throughout the
year, or if such data are provided by the
entity supplying the fuel, use Equation
C–10a of this section:
n
CH 4 or N 2 O = ∑1 x 10−3 ∗ ( Fuel ) p ∗ ( HHV ) p ∗ EF
(Eq. C-10a)
p =1
Where:
VerDate Nov<24>2008
CH4 or N2O = Annual CH4 or N2O emissions
from the combustion of a particular type
of fuel (metric tons).
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00188
Fmt 4701
Sfmt 4702
n = Number of required heat content
measurements for the year.
(Fuel)p = Mass or volume of the fuel
combusted during the measurement
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.012</MATH>
CH 4 or N 2 O = 1 x 10−3 ∗ (HI ) A ∗ EF
specified in paragraphs (b)(5)(ii)(D)
through (b)(5)(ii)(F) of this section.
(6) The Tier 4 Calculation
Methodology, if selected or required,
shall be used beginning on:
(i) January 1, 2010, for a unit 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) 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, the owner or operator shall use the
Tier 3 Calculation Methodology in 2010.
(c) Calculation of CH4 and N2O
emissions from all fuel combustion.
Calculate the annual CH4 and N2O mass
emissions from stationary fuel
combustion sources as follows:
(1) For units subject to the
requirements of the Acid Rain Program
and for other units monitoring and
reporting heat input on a year-round
basis according to § § 75.10(c) and 75.64
of this chapter, use Equation C–8 of this
section:
EP10AP09.011</MATH>
250 mmBtu/hr or less, provided that a
default CO2 emission factor for the fuel
is specified in Table C–1 or C–2 of this
subpart.
(4) The Tier 3 Calculation
Methodology may be used for a unit of
any size, combusting any type of fuel,
except when the use of Tier 4 is
required or elected, as provided in
paragraph (b)(5) of this section.
(5) The Tier 4 Calculation
Methodology:
(i) May be used for a unit of any size,
combusting any type of fuel.
(ii) Shall be used for a unit if:
(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 tons per day of MSW.
(B) The unit combusts solid fossil fuel
or MSW, either as a 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.
EP10AP09.010</GPH>
16634
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
EF = Fuel-specific default emission factor for
CH4 or N2O, from Table C–3 of this
subpart (kg CH4 or N2O per mmBtu).
1 x 10 3 = Conversion factor from
kilograms to metric tons.
CH 4 or N 2 O = 1 x 10−3 ( Steam) ( B) ( EF )
is equipped with a wet flue gas
desulfurization system, or uses other
acid gas emission controls with sorbent
injection, use the following equation to
calculate the CO2 emissions from the
sorbent, if those CO2 emissions are not
monitored by CEMS:
⎛ MWCO 2 ⎞
CO2 = S ∗ R ∗ ⎜
⎟
⎝ MWS ⎠
Where:
CO2 = CO2 emitted from sorbent for the
reporting year (metric tons).
S = Limestone or other sorbent used in the
reporting year (metric tons).
R = Ratio of moles of CO2 released upon
capture of one mole of acid gas.
MWCO2 = Molecular weight of carbon dioxide
(44).
MWS = Molecular weight of sorbent (100, if
calcium carbonate).
(2) The total annual CO2 mass
emissions for the unit shall be the sum
of the CO2 emissions from the
combustion process and the CO2
emissions from the sorbent.
(e) Biogenic CO2 emissions. If any fuel
combusted in the unit meet the
definition of biomass or biomassderived fuel in § 98.6, then the owner or
(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
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
100
∗ Qh ∗ th
(Eq. C-12)
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.
V ff =
Fuel ∗ Fc ∗ GCV
106
(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 (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 part 75 of
PO 00000
Frm 00189
Fmt 4701
Sfmt 4725
this chapter or a site-specific value
determined under section 3.3.6 of
appendix F to part 75 of this chapter (scf
CO2/mmBtu).
GCV = Gross calorific 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).
10 6 = Conversion factor, Btu per mmBtu.
(iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biogenic fuels.
(v) Calculate the biogenic percentage
of the annual CO2 emissions, using
Equation C–14 of this section:
% Biogenic =
E:\FR\FM\10APP2.SGM
10APP2
Vbio
x 100
Vtotal
(Eq. C-14)
EP10AP09.017</MATH>
( %CO2 )h
EP10AP09.016</MATH>
VCO 2 h =
Where:
VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly CO2 concentration,
measured by the CO2 concentration
monitor (%CO2).
Qh = Hourly 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.
(Eq. C-11)
operator shall estimate and report the
total annual biogenic CO2 emissions,
according to paragraph (e)(1), (2), (3), or
(4) of this section, as applicable.
(1) The owner or operator may use
Equation C–1 of this section to calculate
the annual CO2 mass emissions from the
combustion of biogenic fuel, for a unit
of any size, provided that:
(i) The Tier 4 calculation
methodology is not required or elected.
(ii) The biogenic fuel consists of
wood, wood waste, or other biomassderived solid fuels (except for MSW).
(2) If CEMS are used to determine the
total annual CO2 emissions, either
according to part 75 of this chapter or
the Tier 4 Calculation Methodology of
this section and if both fossil fuel and
biogenic fuel (except for MSW) are
combusted in the unit during the
reporting year, 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:
(i) For each operating hour, use
Equation C–12 of this section to
determine the volume of CO2 emitted.
EP10AP09.015</MATH>
(3) Multiply the result from Equations
C–8, C–9, C–10a, or C–10b of this
section (as applicable) by the global
warming potential (GWP) factor to
convert the CH4 or N2O emissions to
metric tons of CO2 equivalent.
(4) If, for a particular type of fuel,
default CH4 and N2O emission factors
are not provided in Table C–4 of this
subpart, the owner or operator may,
subject to the approval of the
Administrator, develop site-specific CH4
and N2O emission factors, based on the
results of source testing.
(d) Calculation of CO2 from sorbent.
(1) When a unit is a fluidized bed boiler,
(Eq. C-10b)
EP10AP09.014</MATH>
Where:
CH4 or N2O = Annual CH4 or N2O emissions
from the combustion of a municipal
solid waste (metric tons).
Steam = Total mass of steam generated by
MSW 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–3 of this subpart (kg
CH4 or N2O per mmBtu).
1 x 10 3 = Conversion factor from
kilograms to metric tons.
(iii) For municipal solid waste
combustion, use Equation C–10b of this
section to estimate CH4 and N2O
emissions:
EP10AP09.013</MATH>
period ‘‘p’’ (mass or volume per unit
time).
(HHV)p = Measured high heat value of the
fuel for period ‘‘p’’ (mmBtu per mass or
volume).
p = Measurement period (day or month, as
applicable).
16635
16636
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(vi) Calculate the annual biogenic CO2
mass emissions, in metric tons, by
multiplying the percent Biogenic
obtained from Equation C–14 of this
section of this section by the total
annual CO2 mass emissions in metric
tons, as determined under paragraph
(a)(1)(iv) of this section.
(3) For a unit that combusts MSW, the
owner or operator shall use, for each
quarter, ASTM Methods D 6866–06a
and D 7459–08, as described in
§ 98.34(f), to determine the relative
proportions of biogenic and nonbiogenic CO2 emissions when MSW is
combusted. The results of each
determination shall be expressed as a
decimal fraction (e.g., 0.30, if 30 percent
of the CO2 from MSW combustion is
biogenic), and the quarterly values shall
be averaged over the reporting year. The
annual biogenic CO2 emissions shall be
calculated as follows:
(i) If the unit qualifies for the Tier 2
or Tier 3 Calculation Methodology of
this section and the owner or operator
elects to use the Tier 2 or Tier 3
Calculation Methodology to quantify
GHG emissions:
(A) Use Equations C–2a, C–2b and C–
3 of this section, as applicable, to
calculate the annual CO2 mass
emissions from MSW combustion and
from any auxiliary fuels such as natural
gas. Sum these values, to obtain the total
annual CO2 mass emissions from the
unit.
(B) Determine the annual biogenic
CO2 mass emissions from MSW
combustion as follows. Multiply the
total annual CO2 mass emissions from
MSW combustion by the biogenic
decimal fraction obtained from ASTM
Methods D 6866–06a and D 7459–08.
(ii) If the unit uses CEMS 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 total annual volume of CO2
emissions from MSW combustion.
(D) Determine the annual volume of
biogenic CO2 emissions from MSW
combustion as follows. Multiply the
annual volume of CO2 emissions from
MSW combustion by the biogenic
decimal fraction obtained from ASTM
Methods D 6866–06a and D 7459–08.
(E) Calculate the biogenic percentage
of the total 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
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
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) of this section.
(4) For biogas combustion, the Tier 2
or Tier 3 Calculation Methodology shall
be used to determine the annual
biogenic CO2 mass emissions, except as
provided in paragraph (e)(2) of this
section.
§ 98.34 Monitoring and QA/QC
requirements.
The CO2 mass emissions data for
stationary combustion units shall be
quality-assured as follows:
(a) For units using the calculation
methodologies described in this
paragraph, the records required under
§ 98.3(g) shall include both the company
records and a detailed explanation of
how company records are used to
estimate the following:
(1) Fuel consumption, when the Tier
1 and Tier 2 Calculation Methodologies
described in § 98.33(a) are used.
(2) Fuel consumption, when solid fuel
is combusted and the Tier 3 Calculation
Methodology in § 98.33(a)(3) is used.
(3) Fossil fuel consumption, when,
pursuant to § 98.33(e), the owner or
operator of a unit that uses CEMS to
quantify CO2 emissions and that
combusts both fossil and biogenic fuels
separately reports the biogenic portion
of the total annual CO2 emissions.
(4) Sorbent usage, if the methodology
in § 98.33(d) is used to calculate CO2
emissions from sorbent.
(b) The owner or operator shall
document the procedures used to ensure
the accuracy of the estimates of fuel
usage and sorbent usage (as applicable)
in paragraph (a) of this section,
including, but not limited to, calibration
of weighing equipment, fuel 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.
(c) For the Tier 2 Calculation
Methodology, the applicable fuel
sampling and analysis methods
incorporated by reference in § 98.7 shall
be used to determine the high heat
values. For coal, the samples shall be
taken at a location in the fuel handling
system that provides a sample
representative of the fuel bunkered or
consumed. The minimum frequency of
the sampling and analysis for each type
of fuel (only for the weeks or months
when that fuel is combusted in the unit)
is as follows:
PO 00000
Frm 00190
Fmt 4701
Sfmt 4702
(1) Monthly, for natural gas, biogas,
fuel oil, and other liquid fuels.
(2) For coal and other solid fuels,
weekly sampling is required to obtain
composite samples, which are analyzed
monthly.
(d) For the Tier 3 Calculation
Methodology:
(1) All oil and gas flow meters (except
for gas billing meters) shall be calibrated
prior to the first year for which GHG
emissions are reported under this part,
using an applicable flow meter test
method listed in § 98.7 or the calibration
procedures specified by the flow meter
manufacturer. Fuel flow meters shall be
recalibrated either annually or at the
minimum frequency specified by the
manufacturer.
(2) Oil tank drop measurements (if
applicable) shall be performed
according to one of the methods listed
in § 98.7.
(3) The carbon content of the fuels
listed in paragraphs (c)(1) and (2) of this
section shall be determined monthly.
For other gaseous fuels (e.g., refinery
gas, or process gas), daily sampling and
analysis is required to determine the
carbon content and molecular weight of
the fuel. An applicable method listed in
§ 98.7 shall be used to determine the
carbon content and (if applicable)
molecular weight of the fuel.
(e) For the Tier 4 Calculation
Methodology, the CO2 and flow rate
monitors must be certified prior to the
applicable deadline specified in
§ 98.33(b)(6).
(1) For initial certification, use the
following procedures:
(i) Section 75.20(c)(2) and (4) and
appendix A to 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 (for the CO2
concentration monitor) and Performance
Specification 6 in appendix B to part 60
(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 part 75 of
this chapter, 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
appendix B to part 75 of this chapter,
appendix F to part 60 of this chapter, or
an applicable State continuous
monitoring program. If appendix F to
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
part 60 of this chapter is selected for ongoing quality assurance, perform daily
calibration drift (CD) assessments for
both the CO2 and flow rate monitors,
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 part
75 of this chapter and the annual
RATAs of the CERMS required by
appendix F to 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.
(f) When municipal solid waste
(MSW) is combusted in a unit, the
biogenic portion of the CO2 emissions
from MSW combustion shall be
determined using ASTM D6866–06a
and ASTM D7459–08. The ASTM
D6866–06a analysis shall be performed
at least once in every calendar quarter
in which MSW is combusted in the unit.
Each gas sample shall be taken using
ASTM D7459–08, 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 necessary to obtain a sample large
enough to meet the specifications of
ASTM D6866–06a. The owner or
operator shall separate total CO2
emissions from MSW combustion in to
biogenic emissions and non-biogenic
emissions, using the average proportion
of biogenic emissions of all samples
analyzed during the reporting year. If
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.
§ 98.35
data.
Procedures for estimating missing
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,
the applicable missing data substitution
procedures in part 75 of this chapter
shall be followed for CO2 concentration,
stack gas flow rate, fuel flow rate, gross
calorific value (GCV), and fuel carbon
content.
(b) For all units that are not subject to
the requirements of the Acid Rain
Program, when the Tier 1, Tier 2, Tier
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
3, or Tier 4 calculation is used, perform
missing data substitution as follows for
each parameter:
(1) For each missing value of the heat
content, carbon content, or molecular
weight of the fuel, and for each missing
value of CO2 concentration and percent
moisture, the substitute data value shall
be the arithmetic average of the qualityassured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
(2) For missing records of stack gas
flow rate, fuel usage, and sorbent usage,
the substitute data value shall be the
best available estimate of the flow rate,
fuel usage, or sorbent consumption,
based on all available process data (e.g.,
steam production, electrical load, and
operating hours). The owner or operator
shall document and keep 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 paragraph (b) and (c)
of this section (as applicable) and the
emissions verification data in paragraph
(d) of this section.
(b) Unit-level emissions data
reporting. Except where aggregation of
unit-level information is permitted
under paragraph (c) of this section, the
owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A code representing the type of
unit.
(3) Maximum rated heat input
capacity of the unit, in mmBtu/hr
(boilers, combustion turbines, engines,
and process heaters only).
(4) Each type of fuel combusted in the
unit during the report year.
(5) The calculated CO2, CH4, and N2O
emissions for each type of fuel
combusted, expressed in metric tons of
each gas and in metric tons of CO2e.
(6) The method used to calculate the
CO2 emissions for each type of fuel
combusted (e.g., part 75 of this chapter
or the Tier 1 or Tier 2 calculation
methodology)
(7) If applicable, indicate which one
of the monitoring and reporting
methodologies in part 75 of this chapter
was used to quantify the CO2 emissions
(e.g., CEMS, appendix G, LME).
(8) The calculated CO2 emissions from
sorbent (if any), expressed in metric
tons.
PO 00000
Frm 00191
Fmt 4701
Sfmt 4702
16637
(9) The total GHG emissions from the
unit for the reporting year, i.e., the sum
of the CO2, CH4, and N2O emissions for
all fuel types, expressed in metric tons
of CO2e.
(c) Reporting alternatives for
stationary combustion units. For
stationary combustion units, the
following reporting alternatives may be
used to simplify the unit-level reporting
required under paragraph (b) of this
section:
(1) Aggregation of small units. If a
facility contains two or more units (e.g.,
boilers or combustion turbines) that
have a combined maximum rated heat
input capacity of 250 mmBtu/hr or less,
the owner or operator may report the
combined emissions for the group of
units in lieu of reporting separately the
GHG emissions from the individual
units, provided that the amount of each
type of fuel combusted in the units in
the group is accurately quantified. More
than one such group of units may be
defined at a facility, so long as the
aggregate maximum rated heat input
capacity of the units in the group does
not exceed 250 mmBtu/hr. 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) The ID number of each unit in the
group.
(iii) Cumulative maximum rated heat
input capacity of the group (mmBtu/hr).
(iv) Each type of fuel combusted in
the units during the reporting year.
(v) The calculated CO2, CH4, and N2O
mass emissions for each type of fuel
combusted in the group of units during
the year, expressed in metric tons of
each gas and in metric tons of CO2e.
(vi) The methodology used to
calculate the CO2 mass emissions for
each type of fuel combusted in the
units.
(vii) The calculated CO2 mass
emissions (if any) from sorbent.
(viii) The total GHG emissions from
the group for the year, i.e., the sum of
the CO2, CH4, and N2O emissions across,
all fuel types, expressed in metric tons
of CO2e.
(2) Monitored common stack
configurations. When the flue gases
from two or more stationary combustion
units at a facility are discharged through
a common stack, if CEMS are used to
continuously monitor CO2 mass
emissions at the common stack
according to part 75 of this chapter or
as described in the Tier 4 Calculation
Methodology in § 98.33(a)(4), the owner
or operator may report the combined
emissions from the units sharing the
E:\FR\FM\10APP2.SGM
10APP2
16638
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
common stack, in lieu of reporting
separately the GHG emissions from the
individual units. If this option is
selected, the following information shall
be reported instead of the information in
paragraph (b) of this section:
(i) Common stack ID number,
beginning with the prefix ‘‘CS’’.
(ii) ID numbers of the units sharing
the common stack.
(iii) Maximum rated heat input
capacity of each unit sharing the
common stack (mmBtu/hr).
(iv) Each type of fuel combusted in
the units during the year.
(v) The methodology used to calculate
the CO2 mass emissions (i.e., CEMS or
the Tier 4 Calculation Methodology).
(vi) The total CO2 mass emissions
measured at the common stack for the
year, expressed in metric tons of CO2e.
(vii) The combined annual CH4 and
N2O emissions from the units sharing
the common stack, expressed in metric
tons of each gas and in metric tons of
CO2e.
(A) If the monitoring is done
according to part 75 of this chapter, use
Equation C–8 of this subpart, where the
term ‘‘(HI)A’’ is the cumulative annual
heat input measured at the common
stack.
(B) For the Tier 4 calculation
methodology, use Equation C–9, C–10a
or C–10b of this subpart separately for
each type of fuel combusted in the units
during the year, and then sum the
emissions for all fuel types.
(viii) The total GHG emissions for the
year from the units that share the
common stack, 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 oil-fired or gas-fired
stationary combustion units at a facility
combust the same type of fuel and that
fuel is fed to the individual units
through a common supply line or pipe,
the owner or operator may report the
combined emissions from the units
served by the common supply line, in
lieu of reporting separately 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 calibrated fuel flow meter.
If this option is selected, the following
information shall be reported instead of
the information in paragraph (b) of this
section:
(i) Common pipe ID number,
beginning with the prefix ‘‘CP’’.
(ii) ID numbers of the units served by
the common pipe.
(iii) Maximum rated heat input
capacity of each unit served by the
common pipe (mmBtu/hr).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(iv) The type of fuel combusted in the
units during the reporting year.
(v) The methodology used to calculate
the CO2 mass emissions.
(vi) The total CO2 mass emissions
from the units served by the common
pipe for the reporting year, expressed in
metric tons of CO2e.
(vii) The combined annual CH4 and
N2O emissions from the units served by
the common pipe, expressed in metric
tons of each gas and in metric tons of
CO2e.
(viii) The total GHG emissions for the
reporting year from the units served by
the common pipe, i.e., the sum of the
CO2, CH4, and N2O emissions, expressed
in metric tons of CO2e.
(d) Verification data. The owner or
operator shall report sufficient data and
supplementary information to verify the
reported GHG emissions.
(1) For stationary combustion sources
using the Tier 1, Tier 2, Tier 3, or Tier
4 Calculation Methodology in
§ 98.33(a)(4) to quantify CO2 emissions,
the following additional information
shall be included in the GHG emissions
report:
(i) For the Tier 1 Calculation
Methodology, report the total quantity
of each type of fuel combusted during
the reporting year, in short tons for solid
fuels, gallons for liquid fuels and scf for
gaseous fuels.
(ii) For the Tier 2 Calculation
Methodology, report:
(A) The total quantity of each type of
fuel combusted during each month
(except for MSW). Express the quantity
of each fuel combusted during the
measurement period in short tons for
solid fuels, gallons for liquid fuels, and
scf for gaseous fuels.
(B) The number of required high heat
value determinations for each type of
fuel for the reporting year (i.e., ‘‘n’’ in
Equation C–2a of this subpart,
corresponding (as applicable) to the
number of operating days or months
when each type of fuel was combusted,
in accordance with § § 98.33(a)(2) and
98.34(c).
(C) For each month, the high heat
value used in Equation C–2a of this
subpart for each type of fuel combusted,
in mmBtu per short ton for solid fuels,
mmBtu per gallon for liquid fuels, and
mmBtu per scf for gaseous fuels.
(D) For each reported HHV, indicate
whether it is an actual measured value
or a substitute data value.
(E) Each method from § 98.7 used to
determine the HHV for each type of fuel
combusted.
(F) For MSW, the total quantity (i.e.,
lb) of steam produced from MSW
combustion during the year, and ‘‘B’’,
the ratio of the unit’s maximum rate
PO 00000
Frm 00192
Fmt 4701
Sfmt 4702
heat input capacity to its design rated
steam output capacity, in mmBtu per lb
of steam.
(iii) For the Tier 3 Calculation
Methodology, report:
(A) The total quantity of each type of
fuel combusted during each month or
day (as applicable), in metric tons for
solid fuels, gallons for liquid fuels, and
scf for gaseous fuels.
(B) The number of required carbon
content determinations for each type of
fuel for the reporting year,
corresponding (as applicable) to the
number of operating days or months
when each type of fuel was combusted,
in accordance with §§ 98.33(a)(3) and
98.34(d).
(C) For each operating month or day,
the carbon content (CC) value used in
Equation C–3, C–4, or C–5 of this
subpart (as applicable), expressed as a
decimal fraction for solid fuels, kg C per
gallon for liquid fuels, and kg C per kg
of fuel for gaseous fuels.
(D) For gaseous fuel combustion, the
molecular weight of the fuel used in
Equation C–5 of this subpart, for each
operating month or day, in kg per kgmole.
(E) For each reported CC value,
indicate whether it is an actual
measured value or a substitute data
value.
(F) For liquid and gaseous fuel
combustion, the dates and results of the
initial calibrations and periodic
recalibrations of the fuel flow meters
used to measure the amount of fuel
combusted.
(G) For fuel oil combustion, each
method from § 98.7 used to make tank
drop measurements (if applicable).
(H) Each method from § 98.7 used to
determine the CC for each type of fuel
combusted.
(I) Each method from § 98.7 used to
calibrate the fuel flow meters (if
applicable).
(iv) For the Tier 4 Calculation
Methodology, report:
(A) The total number of source
operating days and the total number of
source operating hours in the reporting
year.
(B) Whether the CEMS certification
and quality assurance procedures of part
75 of this chapter, part 60 of this
chapter, or an applicable State
continuous monitoring program have
been selected.
(C) The CO2 emissions on each
operating day, i.e., the sum of the hourly
values calculated from Equation C–6 or
C–7 (as applicable), in metric tons.
(D) For CO2 concentration, stack gas
flow rate, and (if applicable) stack gas
moisture content, the number of source
operating hours in which a substitute
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
data value of each parameter was used
in the emissions calculations.
(E) The dates and results of the initial
certification tests of the CEMS, and
(F) The dates and results of the major
quality assurance tests performed on the
CEMS during the reporting year, i.e.,
linearity checks, cylinder gas audits,
and relative accuracy test audits
(RATAs).
(v) If CO2 emissions that are generated
from acid gas scrubbing with sorbent
injection are not captured using CEMS,
report:
(A) The total amount of sorbent used
during the report year, in metric tons.
(B) The molecular weight of the
sorbent.
(C) The ratio (‘‘R’’) in Equation C–11
of this subpart.
(vi) When ASTM methods D7459–08
and D6866–06a are used to determine
the biogenic portion of the annual CO2
emissions from MSW combustion, as
described in §§ 98.33(e) and 98.34(f), the
owner or operator shall report:
(A) The results of each quarterly
sample analysis, expressed as a decimal
fraction, e.g., if the biogenic fraction of
the CO2 emissions from MSW
combustion is 30 percent, report 0.30.
(B) The total quantity of MSW
combusted during the reporting year, in
short tons if the Tier 2 Calculation
Methodology is used or in metric tons
if the Tier 3 calculation methodology is
used.
(vii) For units that combust both fossil
fuel and biogenic fuel, when CEMS are
used to quantify the annual CO2
emissions, the owner or operator shall
report the following additional
information, as applicable:
(A) The annual volume of CO2
emitted from the combustion of all
fuels, i.e., Vtotal, in scf.
(B) The annual volume of CO2 emitted
from the combustion of fossil fuels, i.e.,
Vff, in scf. If more than one type of fossil
fuel was combusted, report the
combustion volume of CO2 for each fuel
separately as well as the total.
(C) The annual volume of CO2 emitted
from the combustion of biogenic fuels,
i.e., Vbio, in scf.
(D) The carbon-based F-factor used in
Equation C–14 of this subpart, for each
type of fossil fuel combusted, in scf CO2
per mmBtu.
(E) The annual average GCV value
used in Equation C–14 of this subpart,
for each type of fossil fuel combusted,
in Btu/lb, Btu/gal, or Btu/scf, as
appropriate.
(F) The total quantity of each type of
fossil fuel combusted during the
reporting year, in lb, gallons, or scf, as
appropriate.
(G) The total annual biogenic CO2
mass emissions, in metric tons.
(2) Within 7 days of receipt of a
written request (e.g., a request by
electronic mail) from the Administrator
or from the applicable State or local air
pollution control agency, the owner or
operator shall submit the explanations
described in § 98.34(a) and (b), as
follows:
(i) A detailed explanation of how
company records are used to quantify
fuel consumption, if Calculation
Methodology Tier 1 or Tier 2 of this
16639
subpart is used to calculate CO2
emissions.
(ii) A detailed explanation of how
company records are used to quantify
fuel consumption, if solid fuel is
combusted and the Tier 3 Calculation
Methodology in § 98.33(a)(3) is used to
calculate CO2 emissions.
(iii) A detailed explanation of how
sorbent usage is quantified, if the
methodology in § 98.33(d) is used to
calculate CO2 emissions from sorbent.
(iv) A detailed explanation of how
company records are used to quantify
fossil fuel consumption, when, as
described in § 98.33(e), the owner or
operator of a unit that combusts both
fossil fuel and biogenic fuel uses CEMS
to quantify CO2 emissions.
§ 98.37
Records that must be retained.
The recordkeeping requirements of
§ 98.3(g) and, if applicable, § 98.34(a)
and (b) shall be fully met for affected
facilities with stationary combustion
sources. Also, the records required
under § 98.35(a)(1), documenting the
data substitution procedures for missing
stack flow rate, fuel flow rate, fuel usage
and (if applicable) sorbent usage
information and site-specific source
testing (as allowed in § 98.33(c)(4)),
shall be retained. No special
recordkeeping beyond that specified in
§§ 98.3, 98.35(a)(4), and 98.34(a) and (b)
is required. All required records must be
retained for a period of five years.
§ 98.38
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE C–1 OF SUBPART C—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS TYPES OF FUEL
Fuel type
Default high heat
value
Default CO2
emission factor
Coal and Coke
mmBtu/short ton
kg CO2/mmBtu
Anthracite .....................................................................................................................................................
Bituminous ...................................................................................................................................................
Sub-bituminous ............................................................................................................................................
Lignite ..........................................................................................................................................................
Unspecified (Residential/Commercial) .........................................................................................................
Unspecified (Industrial Coking) ....................................................................................................................
Unspecified (Other Industrial) ......................................................................................................................
Unspecified (Electric Power) .......................................................................................................................
Coke .............................................................................................................................................................
Natural Gas
25.09
24.93
17.25
14.21
22.24
26.28
22.18
19.97
24.80
mmBtu/scf
Unspecified (Weighted U.S. Average) .........................................................................................................
Petroleum Products
1.027 x 10¥3
mmBtu/gallon
Asphalt & Road Oil ......................................................................................................................................
Aviation gasoline ..........................................................................................................................................
Distillate Fuel Oil (# 1, 2, & 4) .....................................................................................................................
Jet Fuel ........................................................................................................................................................
Kerosene ......................................................................................................................................................
LPG (energy use) ........................................................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00193
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
0.158
0.120
0.139
0.135
0.135
0.092
10APP2
103.54
93.40
97.02
96.36
95.26
93.65
93.91
94.38.
102.04
kg CO2/mmBtu.
53.02
kg CO2/mmBtu
75.55
69.14
73.10
70.83
72.25
62.98
16640
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE C–1 OF SUBPART C—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS TYPES OF FUEL—
Continued
Default high heat
value
Fuel type
Propane .......................................................................................................................................................
Ethane ..........................................................................................................................................................
Isobutane .....................................................................................................................................................
n-Butane ......................................................................................................................................................
Lubricants ....................................................................................................................................................
Motor Gasoline ............................................................................................................................................
Residual Fuel Oil (# 5 & 6) ..........................................................................................................................
Crude Oil ......................................................................................................................................................
Naphtha (< 401 deg. F) ...............................................................................................................................
Natural Gasoline ..........................................................................................................................................
Other Oil (> 401 deg. F) ..............................................................................................................................
Pentanes Plus ..............................................................................................................................................
Petrochemical Feedstocks ...........................................................................................................................
Petroleum Coke ...........................................................................................................................................
Special Naphtha ..........................................................................................................................................
Unfinished Oils .............................................................................................................................................
Waxes ..........................................................................................................................................................
Biomass-derived Fuels (solid)
Default CO2
emission factor
0.091
0.069
0.099
0.103
0.144
0.124
0.150
0.138
0.125
0.110
0.139
0.110
0.129
0.143
0.125
0.139
0.132
mmBtu/short Ton
Wood and Wood waste (12% moisture content) or other solid biomass-derived fuels ..............................
63.02
59.54
65.04
64.93
74.16
70.83
78.74
74.49
66.46
66.83
73.10
66.83
70.97
102.04
72.77
74.49
72.58
kg CO2/mmBtu
15.38
mmBtu/scf
kg CO2/mmBtu
Varies
Biomass-derived Fuels (Gas)
93.80
52.07
Biogas ..........................................................................................................................................................
Note: Heat content factors are based on higher heating values (HHV). Also, for petroleum products, the default heat content values have been
converted from units of mmBtu per barrel to mmBtu per gallon.
TABLE C–2 OF SUBPART C—DEFAULT CO2 EMISSION FACTORS FOR THE COMBUSTION OF ALTERNATIVE FUELS
Default CO2
emission factor
(kg CO2/mmBtu)
Fuel type
Waste Oil .....................................................................................................................................................................................
Tires .............................................................................................................................................................................................
Plastics .........................................................................................................................................................................................
Solvents .......................................................................................................................................................................................
Impregnated Saw Dust ................................................................................................................................................................
Other Fossil based wastes ..........................................................................................................................................................
Dried Sewage Sludge ..................................................................................................................................................................
Mixed Industrial waste .................................................................................................................................................................
Municipal Solid Waste .................................................................................................................................................................
74
85
75
74
75
80
110
83
90.652
Note: Emission factors are based on higher heating values (HHV). Values were converted from LHV to HHV assuming that LHV are 5 percent
lower than HHV for solid and liquid fuels.
TABLE C–3 OF SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL
Fuel type
Default CH4
emission factor
(kg CH4/mmBtu)
Asphalt .........................................................................................................................................................
Aviation Gasoline .........................................................................................................................................
Coal ..............................................................................................................................................................
Crude Oil ......................................................................................................................................................
Digester Gas ................................................................................................................................................
Distillate .......................................................................................................................................................
Gasoline .......................................................................................................................................................
Jet Fuel ........................................................................................................................................................
Kerosene ......................................................................................................................................................
Landfill Gas ..................................................................................................................................................
LPG ..............................................................................................................................................................
Lubricants ....................................................................................................................................................
Municipal Solid Waste .................................................................................................................................
Naphtha .......................................................................................................................................................
Natural Gas ..................................................................................................................................................
Natural Gas Liquids .....................................................................................................................................
Other Biomass .............................................................................................................................................
3.0
3.0
1.0
3.0
9.0
3.0
3.0
3.0
3.0
9.0
1.0
3.0
3.0
3.0
9.0
3.0
3.0
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00194
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
10¥3
10¥3
10¥2
10¥3
10¥4
10¥3
10¥3
10¥3
10¥3
10¥4
10¥3
10¥3
10¥2
10¥3
10¥4
10¥3
10¥2
Default N2O
emission factor
(kg N2O/mmBtu)
6.0
6.0
1.5
6.0
1.0
6.0
6.0
6.0
6.0
1.0
1.0
6.0
4.0
6.0
1.0
6.0
4.0
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
×
10¥4
10¥4
10¥3
10¥4
10¥4
10¥4
10¥4
10¥4
10¥4
10¥4
10¥4
10¥4
10¥3
10¥4
10¥4
10¥4
10¥3
16641
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE C–3 OF SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL—Continued
Fuel type
Default CH4
emission factor
(kg CH4/mmBtu)
Petroleum Coke ...........................................................................................................................................
Propane .......................................................................................................................................................
Refinery Gas ................................................................................................................................................
Residual Fuel Oil .........................................................................................................................................
Tites .............................................................................................................................................................
Waste Oil .....................................................................................................................................................
Waxes ..........................................................................................................................................................
Wood and Wood Waste ..............................................................................................................................
3.0
1.0
9.0
3.0
3.0
3.0
3.0
3.0
×
×
×
×
×
×
×
×
Default N2O
emission factor
(kg N2O/mmBtu)
10¥3
10¥3
10¥4
10¥3
10¥3
10¥2
10¥3
10¥2
6.0
1.0
1.0
6.0
6.0
4.0
6.0
4.0
×
×
×
×
×
×
×
×
10¥4
10¥4
10¥4
10¥4
10¥4
10¥3
10¥4
10¥3
Note: Values were converted from LHV to HHV assuming that LHV are 5 percent lower than HHV for solid and liquid fuels and 10 percent
lower for gaseous fuels. Those employing this table are assumed to fall under the IPCC definitions of the ‘‘Energy Industry’’ or ‘‘Manufacturing Industries and Construction’’. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC ‘‘Energy Industry’’ category may employ a value of 1 g of CH4/MMBtu.
Subpart D—Electricity Generation
§ 98.40
Definition of the source category.
(a) The electricity generation source
category comprises all facilities with
one or more electricity generating units,
including electricity generating units
that are subject to the requirements of
the Acid Rain Program.
(b) This source category does not
include portable equipment or
generating units designated as
emergency generators in a permit issued
by a State or local air pollution control
agency.
§ 98.41
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains one or more electricity
generating units and the facility meets
the requirements of either § 98.2(a)(1) or
(2).
§ 98.42
GHGs to report.
The annual mass emissions of CO2,
N2O, and CH4 shall be reported for each
electricity generating unit.
§ 98.43
Calculating GHG emissions.
(a) For each electricity generating unit
subject to the requirements of the Acid
Rain Program, the owner or operator
shall continue to monitor and report
CO2 mass emissions as required under
§§ 75.13 and 75.64 of this chapter. CO2
emissions for the purposes of the GHG
emissions reports required under
§§ 98.3 and 98.36 shall be calculated as
follows:
(1) The owner or operator shall
convert the cumulative annual CO2
mass emissions reported in the fourth
quarter electronic data report required
under § 75.64 of this chapter from units
of short tons to metric tons. To convert
tons to metric tons, divide by 1.1023.
(2) The annual CH4 and N2O mass
emissions shall be calculated using the
methods specified in § 98.33 for
stationary fuel combustion units.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(b) For each unit that is not subject to
the reporting requirements of the Acid
Rain Program, the annual CO2, CH4, and
N2O mass emissions shall be calculated
using the methods specified in § 98.33
for stationary fuel combustion units.
§ 98.44 Monitoring and QA/QC
requirements.
(a) For electricity generation units
subject to the requirements of the Acid
Rain Program, the CO2 emissions data
shall be quality assured according to the
applicable procedures in appendices B,
D, and G to part 75 of this chapter.
(b) For electricity generating units that
are not subject to the requirements of
the Acid Rain Program, the quality
assurance and quality control
procedures specified in § 98.34 for
stationary fuel combustion units shall
be followed.
§ 98.45
data.
Procedures for estimating missing
(a) For electricity generation units
subject to the requirements of the Acid
Rain Program, the applicable missing
data substitution procedures in part 75
of this chapter shall be followed for CO2
concentration, stack gas flow rate, fuel
flow rate, gross calorific value (GCV),
and fuel carbon content.
(b) For each electricity generating unit
that is not subject to the requirements of
the Acid Rain Program, the missing data
substitution procedures specified in
§ 98.35 for stationary fuel combustion
units shall be implemented.
§ 98.46
Data reporting requirements.
(a) For electricity generation units
subject to the requirements of the Acid
Rain Program, the owner or operator of
a facility containing one or more
electricity generating units shall meet
the data reporting requirements
specified in § 98.36(b) and, if applicable,
§ 98.36(c)(2) or (3).
(b) For electricity generating units not
subject to the requirements of the Acid
PO 00000
Frm 00195
Fmt 4701
Sfmt 4702
Rain Program, the owner or operator of
a facility containing one or more
electricity generating units shall meet
the data reporting and verification
requirements specified in § 98.36.
§ 98.47
Records that must be retained.
The owner or operator of a facility
containing one or more electricity
generating units shall meet the
recordkeeping requirements of § 98.3(g)
and, if applicable, § 98.37.
§ 98.48
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart E—Adipic Acid Production
§ 98.50
Definition of source category.
The adipic acid production source
category consists of all adipic acid
production facilities that use oxidation
to produce adipic acid.
§ 98.51
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an adipic acid production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.52
GHGs to report.
(a) You must report N2O process
emissions from adipic acid production
as required by this subpart.
(b) You must report CO2, CH4, and
N2O emissions from each stationary
combustion unit that uses a carbonbased fuel, following the requirements
of subpart C of this part.
§ 98.53
Calculating GHG emissions.
You must determine annual N2O
emissions from adipic acid production
using a facility-specific emission factor
according to paragraphs (a) through (e)
of this section.
(a) You must conduct an annual
performance test to measure N2O
emissions from the waste gas streams of
E:\FR\FM\10APP2.SGM
10APP2
16642
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
each adipic acid oxidation process. You
must conduct the performance test
under normal process operating
conditions.
(b) You must conduct the emissions
test using the methods specified in
§ 98.54(b).
(c) You must measure the adipic acid
production rate for the facility during
the test and calculate the production
CN 2O ∗1.14 × 10−7 ∗ Q
∑
P
= 1
n
rate for the test period in metric tons per
hour.
(d) You must calculate an average
facility-specific emission factor
according to Equation E–1 of this
section:
n
1.14x10¥7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas
(dscf/hr).
P = Production rate during performance test
(tons adipic acid produced/hr).
n = Number of test runs.
EN 2 O =
Where:
EN2O = N2O mass emissions per year (metric
tons of N2O).
EFN2O = Facility-specific N2O emission factor
(lb N2O/ton adipic acid produced).
Pa = Total production for the year (ton adipic
acid produced).
DFN = Destruction factor of N2O abatement
technology (abatement device
manufacturer’s specified destruction
efficiency, percent of N2O removed from
air stream).
AFN = Abatement factor of N2O abatement
technology (percent of year that
abatement technology was used).
2205 = Conversion factor (lb/metric ton).
§ 98.54 Monitoring and QA/QC
requirements.
(a) You must conduct a new
performance test and calculate a new
facility-specific emissions factor at least
annually. You must also conduct a new
performance test whenever the
production rate is changed by more than
10 percent from the production rate
measured during the most recent
performance test. The new emissions
factor may be calculated using all
available performance test data (i.e.,
average with the data from previous
years), except in cases where process
modifications have occurred or
operating conditions have changed.
Only the data consistent with the
reporting period after the changes were
implemented shall be used.
(b) You must conduct each emissions
test using EPA Method 320 in 40 CFR
part 63, Appendix A or ASTM D6348–
03 (incorporated by reference—see
§ 98.7) to measure the N2O
concentration in conjunction with the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
EFN2O ∗ Pa ∗ (1 − DFN ) ∗ AFN
2205
(Eq. E-2)
applicable EPA methods in 40 CFR part
60, appendices A–1 through A–4.
Conduct three emissions test runs of 1
hour each.
(c) Each facility must conduct all
required performance tests according to
a test plan and EPA Method 320 in 40
CFR part 63, appendix A or ASTM
D6348–03 (incorporated by referencesee § 98.7). All QA/QC procedures
specified in the reference test methods
and any associated performance
specifications apply. For each test, the
facility must prepare an emission factor
determination report that must include
the items in paragraphs (c)(1) through
(3) of this section:
(1) Analysis of samples,
determination of emissions, and raw
data.
(2) All information and data used to
derive the emissions factor.
(3) The production rate during the test
and how it was determined. The
production rate can be determined
through sales records, or through direct
measurement using flow meters or
weigh scales.
§ 98.55
data.
Procedures for estimating missing
Procedures for estimating missing
data are not provided for N2O process
emissions for adipic acid production
facilities calculated according to § 98.53.
A complete record of all measured
parameters used in the GHG emissions
calculations is required.
§ 98.56
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
PO 00000
Frm 00196
Fmt 4701
Sfmt 4702
(e) You must calculate annual adipic
acid production process emissions of
N2O for the facility by multiplying the
emissions factor by the total annual
adipic acid production at the facility,
according to Equation E–2 of this
section:
must contain the information specified
in paragraphs (a) through (h) of this
section for each adipic acid production
facility:
(a) Annual N2O emissions from adipic
acid production in metric tons.
(b) Annual adipic acid production
capacity (in metric tons).
(c) Annual adipic acid production, in
units of metric tons of adipic acid
produced.
(d) Number of facility operating hours
in calendar year.
(e) Emission rate factor used (lb N2O/
ton adipic acid).
(f) Abatement technology used (if
applicable).
(g) Abatement technology efficiency
(percent destruction).
(h) Abatement utilization factor
(percent of time that abatement system
is operating).
§ 98.57
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the records specified in paragraphs (a)
through (f) of this section at the facility
level:
(a) Annual N2O emissions from adipic
acid production, in metric tons.
(b) Annual adipic acid production
capacity, in metric tons.
(c) Annual adipic acid production, in
units of metric tons of adipic acid
produced.
(d) Number of facility operating hours
in calendar year.
(e) Measurements, records and
calculations used to determine the
annual production rate.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.019</GPH>
Where:
EFN2O = Average facility-specific N2O
emissions factor (lb N2O/ton adipic acid
produced).
CN2O = N2O concentration during
performance test (ppm N2O).
(Eq. E-1)
EP10AP09.018</GPH>
EFN 2O
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
aluminum manufacturing process
comprises the following operations:
(1) Electrolysis in prebake and
S<derberg cells.
(2) Anode baking for prebake cells.
(b) This source category does not
include experimental cells or research
and development process units.
§ 98.60
Definition of the source category.
(a) A primary aluminum production
facility manufactures primary
´
aluminum using the Hall-Heroult
manufacturing process. The primary
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an aluminum production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.62
GHGs to report.
You must report:
(a) Total perfluoromethane (CF4), and
perfluoroethane (C2F6) emissions from
E CF 4 = SCF 4 × AEM × MP × 0.001
Where:
ECF4 = Monthly CF4 emissions from
aluminum production (metric tons CF4).
SCF4 = The slope coefficient ((kg CF4/metric
ton Al)/(AE-Mins/cell-day)).
AEM = The anode effect minutes per cell-day
(AE-Mins/cell-day).
(b) Use the following procedures to
calculate CO2 emissions from anode
consumption during electrolysis:
Where:
ECO2 = Annual CO2 emissions from prebaked
anode consumption (metric tons CO2).
NAC = Net annual prebaked anode
consumption per metric ton Al (metric
tons C/metric tons Al).
([100
MP = Metal production (metric tons Al).
where AEM and MP are calculated
monthly.
(Eq. F-2)
0.001 = Conversion factor from kg to metric
tons, where ECF4 is calculated monthly.
E CO 2 = NAC × MP ×
Calculating GHG emissions.
(a) Use Equation F–1 of this section to
estimate CF4 emissions from anode
effects, and use Equation F–2 to
estimate C2F6 emissions from anode
effects from each prebake and S<derberg
electrolysis cell.
(Eq. F-1)
E C 2 F6 = E CF 4 × FC 2 F6 / CF 4 × 0.001
Where:
EC2F6 = Monthly C2F6 emissions from
aluminum production (metric tons C2F6).
ECF4 = CF4 emissions from aluminum
production (kg CF4).
FC2F6/CF4 = The weight fraction of C2F6/CF4
(kg C2F6/kg CF4).
§ 98.63
(1) For Prebake cells: You must
calculate CO2 emissions from anode
consumption using Equation F–3 of this
section:
− Sa − Ash a ] /100 ) × (44 / 12)
MP = Total annual metal production (metric
tons Al).
Sa = Sulfur content in baked anode (percent
weight).
Asha = Ash content in baked anode (percent
weight).
(Eq. F-3)
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) For S<derberg cells you must
calculate CO2 emissions using Equation
F–4 of this section:
E CO 2 = (PC x MP − [ CSM x MP ] /1000 − BC /100 × PC ×
MP × ⎡Sp + Ash p + H p ⎤ /100 − [100 − BC] /100 × PC × MP ×
⎣
⎦
Sc + Ash c ] /100 − MP × CD × (44 /12)
[
Where:
ECO2 = Annual CO2 emissions from paste
consumption (metric ton CO2).
PC = Annual paste consumption (metric ton/
metric ton Al).
MP = Total annual metal production (metric
ton Al).
CSM = Annual emissions of cyclohexane
soluble matter (kg/metric ton Al).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
BC = Binder content of paste (percent
weight).
Sp = Sulfur content of pitch (percent weight).
Ashp = Ash content of pitch (percent weight).
Hp = Hydrogen content of pitch (percent
weight).
Sc = Sulfur content in calcined coke (percent
weight).
Ashc = Ash content in calcined coke (percent
weight).
PO 00000
Frm 00197
Fmt 4701
Sfmt 4702
(Eq. F-4)
CD = Carbon in skimmed dust from
S<derberg cells (metric ton C/metric ton
Al).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(c) Use the following procedures to
calculate CO2 emissions from anode
baking of prebake cells:
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.023</MATH>
Subpart F—Aluminum Production
§ 98.61
EP10AP09.022</MATH>
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
EP10AP09.021</MATH>
§ 98.58
anode effects in all prebake and
S<derberg electrolysis cells.
(b) Total CO2 emissions from anode
consumpton during electrolysis in all
prebake and S<derberg electrolysis cells.
(c) Total CO2 emissions from anode
baking for all prebake cells.
(d) For CO2, N2O, and CH4 emissions
from stationary fuel combustion units,
you must follow the requirements in
subpart C of this part.
EP10AP09.020</MATH>
(f) Emission rate factor used and
supporting test or calculation
information including the annual
emission rate factor determination
report specified in § 98.54(c). This
report must be available upon request.
16643
16644
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(1) Use Equation F–5 of this section to
calculate emissions from pitch
volatiles.
− H w − BA − WT ) × (44 /12)
Hw = Annual hydrogen content in green
anodes (metric tons).
BA = Annual baked anode production
(metric tons).
WT = Annual waste tar collected (metric
tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) Use Equation F–6 of this section to
calculate emissions from bake furnace
packing material.
)
E CO 2 PC = PCC × BA × ⎡100 − Spc − Ash pc ⎤ /100 × (44 /12)
⎣
⎦
Where:
ECO2PC = Annual CO2 emissions from bake
furnace packing material (metric tons
CO2).
PCC = Annual packing coke consumption
(metric tons/metric ton baked anode).
BA = Annual baked anode production
(metric tons).
Spc = Sulfur content in packing coke (percent
weight).
Ashpc = Ash content in packing coke (percent
weight).
44/12 = Ratio of molecular weights, CO2 to
carbon.
§ 98.64 Monitoring and QA/QC
requirements.
(a) The smelter-specific slope
coefficient must be measured at least
every 36 months in accordance with the
EPA/IAI Protocol for Measurement of
Tetrafluoromethane and
Hexafluoroethane Emissions from
Primary Aluminum Production (2008).
(b) The minimum frequency of the
measurement and analysis is annually
except as follows: Monthly—anode
effect minutes per cell day, production.
(c) Sources may use smelter-specific
values from annual measurements of
parameters needed to complete the
equations in § 98.63 (e.g., sulfur, ash,
and hydrogen contents), or may use
default values from Volume III, Section
4.4, in Chapter 4, of the 2006 IPCC
Guidelines for National Greenhouse Gas
Inventories.
ECO 2 = EFp x MPp + EFs x MPs
Where:
ECO2 = CO2 emissions from anode and/or
paste consumption, tonnes CO2.
EFp = Prebake technology specific emission
factor (1.6 tonnes CO2/tonne aluminum
produced).
MPp = Metal production from prebake
process (tonnes Al).
EFs = S<derberg technology specific emission
factor (1.7 tonnes CO2/tonne Al
produced).
MPs = Metal production from S<derberg
process (tonnes Al).
(b) For other parameters, use the
average of the two most recent data
points.
§ 98.66
Data reporting requirements.
In addition to the information
required by § 98.3(c), you must report
the following information at the facility
level:
(a) Annual aluminum production in
metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific
information on an annual basis:
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Frm 00198
Fmt 4701
Sfmt 4702
§ 98.65
data.
Procedures for estimating missing
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation or if a required sample
measurement is not taken), a substitute
data value for the missing parameter
shall be used in the calculations,
according to the following requirements:
(a) Where anode or paste
consumption data are missing, CO2
emissions can be estimated from
aluminum production using Tier 1
method per Equation F–7 of this section.
(Eq. F-7)
(1) Perfluoromethane emissions and
perfluoroethane emissions from anode
effects in all prebake and all S<derberg
electolysis cells combined.
(2) Anode effect minutes per cell-day,
anode effect frequency (AE/cell-day),
anode effect duration (minutes).
(3) Smelter-specific slope coefficient
and the last date when the smelterspecific-slope coefficient was measured.
(d) Method used to measure the
frequency and duration of anode effects.
(e) The following CO2-specific
information for prebake cells on an
annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the
smelter.
(f) The following CO2-specific
information for S<derberg cells on an
annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the
smelter.
(g) Smelter-specific inputs to the CO2
process equations (e.g., levels of sulfur
PO 00000
(Eq. F-6)
and ash) that were used in the
calculation, on an annual basis.
(h) Exact data elements required will
vary depending on smelter technology
(e.g., point-feed prebake or S<derberg).
§ 98.67
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the following records:
(a) Monthly aluminum production in
metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific
information on a monthly basis:
(1) Perfluoromethane and
perfluoroethane emissions from anode
effects in each prebake and S<derberg
electolysis cells.
(2) Anode effect minutes per cell-day,
anode effect frequency (AE/cell-day),
anode effect duration (minutes) from
each prebake and S<derberg electolysis
cells.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.026</GPH>
(
(Eq. F-5)
EP10AP09.025</GPH>
Where:
ECO2PV = Annual CO2 emissions from pitch
volatiles combustion (metric tons CO2).
GA = Initial weight of green anodes (metric
tons).
( GA
EP10AP09.024</GPH>
E CO 2 PV =
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Definition of source category.
The ammonia manufacturing source
category comprises the process units
listed in paragraphs (a) and (b) of this
section.
(a) Ammonia manufacturing processes
in which ammonia is manufactured
from a fossil-based feedstock produced
via steam reforming of a hydrocarbon.
(b) Ammonia manufacturing
processes in which ammonia is
manufactured through the gasification
of solid raw material.
§ 98.71
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an ammonia manufacturing
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.72
GHGs to report.
You must report:
(a) Carbon dioxide (CO2) process
emissions from steam reforming of a
hydrocarbon or the gasification of solid
raw material, reported for each
ammonia manufacturing process unit.
(b) CO2, N2O, and CH4 emissions from
fuel combustion at ammonia
manufacturing processes and any other
stationary fuel combustion units. You
⎛ 12 44
MW ⎞
CO 2 = ⎜ ∑
∗ ( Fdstk )n ∗ (CC) n ∗
⎟ ∗ 0.001
MVC ⎠
⎝ n=1 12
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the gaseous feedstock
used in month n (scf of feedstock).
(CC)n = Average carbon content of the
gaseous feedstock, from the analysis
results for month n (kg C per kg of
feedstock).
MW = Molecular weight of the gaseous
feedstock (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
44/12 = Ratio of molecular weights, CO2 to
carbon.
⎞
⎛ 12 44
CO 2 = ⎜ v ∑
∗ ( Fdstk )n ∗ (CC) n ⎟ ∗ 0.001
⎠
⎝ n =1 12
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock
used in month n (gallons of feedstock).
(CC)n = Average carbon content of the liquid
feedstock, from the analysis results for
month n (kg C per gallon of feedstock).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
(RCO2)n = CO2 captured or recovered for use
in urea or methanol production for
month n, kg CO2.
⎞
⎛ 12 44
CO 2 = ⎜ ∑
∗ ( Fdstk )n ∗ (CC) n ⎟ ∗ 0.001
12
⎠
⎝ n =1
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00199
Fmt 4701
Sfmt 4725
§ 98.73
Calculating GHG emissions.
You must determine CO2 process
emissions in accordance with the
procedures specified in either paragraph
(a) or (b) of this section.
(a) Any ammonia manufacturing
process unit that meets the conditions
specififed in § 98.33(b)(5)(iii)(A), (B),
and (C), or § 98.33(b)(5)(ii)(A) through
(F) shall calculate total CO2 emissions
using a continuous emissions
monitoring system according to the Tier
4 Calculation Methodology specified in
§ 98.33(a)(4).
(b) If the facility does not measure
total emissions with a CEMS, you must
calculate the annual CO2 process
emissions from feedstock used for
ammonia manufacturing.
(1) Gaseous feedstock. You must
calculate the total CO2 process
emissions from gaseous feedstock
according to Equation G–1 of this
section:
(Eq. G-1)
0.001 = Conversion factor from kg to metric
tons.
(2) Liquid feedstock. You must
calculate the total CO2 process
emissions from liquid feedstock
according to Equation G–2 of this
section:
(Eq. G-2)
(3) Solid feedstock. You must
calculate the total CO2 process
emissions from solid feedstock
according to Equation G–3 of this
section:
(Eq. G-3)
E:\FR\FM\10APP2.SGM
EP10AP09.029</MATH>
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.70
must follow the requirements of 40 CFR
98, subpart C (General Stationary Fuel
Combustion Sources).
(c) For CO2 collected and used on site
or transferred off site, you must follow
the requirements of subpart PP
(Suppliers of CO2) of this part.
EP10AP09.028</GPH>
§ 98.68
Subpart G—Ammonia Manufacturing
10APP2
EP10AP09.027</GPH>
(3) Smelter-specific slope coefficient
and the last date when the smelterspecific-slope coefficient was measured.
(d) Method used to measure the
frequency and duration of anode effects.
(e) The following CO2-specific
information for prebake cells on an
annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the
smelter.
(f) The following CO2-specific
information for S<derberg cells on an
annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the
smelter.
(g) Smelter-specific inputs to the CO2
process equations (e.g., levels of sulfur
and ash) that were used in the
calculation, on an annual basis.
(h) Exact data elements required will
vary depending on smelter technology
(e.g., point-feed prebake or S<derberg).
16645
16646
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Mass of the solid feedstock used
in month n (kg of feedstock).
(CC)n = Average carbon content of the solid
feedstock, from the analysis results for
month n (kg C per kg of feedstock).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
(RCO2)n = CO2 captured or recovered for use
in urea or methanol production for
month n, kg CO2.
§ 98.75
data.
§ 98.74 Monitoring and QA/QC
requirements.
(a) Facilities must continuously
measure the quantity of gaseous or
liquid feedstock consumed using a flow
meter. The quantity of solid feedstock
consumed can be obtained from
company records and aggregated on a
monthly basis.
(b) You must collect a sample of each
feedstock on a monthly basis and
analyze the carbon content using any
suitable method incorporated by
reference in § 98.7.
(c) All fuel flow meters and gas
composition monitors shall be
calibrated prior to the first reporting
year, using a suitable method published
by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, or
others). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Fuel flow
meters and gas composition monitors
shall be recalibrated either annually or
at the minimum frequency specified by
the manufacturer, whichever is more
frequent.
(d) You must document the
procedures used to ensure the accuracy
of the estimates of feedstock
consumption.
Procedures for estimating missing
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation), a substitute data value for
the missing parameter shall be used in
the calculations, according to the
requirements in paragraphs (a) and (b)
of this section.
(a) For missing feedstock supply rates,
use the lesser of the maximum supply
rate that the unit is capable of
processing or the maximum supply rate
that the meter can measure.
(b) There are no missing data
procedures for carbon content. A re-test
must be performed if the data from any
monthly measurements are determined
to be invalid.
§ 98.76
Data reporting requirements.
In addition to the information
required by § 98.3(c) of subpart A of this
part, each annual report must contain
the information specified in paragraphs
(a) through (c) for each ammonia
manufacturing process unit:
(a) Annual CO2 process emissions
(metric tons).
(b) Total quantity of feedstock
consumed for ammonia manufacturing.
(c) Monthly analyses of carbon
content for each feedstock used in
ammonia manufacturing (kg carbon/kg
of feedstock).
§ 98.77
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) and (b) of
this section.
(a) Method used for determining
quantity of feedstock used.
(b) Monthly analyses of carbon
content for each feedstock used in
ammonia manufacturing.
k
CO 2
CMF
= ∑ CO 2
+ CO 2
cli , m
rm
§ 98.78
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart H—Cement Production
§ 98.80
Definition of the source category.
The cement production source
category consists of each kiln and each
in-line kiln/raw mill at any portland
cement manufacturing facility including
alkali bypasses, and includes kilns and
in-line kiln/raw mills that burn
hazardous waste.
§ 98.81
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a cement production process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.82
GHGs to report.
Carbon dioxide (CO2) process
emissions from calcination, reported for
all kilns combined.
CO2, N2O, and CH4 emissions from
fuel combustion at each kiln and any
other stationary combustion units, by
following the requirements of 40 CFR
98, subpart C (General Stationary Fuel
Combustion Sources).
§ 98.83
Calculating GHG emissions.
(a) Cement kilns that meet the
conditions specified in § 98.33(b)(5)(ii)
or (iii) shall calculate total CO2
emissions using the Tier 4 Calculation
Methodology specified in § 98.33(a)(4).
(b) If CEMS are not used to determine
the total annual CO2 emissions from
kilns, then you must calculate process
CO2 emissions by following paragraphs
(b)(1) through (3) of this section.
(1) Calculate CO2 process emissions
from all kilns at the facility using
Equation H–1 of this section:
(Eq. H-1)
m =1
p
r
j =1
(2) CO2 emissions from clinker
production. Calculate CO2 emissions
from each kiln using Equations H–2 and
H–3 of this section.
i =1
CO 2 cli,m = ∑ ⎡( Cli, j ) ∗ ( EFcli, j ) ⎤ + ∑ ⎡( CKD,i ) ∗ ( EFCKD,i ) ⎤
⎣
⎦
⎣
⎦
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00200
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
(Eq. H-2)
10APP2
EP10AP09.031</MATH>
CO2 rm = Total annual emissions of CO2 from
raw materials, metric tons.
k = Total number of kilns at a cement
manufacturing facility.
EP10AP09.030</MATH>
Where:
CO2 CMF = Total annual emissions of CO2
from cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2
from clinker production from kiln m,
metric tons.
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
metric ton clinker computed as specified
in Equation H–3 of this section.
CKDi = Cement kiln dust (CKD) discarded in
quarter i from kiln m, metric tons.
EFCKD,i = Kiln specific fraction of calcined
material in CKD not recycled to the kiln,
for quarter i from kiln m, as determined
in paragraph (c)(2)(i).
p = Number of months for clinker
calculation, 12.
r = Number of quarters for CKD calculation,
4.
EFCli = ( CLiCaO − ClincCaO ) ∗ MRCaO + ( CliMgO − ClincMgO ) ∗ MRMgO
ClincMgO = Monthly non-carbonate MgO of
Clinker, wt% as determined in
§ 98.84(b).
(i) EFCKD must be determined through
X-ray fluorescence (XRF) test or other
testing method specified in § 98.84(a),
except as provided in paragraph
(c)(2)(ii) of this section.
(ii) A default factor of 1.0, which
assumes that 100 percent of all
carbonates in CKD are calcined, may be
CO 2
Where:
rm = The amount of raw material consumed
annually, metric tons/yr.
TOCrm = Organic carbon content of raw
material, as determined in § 98.84(c) or
using a default factor of 0.2 percent of
total raw material weight.
3.664 = The CO2 to carbon molar ratio.
§ 98.84 Monitoring and QA/QC
requirements.
(a) You must determine the plantspecific fraction of calcined material in
cement kiln dust (CKD) not recycled to
the kiln (EFCKD) using an x-ray
fluorescence test or other enhanced
testing method. The monitoring must be
conducted quarterly for each kiln from
a CKD sample drawn from bulk CKD
storage.
(b) You must determine the weight
percents of CaO, MgO, non-carbonate
CaO, and non-carbonate MgO in clinker
from each kiln using an x-ray
fluorescence test or other enhanced
testing method. The monitoring must be
conducted monthly for each kiln from a
clinker sample drawn from bulk clinker
storage.
(c) The total organic carbon contents
of raw materials must be determined
annually using ASTM Method C114–07
or a similar ASTM method approved for
total organic carbon determination in
raw mineral materials. The analysis
must be conducted on sample material
drawn from bulk raw material storage
for each category of raw material (i.e.
limestone, sand, shale, iron oxide, and
alumina).
(d) The quantity of clinker produced
monthly by each kiln must be
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
rm
= rm ∗ TOCrm ∗ 3.664
(Eq. H-4)
determined by direct weight
measurement using the same plant
instruments used for accounting
purposes, such as weigh hoppers or belt
weigh feeders.
(e) The quantity of CKD discarded
quarterly by each kiln must be
determined by direct weight
measurement using the same plant
instruments used for accounting
purposes, such as weigh hoppers or belt
weigh feeders.
(f) The quantity of each category of
raw materials consumed annually by the
facility (i.e. limestone, sand, shale, iron
oxide, and alumina) must be determined
by direct weight measurement using the
same plant instruments used for
accounting purposes, such as weigh
hoppers or belt weigh feeders.
§ 98.85
data.
Procedures for estimating missing
If the CEMS approach is used to
determine CO2 emissions, the missing
data procedures in § 98.35 apply.
Procedures for estimating missing data
do not apply to CO2 process emissions
from cement manufacturing facilities
calculated according to § 98.83(b). If
data on the carbonate content or organic
carbon content is missing, facilities
must undertake a new analysis.
§ 98.86
Data reporting requirements.
In addition to the information
required by § 98.3(b) of this part, each
annual report must contain the
information specified in paragraphs (a)
through (k) of this section for each
portland cement manufacturing facility.
PO 00000
Frm 00201
Fmt 4701
Sfmt 4702
used instead of testing to determine
EFCKD.
(iii) The weight percents of CaO,
MgO, non-carbonate CaO, and noncarbonate MgO of clinker used in
Equation H–3 must be determined using
the measurement methods specified in
§ 98.84(b).
(3) CO2 emissions from raw materials.
Calculate CO2 emissions using Equation
H–4 of this section:
(a) The total combined CO2 emissions
from all kilns at the facility (in metric
tons).
(b) Annual clinker production (tons).
(c) Number of kilns.
(d) Annual CKD production (in metric
tons).
(e) Total annual fraction of CKD
recycled to the kilns (as a percentage).
(f) Annual weighted average carbonate
composition (by carbonate).
(g) Annual weighted average fraction
of calcination achieved (for each
carbonate, percent).
(h) Site-specific emission factor
(metric tons CO2/metric ton clinker
produced).
(i) Organic carbon content of the raw
material (percent).
(j) Annual consumption of raw
material (metric tons).
(k) Facilities that use CEMS must also
comply with the data reporting
requirements specified in § 98.36(d)(iv).
§ 98.87
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (i) of
this section for each portland cement
manufacturing facility.
(a) Monthly carbonate consumption.
(b) Monthly clinker production (tons).
(c) Monthly CKD production (in
metric tons).
(d) Total annual fraction of CKD
recycled to the kiln (as a percentage).
(e) Monthly analysis of carbonate
composition in clinker (by carbonate).
(f) Monthly analysis of fraction of
calcination achieved for CKD and each
carbonate.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.033</MATH>
Where:
CliCaO = Monthly CaO content of Clinker,
wt% as determined in § 98.84(b).
MRCaO = Molecular Ratio of CO2/CaO =
0.785.
CliMgO = Monthly MgO content of Clinker,
wt% as determined in § 98.84(b).
MRMgO = Molecular Ratio of CO2/MgO =
1.092.
ClincCaO = Monthly non-carbonate CaO of
Clinker, wt% as determined in
§ 98.84(b).
(Eq. H-3)
EP10AP09.032</MATH>
Where:
Cli,j = Quantity of clinker produced in month
j from kiln m, metric tons.
EFCli,j = Kiln specific clinker emission factor
for month j for kiln m, metric tons CO2/
16647
16648
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.93
Calculating GHG emissions.
(a) You shall calculate annual facilitylevel F–GHG emissions of each F–GHG
from all etching processes using
Equations I–1 and I–2 of this section:
etchEi = ∑ Eij
(Eq. I-1)
j
Where:
etchEi = Annual emissions of input gas i from
all etch processes
Eij = Annual emissions of input gas i from
etch process j (metric tons), calculated in
equation I–5.
etchBEk = ∑ ∑ BEkij
j
(Eq. I-2)
i
E ij = Cij ∗ (1 − U ij ) ∗ (1 − a ij ∗ d ij ) ∗ 0.001
Where:
Eij = Annual emissions of input gas i from
process j (metric tons).
Cij = Amount of input gas i consumed in
process j, (kg).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00202
Fmt 4701
Sfmt 4725
(Eq. I-3)
j
Where:
cleanEi = Annual emissions of input gas i
from all CVD cleaning processes (metric
tons).
Eij = Annual emissions of input gas i from
CVD cleaning process j (metric tons),
calculated in equation I–5.
cleanBEk = ∑ ∑ BEkij
j
(Eq. I-4)
i
Where:
cleanBEk = Annual emissions of by-product
gas k from all CVD cleaning processes
(metric tons)
BEkij = Annual emissions of by-product k
formed from input gas i during CVD
cleaning process j (metric tons),
calculated in equation I–6.
(c) You shall calculate annual facilitylevel F–GHG emissions for each etching
process and each chamber cleaning
process using Equations I–5 and I–6 of
this section.
(1) Semiconductor facilities that have
an annual capacity of greater than
10,500 m2 silicon shall use processspecific process utilization and byproduct formation factors determined as
specified in § 98.94(b).
(2) All other electronics facilities shall
use the default emission factors for
process utilization and by-production
formation shown in Tables I–2, I–3, and
I–4 of subpart I for semiconductor and
MEMs, LCD, and PV manufacturing,
respectively.
(Eq. I-5)
Uij = Process utilization rate for input gas i
during process j.
aij = Fraction of input gas i used in process
j with abatement devices.
dij = Fraction of input gas i destroyed in
abatement devices connected to process
BEij = Bkij ∗ Cij ∗ (1 − aij ∗ d kj )
cleanEi = ∑ Eij
j (defined in Equation I–11). This is zero
unless the facility verifies the DRE of the
device pursuant to § 98.94(c) of Subpart
I.
0.001 = Conversion factor from kg to metric
tons.
(Eq. I-6)
E:\FR\FM\10APP2.SGM
EP10AP09.039</MATH>
Definition of the source category.
(a) The electronics source category
consists of any of the processes listed in
paragraphs (a)(1) through (5) of this
section. Electronics manufacturing
facilities include but are not limited to
facilities that manufacture
semiconductors, liquid crystal displays
(LCD), microelectromechanical systems
(MEMs), and photovoltaic (PV) cells.
(1) Each electronics manufacturing
production process in which the etching
process uses plasma-generated fluorine
atoms, which chemically react with
exposed thin films (e.g., dielectric,
metals) and silicon to selectively
remove portions of material.
(2) Each electronics manufacturing
production process in which chambers
used for depositing thin films are
cleaned periodically using plasmagenerated fluorine atoms from
fluorinated and other gases.
(3) Each electronics manufacturing
production process in which some
fluorinated compounds can be
transformed in the plasma processes
into different fluorinated compounds
which are then exhausted, unless
abated, into the atmosphere.
(4) Each electronics manufacturing
production process in which the
chemical vapor deposition process uses
nitrous oxide.
(5) Each electronics manufacturing
production process in which fluorinated
GHGs are used as heat transfer fluids
(HTFs) to cool process equipment,
control temperature during device
GHGs to report.
(a) You shall report emissions of
nitrous oxide and fluorinated GHGs (as
defined in § 98.6). The fluorinated GHGs
that are emitted from electronics
production processes include but are
not limited to those listed in Table I–1
of this subpart. You must report:
(1) Fluorinated GHGs from plasma
etching.
(2) Fluorinated GHGs from chamber
cleaning.
(3) Nitrous oxide from chemical vapor
deposition.
(4) Fluorinated GHGs from heat
transfer fluid use.
(b) You shall report CO2, N2O and CH4
combustion-related emissions, if any, at
electronics manufacturing facilities. For
stationary fuel combustion sources,
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements in subpart C of this part.
EP10AP09.038</MATH>
§ 98.90
§ 98.92
(b) You shall calculate annual facilitylevel F–GHG emissions of each F–GHG
from all CVD chamber cleaning
processes using Equations I–3 and I–4 of
this section:
EP10AP09.037</MATH>
Subpart I—Electronics Manufacturing
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an electronics manufacturing
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
10APP2
EP10AP09.036</MATH>
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.91
Where:
etchBEk = Annual emissions of by-product
gas k from all etch processes (metric
tons).
BEkij = Annual emissions of by-product k
formed from input gas i during etch
process j (metric tons), calculated in
equation I–6.
EP10AP09.035</MATH>
§ 98.88
testing, and solder semiconductor
devices to circuit boards.
EP10AP09.034</MATH>
(g) Monthly cement production.
(h) Documentation of calculated sitespecific clinker emission factor.
(i) Facilities that use CEMS must also
comply with the recordkeeping
requirements specified in § 98.37.
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
process (j). This is zero unless the facility
verifies the DRE of the device pursuant
to § 98.94(c) of Subpart I.
0.001 = Conversion factor from kg to metric
tons.
(d) You shall report annual N2O
facility-level emissions during chemical
vapor deposition using Equation I–7 of
this section.
(Eq. I-7)
EH i = density ∗ [ I io + Pit − N it + Rit − I it − Dit ∗ 0.001]
Rit = Total nameplate capacity [charge] of
equipment that contains heat transfer
fluid i and that is retired during the
current reporting period.
Iit = Inventory of heat transfer fluid i at the
end of current reporting period (l).
Dit = Amount of heat transfer fluid i
recovered and sent off site during current
reporting period, (l).
0.001 = Conversion factor from kg to metric
tons.
Ci = I Bi − I Ei + A − D ∗ 0.001
Where:
Ci = Annual consumption of input gas i
(metric tons/year).
IBi = Inventory of input gas i stored in
cylinders or other containers at the
beginning of the year, including heels
(kg).
IEi = Inventory of input gas i stored in
cylinders or other containers at the end
of the year, including heels (kg).
A = Acquisitions of that gas during the year
through purchases or other transactions,
including heels in cylinders or other
containers returned to the electronics
production facility (kg).
D = Disbursements of gas through sales or
other transactions during the year,
including heels in cylinders or other
containers returned by the electronics
production facility to the gas distributor
(kg).
0.001 = Conversion factor from kg to metric
tons.
(2) Monitor the mass flow of the pure
gas into the system using flowmeters.
The flowmeters must have an accuracy
and precision of one percent of full
scale or better.
(b) If you use fluorinated GHG
utilization rates and by-product
emission factors other than the defaults
in Tables I–2, I–3, or I–4 of Subpart I,
you must use fluorinated GHG
utilization rates and by-product
emission factors that have been
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Frm 00203
Fmt 4701
Sfmt 4702
§ 98.94 Monitoring and QA/QC
requirements.
(a) You must estimate gas
consumption according to the
requirements in paragraph (a)(1) or
(a)(2) of this section for each process or
process type, as appropriate.
(1) Monitor changes in container mass
and inventories for each gas using weigh
scales with an accuracy and precision of
one percent of full scale or better.
Calculate the gas consumption using
Equation I–9 of this section.
(Eq. I-9)
measured using the International
SEMATECH Manufacturing Initiative’s
Guideline for Environmental
Characterization of Semiconductor
Process Equipment. You may use
fluorinated GHG utilization rates and
by-product emission factors measured
by manufacturing equipment suppliers
if the conditions in paragraph (b)(1) and
(2) of this section are met.
(1) The manufacturing equipment
supplier has measured the GHG
utilization rates and by-product
emission factors using the International
SEMATECH Guideline.
(2) The conditions under which the
measurements were made are
representative of your facility’s F–GHG
emitting processes.
(c) If your facility employs abatement
devices and you wish to reflect the
emission reductions due to these
devices in § 98.93(c), you must verify
the destruction or removal efficiency
(DRE) of the devices using the methods
in either paragraph (c)(1) or (2) of this
section.
(1) Experimentally determine the
effective dilution through the abatement
device and measure abatement DRE
during actual or simulated process
conditions by following the procedures
of this paragraph.
PO 00000
(Eq. I-8)
(i) Measure the concentrations of F–
GHGs exiting the process tool and
entering and exiting the abatement
system under operating process and
abatement system conditions that are
representative of those for which F–
GHG emissions are estimated and
abatement-system DRE is used for the
F–GHG reporting period.1
(ii) Measure the dilution through the
abatement system and calculate the
dilution factor under the representative
operating conditions given in paragraph
(c)(i) of this section by using the tracer
method. This method consists of
injecting known flows of a non-reactive
gas (such as krypton) at the inlet of the
abatement system, measuring the timeaveraged concentrations of krypton
entering ([Kr]in) and exiting ([Kr]out) the
abatement system, and calculating the
dilution factor (DF) as the ratio of the
time-averaged measured krypton
concentrations entering and exiting the
abatement system, using equation I–10
of this section.
1 Abatement system means a point-of-use (POU)
abatement system whereby a single abatement
system is attached to a single process tool or single
process chamber of a multi-chamber tool.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.042</MATH>
Where:
EHi = Emissions of fluorinated GHG heat
transfer fluid i, (metric tons/year).
Density = Density of heat transfer fluid i (kg/
l).
Iio = Inventory of heat transfer fluid i at the
end of previous reporting period (l).
Pit = Net purchases of heat transfer fluid i
during the current reporting period (l).
Nit = Total nameplate capacity [charge] of
equipment that contains heat transfer
fluid i and that is installed during the
current reporting period.
(e) For facilities that use heat transfer
fluids, you shall report the annual
emissions of fluorinated GHG heat
transfer fluids using Equation I–8 of this
section.
EP10AP09.041</MATH>
E ( N 2 O ) = C N2O x 0.001
Where:
E(N2O) = Annual emissions of N2O (metric
tons/year).
CN2O = Annual Consumption of N2O (kg).
0.001 = Conversion factor from kg to metric
tons.
EP10AP09.040</MATH>
Where:
BEkij = Annual emissions of by-product k
formed from input gas i during process
j (metric tons).
Bkij = Kg of gas k created as a by-product per
kg of input gas i consumed in process j.
Cij = Amount of input gas i consumed in
process j (kg).
aij = Fraction of input gas i used in process
j with abatement devices.
dkj = Fraction of by-product gas k destroyed
in abatement devices connected to
16649
16650
(Eq. I-10)
(iii) Measure the F–GHG
concentrations in and out of the device
with all process chambers connected to
the F–GHG abatement system and under
the production and abatement system
conditions for which F–GHG emissions
are estimated for the reporting period.2
(iv) Calculate abatement system DRE
using Equation I–11 of this section,
where it is assumed that the
measurement pressure and temperature
at the inlet and outlet of the abatement
system are identical and where the
relative precision (e) of the quantity
ci¥out*DF/ci¥in shall not exceed ±10
percent (two standard deviations) using
proper statistical methods.
dij = 1 −
DF ∗ ci − out
ci −in
(Eq. I -11)
Where:
dij = Destruction or removal efficiency (DRE)
ci¥in = Concentration of gas i in the inflow
to the abatement system (ppm).
ci¥out = Concentration of gas i in the outflow
from the abatement system (ppm).
DF = Dilution Factor calculated using
Equation I–10.
(v) The DF may not be obtained by
calculation from flows other than those
obtained by using the tracer method
described in paragraph (ii) of this
section.
(2) Install abatement devices that have
been tested by a third party (e.g., UL)
according to EPA’s Protocol for
Measuring Destruction or Removal
Efficiency (DRE) of Fluorinated
Greenhouse Gas Abatement Equipment
in Electronics Manufacturing. This
testing may be obtained by the
manufacturer of the equipment.
(d) Abatement devices must be
operated within the manufacturer’s
specified equipment lifetime and gas
flow and mix limits and must be
maintained according to the
manufacturer’s guidelines.
(e) You shall adhere to the QA/QC
procedures of this paragraph when
estimating F–GHG and N2O emissions
from cleaning/etching processes:
(1) You shall follow the QA/QC
procedures in the International
SEMATECH Manufacturing Initiative’s
Guideline for Environmental
Characterization of Semiconductor
2 Most process tools have multiple chambers. For
combustion-type abatement systems, the outlets of
each chamber separately enter the destructionreactor because premixing of certain gaseous
mixtures may be conducive to fire or explosion. For
the less-frequently used plasma-type POU
abatement systems, there is one system per
chamber.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Process Equipment when estimating
facility-specific gas process utilization
and by-product gas formation.
(2) You shall follow the QA/QC
procedures in the EPA DRE
measurement protocol when estimating
abatement device DRE.
(3) You shall certify that abatement
devices are maintained in accordance
with manufacturer specified guidelines.
(4) You shall certify that gas
consumption is tracked to a high degree
of precision as part of normal facility
operations and that further QA/QC is
not required.
(f) You shall adhere to the QA/QC
procedures of this paragraph when
estimating F–GHG emissions from heat
transfer fluid use:
(1) You shall review all inputs to
Equation I–4 of this section to ensure
that all inputs and outputs to the
facility’s system are accounted for.
(2) You shall not enter negative inputs
into the mass balance Equation I–4 of
this section and shall ensure that no
negative emissions are calculated.
(3) You shall ensure that the
beginning of year inventory matches the
end of year inventory from previous
year.
(g) All flowmeters, scales, load cells,
and volumetric and density measures
used to measure quantities that are to be
reported under § 98.92 and § 98.96 shall
be calibrated using suitable NISTtraceable standards and suitable
methods published by a consensus
standards organization (e.g., ASTM,
ASME, ASHRAE, or others).
Alternatively, calibration procedures
specified by the flowmeter, scale, or
load cell manufacturer may be used.
Calibration shall be performed prior to
the first reporting year. After the initial
calibration, recalibration shall be
performed at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
(h) All instruments (e.g., mass
spectrometers and fourier transform
infrared measuring systems) used to
determine the concentration of
fluorinated greenhouse gases in process
streams shall be calibrated just prior to
DRE, gas utilization, or product
formation measurement through
analysis of certified standards with
known concentrations of the same
chemicals in the same ranges (fractions
by mass) as the process samples.
Calibration gases prepared from a highconcentration certified standard using a
gas dilution system that meets the
requirements specified in Test Method
205, 40 CFR Part 51, Appendix M may
also be used.
PO 00000
Frm 00204
Fmt 4701
Sfmt 4702
§ 98.95
data.
Procedures for estimating missing
(a) For semiconductor facilities that
have an annual capacity of greater than
10,500 m2 silicon, you shall estimate
missing site-specific gas process
utilization and by-product formation
using default factors from Tables I–2
through I–4 of this subpart. However,
use of these default factors shall be
restricted to less than 5 percent of the
total facility emissions.
(b) For facilities using heat transfer
fluids and missing data for one or more
of the parameters in Equation I–8, you
shall estimate heat transfer fluid
emissions using the arithmetic average
of the emission rates for the year
immediately preceding the period of
missing data and the months
immediately following the period of
missing data. Alternatively, you may
estimate missing information using
records from the heat transfer fluid
supplier. You shall document the
method used and values estimated for
all missing data values.
(c) If the methods specified in
paragraphs (a) and (b) of this section are
likely to significantly under- or
overestimate the value of the parameter
during the period when data were
missing (e.g., because the monitoring
failure was linked to a process
disturbance that is likely to have
significantly increased the F–GHG
emission rate), you shall develop a best
estimate of the parameter, documenting
the methods used, the rationale behind
them, and the reasons why the methods
specified in paragraphs (a) and (b) of
this section would lead to a significant
under-or overestimate of the parameter.
§ 98.96
Data reporting requirements.
In addition to the information
required by § 98.3(c), you shall include
in each annual report the following
information for each electronics
manufacturer.
(a) Emissions of each GHG emitted
from all plasma etching processes, all
chamber cleaning, all chemical vapor
deposition processes, and all heat
transfer fluid use, respectively.
(b) The method, mass of input F–GHG
gases, and emission factors used for
estimating F–GHG emissions.
(c) Production in terms of substrate
surface area (e.g., silicon, PV-cell, LCD).
(d) Factors used for gas process
utilization and by-product formation,
and the source and uncertainty for each
factor.
(e) The verified DRE and its
uncertainty for each abatement device
used, if you have verified the DRE
pursuant to § 98.94(c).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.044</MATH>
[ Kr ] in
[ Kr ] out
EP10AP09.043</MATH>
DF =
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
16651
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(f) Fraction of each gas fed into each
process type with abatement devices.
(g) Description of abatement devices,
including the number of devices of each
manufacturer and model.
(h) For heat transfer fluid emissions,
inputs in the mass-balance Equation.
(i) Example calculations for F–GHG,
N2O, and heat transfer fluid emissions.
(j) Estimate of the overall uncertainty
in the emissions estimate.
§ 98.97
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the following records:
(a) Data used to estimate emissions
including all spreadsheets and copies of
calculations used to estimate emissions.
that the DRE was calculated using the
formula given in § 98.94(c)(1)(iv).
(3) Documentation of the measured
flows, concentrations and calculations
used to calculate DF, relative precision
(e), and DRE.
(d) The date and results of the initial
and any subsequent tests to determine
process tool gas utilization and byproduct formation factors.
(e) Abatement device calibration and
maintenance records.
(b) Documentation for the values used
for GHG utilization rates and by-product
emission factors, including
documentation that these were
measured using the the International
SEMATECH Manufacturing Initiative’s
Guideline for Environmental
Characterization of Semiconductor
Process Equipment.
(c) The date and results of the initial
and any subsequent tests of emission
control device DRE, including the
following information:
(1) Dated certification, by the
technician who made the measurement,
that the dilution factor was determined
using the tracer method.
(2) Dated certification, by the
technician who made the measurement,
§ 98.98
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE I–1 OF SUBPART I—GHGS TYPICALLY USED BY THE ELECTRONICS INDUSTRY
Product type
F–GHGs Used during manufacture
Electronics .......................................
CF4, C2F6, C3F8, c-C4F8, c-C4F8O, C4F6, C5F8, CHF3, CH2F2, NF3, SF6, and HTFs (CF3-(O-CF(CF3)CF2)n-(O-CF2)m-O-CF3, CnF2n+2, CnF2n+1(O)CmF2m+1, CnF2nO, (CnF2n+1)3N)
TABLE I–2 OF SUBPART I—DEFAULT EMISSION FACTORS FOR SEMICONDUCTOR AND MEMS MANUFACTURING
Factors
Process gases
Etch 1-Ui
CF4 ...........................................................
C2F6 ..........................................................
CHF3 ........................................................
CH2F2 .......................................................
C3F8 ..........................................................
c-C4F8 .......................................................
NF3 ...........................................................
Remote
NF3 ...........................................................
SF6 ...........................................................
C4F6a ........................................................
C5F8a ........................................................
C4F8Oa ......................................................
CVD 1-Ui
Etch BCF4
Etch BC2F6
CVD BCF4
CVD BC3F8
0.7
0.4*
0.4*
0.06*
NA
0.2*
NA
0.9
0.6
NA
NA
0.4
0.1
0.02
NA
0.4*
0.07*
0.08*
NA
0.2
NA
NA
NA
NA
NA
NA
0.2
NA
NA
0.1
NA
NA
0.1
0.1
† 0.02
NA
NA
NA
NA
NA
NA
NA
0.2
0.2
0.1
0.2
NA
0.2
NA
NA
0.1
0.1
NA
NA
0.3*
0.2
NA
NA
NA
0.2*
0.2
NA
† 0.1
NA
NA
0.1
0.1
NA
NA
NA
NA
0.4
Notes: NA denotes not applicable based on currently available information.
* Estimate includes multi-gas etch processes.
† Estimate reflects presence of low-k, carbide and multi-gas etch processes that may contain a C-containing FC additive.
TABLE I–3 OF SUBPART I—DEFAULT EMISSION FACTORS FOR LCD MANUFACTURING
Factors
Process gases
Etch
1-Ui
CF4 .......................................................................................
C2F6 ......................................................................................
CHF3 ....................................................................................
CH2F2 ...................................................................................
C3F8 ......................................................................................
c-C4F8 ...................................................................................
NF3 Remote .........................................................................
NF3 .......................................................................................
SF6 .......................................................................................
CVD
1-Ui
0.6
NA
0.2
NA
NA
0.1
NA
NA
0.3
Etch
BCF4
NA
NA
NA
NA
NA
NA
0.03
0.3
0.9
NA
NA
0.07
NA
NA
0.009
NA
NA
NA
Notes: NA denotes not applicable based on currently available information.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00205
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Etch
BCHF3
NA
NA
NA
NA
NA
0.02
NA
NA
NA
Etch
BC2F6
NA
NA
0.05
NA
NA
NA
NA
NA
NA
16652
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE I–4 OF SUBPART I—DEFAULT EMISSION FACTORS FOR PV MANUFACTURING
Factors
Process gases
Etch
1-Ui
CF4 .......................................................................................
C2F6 ......................................................................................
CHF3 ....................................................................................
CH2F2 ...................................................................................
C3F8 ......................................................................................
c-C4F8 ...................................................................................
NF3 Remote .........................................................................
NF3 .......................................................................................
SF6 .......................................................................................
CVD
1-Ui
0.7
0.4
0.4
NA
NA
0.2
NA
NA
0.4
Etch
BC2F6
Etch
BCF4
NA
0.6
NA
NA
0.1
0.1
NA
0.3
0.4
NA
0.2
NA
NA
NA
0.1
NA
NA
NA
CVD
BCF4
NA
NA
NA
NA
NA
0.1
NA
NA
NA
NA
0.2
NA
NA
0.2
0.1
NA
NA
NA
Notes: NA denotes not applicable based on currently available information.
Subpart J—Ethanol Production
§ 98.100
Definition of the source category.
the calculation procedures, monitoring
and QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
II of this part.
An ethanol production facility is a
facility that produces ethanol from the
fermentation of sugar, starch, grain, or
cellulosic biomass feedstocks; or
produces ethanol synthetically from
ethylene or hydrogen and carbon
monoxide.
§ 98.103
§ 98.101
Subpart K—Ferroalloy Production
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an ethanol production process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.102
GHGs to report.
You must report:
(a) Emissions of CO2, N2O, and CH4
from on-site stationary combustion. You
must follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of subpart C of this part.
(b) Emissions of CH4 from on-site
landfills. You must follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
HH of this part.
(c) Emissions of CH4 from on-site
wastewater treatment. You must follow
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.110
Definition of the source category.
The ferroalloy production source
category consists of any facility that
uses pyrometallurgical techniques to
produce any of the following metals:
ferrochromium, ferromanganese,
ferromolybdenum, ferronickel,
ferrosilicon, ferrotitanium,
ferrotungsten, ferrovanadium,
silicomanganese, or silicon metal.
§ 98.111
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a ferroalloy production process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.112
GHGs to report.
(a) You must report the CO2 emissions
from each electric arc furnace used for
ferroalloy production.
(b) You must report the CH4 emissions
from each electric arc furnace used for
PO 00000
Frm 00206
Fmt 4701
Sfmt 4702
the production of any ferroalloy listed
in Table K–1 of this subpart.
(c) You must report the CO2, CH4, and
N2O emissions from each stationary
combustion unit following the
requirements specified in subpart C of
this part.
§ 98.113
Calculating GHG emissions.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must estimate total CO2 emissions
according to the requirements in
§ 98.33.
(b) If you do not operate and maintain
a CEMS that measures total CO2 process
emissions consistent with the
requirements in subpart C, you must
determine using the procedure specified
in paragraphs (b)(1) and (2) of this
section the total CO2 emissions from all
electric arc furnaces that are used for
ferroalloy production.
(1) For each EAF at your facility used
for ferroalloy production, you must
determine the mass of carbon in each
carbon-containing input and output
material for the electric arc furnace for
each calendar month using Equation K–
1 of this section. Carbon containing
input materials include carbon eletrodes
and carbonaceous reducing agents.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
E CO 2 =
16653
44 12 ⎛
⎞
× ∑ ⎜ ∑ M reducing agenti × Creducing agenti ⎟
12 n =1 ⎝ i
⎠n
+
44 12 ⎛
⎞
× ∑ ⎜ ∑ M electrodem × Celectrodem ⎟
12 n =1 ⎝ m
⎠n
+
44 12 ⎛
⎞
× ∑ ⎜ ∑ M oreh × Coreh ⎟
12 n =1 ⎝ h
⎠n
+
⎞
44 12 ⎛
× ∑ ⎜ ∑ M flux j × Cflux j ⎟
⎜ j
⎟
12 n =1 ⎝
⎠n
−
44 12 ⎛
⎞
× ∑ ⎜ ∑ M product k × Cproduct k ⎟
12 n =1 ⎝ k
⎠n
−
44 12 ⎛
× ∑ ⎜ ∑ M non-product outgoingl × C
12 n =1 ⎝ l
Where:
ECO2 = Annual CO2 mass emissions from an
individual EAF, metric tons.
Mreducing agenti = Mass of reducing agent i fed,
charged, or otherwise introduced into
the EAF, metric tons.
Creducing agenti = Carbon content in reducing
agent i, metric tons of C/metric ton
reducing agent.
Melectrodem = Mass of carbon electrode m
consumed in the EAF, metric tons.
(Eq. K-1)
non-product outgoing1
⎞
⎟
⎠n
Celectrodem = Carbon content of the carbon
electrode m, percent by weight,
expressed as a decimal fraction.
Moreh = Mass of ore h charged to the EAF,
metric tons.
Coreh = Carbon content in ore h, metric tons
of C/metric ton ore.
Mfluxj = Mass of flux material j fed, charged,
or otherwise introduced into the EAF to
facilitate slag formation, metric tons.
Cfluxj = Carbon content in flux material j,
metric tons of C/metric ton material.
Mproductk = Mass of alloy product k tapped
from EAF, metric tons.
Cproductk = Carbon content in alloy product k,
metric tons of C/metric ton product.
Mnon-product outgoingl = Mass of non-product
outgoing material l removed from EAF,
metric tons.
Cnon-product outgoingl = Carbon content in nonproduct outgoing material l, metric tons
of C/metric ton.
(2) You must determine the total CO2
emissions from the electric arc furnaces using
Equation K–2 of this section:
k
CO 2 = ∑ E CO 2k
(Eq. K-2)
1
1
(
Where:
ECH4 = Annual CH4 emissions from an
individual EAF, metric tons.
Mproducti = Annual mass of alloy product i
produced in the EAF, metric tons.
EFproducti = CH4 emission factor for alloy
product i from Table K–1 of this subpart,
kg of CH4 emissions per metric ton of
alloy product i.
(2) You must determine the total CH4
emissions using Equation K–4 of this
section:
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
)
(Eq. K-3)
j
CH 4 = ∑ E CH 4 j
(Eq. K-4)
1
Where:
CH4 = Total annual CH4 emissions, metric
tons/year.
ECH4j = Annual CH4 emissions from EAF k
calculated using Equation K–3 of this
section, metric tons/year.
j = Total number of EAFs at facility used for
the production of ferroalloys listed in
Table K–1 of this subpart.
PO 00000
Frm 00207
Fmt 4701
Sfmt 4702
§ 98.114 Monitoring and QA/QC
requirements.
If you determine CO2 emissions using
the carbon balance procedure in
§ 98.113(b), you must meet the
requirements specified in paragraphs (a)
through (c) of this section.
(a) Determine the mass of each solid
carbon-containing process input and
output material by direct measurements
or calculations using process operating
information, and record the total mass
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.048</MATH>
i
E CH 4 = ∑ M producti × EFproducti
EP10AP09.047</MATH>
(c) For the electric arc furnaces used
at your facility for the production of any
ferroalloy listed in Table K–1 of this
subpart, you must determine the total
CH4 emissions using the procedure
specified in paragraphs (c)(1) and (2) of
this section.
(1) For each EAF, calculate annual
CH4 emissions using Equation K–3 of
this section:
EP10AP09.046</MATH>
k = Total number of EAFs at facility used for
the ferroalloy production.
EP10AP09.045</MATH>
Where:
CO2 = Total annual CO2 emissions, metric
tons/year.
ECO2k = Annual CO2 emissions calcaluated
using Equation K–1 of this supart, metric
tons/year.
16654
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
of each material consumed or produced
for each calendar month.
(b) For each process input and output
material identified in paragraph (a) of
this section, you must determine the
average carbon content of the material
for the specified period using
information provided by your material
supplier or by collecting and analyzing
a representative sample of the material.
(c) For each input material identified
in paragraph (a) of this section for
which the carbon content is not
provided by your material supplier, the
carbon content of the material must be
analyzed by an independent certified
laboratory at least annually using the
test methods (and their QA/QC
procedures) in § 98.7. Use ASTM
E1941–04 (‘‘Standard Test Method for
Determination of Carbon in Refractory
and Reactive Metals and Their Alloys’’)
for analysis of metal ore and alloy
product; ASTM D5373–02 (‘‘Standard
Test Methods for Instrumental
Determination of Carbon, Hydrogen, and
Nitrogen in Laboratory Samples of Coal
and Coke’’) for analysis of carbonaceous
reducing agents and carbon electrodes,
and ASTM C25–06 (‘‘Standard Test
Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime’’) for analysis of flux materials
such as limestone or dolomite.
§ 98.115 Procedures for estimating
missing data.
For the carbon input procedure in
§ 98.113(b), a complete record of all
measured parameters used in the GHG
emissions calculations is required (e.g.,
raw materials carbon content values,
etc.). Therefore, whenever a qualityassured value of a required parameter is
unavailable, a substitute data value for
the missing parameter shall be used in
the calculations.
(a) For each missing value of the
carbon content the substitute data value
shall be the arithmetic average of the
quality-assured values of that parameter
immediately preceding and immediately
following the missing data incident. 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 qualityassured value obtained after the missing
data period.
(b) For missing records of the mass of
carbon-containing input or output
material consumption, the substitute
data value shall be the best available
estimate of the mass of the input or
output material. The owner or operator
shall document and keep records of the
procedures used for all such estimates.
(c) If you are required to calculate CH4
emissions for the electric arc furnace as
specified in § 98.113(c), then you are
required to have 100 percent of the
specified data for each reporting period.
§ 98.116
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (f) of this
section.
(a) Annual CO2 emissions from each
electric arc furnace used for ferroalloy
production, in metric tons and the
method used to estimate these
emissions.
(b) Annual CH4 emissions from each
electric arc furnace used for the
production of any ferroalloy listed in
Table K–1 of this subpart.
(c) Facility ferroalloy product
production capacity (metric tons).
(d) Annual facility production
quantity for each ferroalloy product
(metric tons).
(d) Number of facility operating hours
in calendar year.
(f) If you use the carbon balance
procedure, report for each carboncontaining input and output material
consumed or used (other than fuel), the
information specified in paragraphs
(g)(1) and (2) of this section.
(1) Annual material quantity (in
metric tons).
(2) Annual average of the monthly
carbon content determinations for each
material and the method used for the
determination (e.g., supplier provided
information, analyses of representative
samples you collected).
§ 98.117
Records that must be retained.
In addition to the records required by
§ 98.3(g) of this part, you must retain the
records specified in paragraphs (a)
through (e) of this section.
(a) Monthly facility production
quantity for each ferroalloy product (in
metric tons).
(b) Number of facility operating hours
each month.
(c) If you use the carbon balance
procedure, record for each carboncontaining input and output material
consumed or used (other than fuel), the
information specified in paragraphs
(c)(1) and (2) of this section.
(1) Monthly material quantity (in
metric tons).
(2) Monthly average carbon content
determined for material and records of
the supplier provided information or
analyses used for the determination.
(d) You must keep records that
include a detailed explanation of how
company records of measurements are
used to estimate the carbon input input
and output to each electric arc furnace.
You also must document the procedures
used to ensure the accuracy of the
measurements of materials fed, charged,
or placed in an affected unit including,
but not limited to, calibration of
weighing equipment and other
measurement devices. The estimated
accuracy of measurements made with
these devices must also be recorded,
and the technical basis for these
estimates must be provided.
(e) If you are required to calculate CH4
emissions for the electric arc furnace as
specified in § 98.113(c), you must
maintain records of the total amount of
each alloy product produced for the
specified reporting period, and the
appropriate alloy-product specific
emission factor used to calculate CH4
emissions.
§ 98.118
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE K–1 OF SUBPART K—ELECTRIC ARC FURNACE (EAF) CH4 EMISSION FACTORS
CH4 Emission factor
(kg CH4 per metric ton product)
EAF operation
Alloy product produced in EAF
Batch-charging
silicon metal .................................................................................................................................
ferrosilicon 90% ...........................................................................................................................
ferrosilicon 75% ...........................................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00208
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
1.5
1.4
1.3
10APP2
Sprinklecharging a
1.2
1.1
1.0
Sprinklecharging and
>750 ° Cb
0.7
0.6
0.5
16655
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE K–1 OF SUBPART K—ELECTRIC ARC FURNACE (EAF) CH4 EMISSION FACTORS—Continued
CH4 Emission factor
(kg CH4 per metric ton product)
EAF operation
Alloy product produced in EAF
ferrosilicon 65% ...........................................................................................................................
Sprinklecharging and
>750 ° Cb
Sprinklecharging a
Batch-charging
1.3
1.0
0.5
a Sprinkle-charging
is charging intermittently every minute.
b Temperature measured in off-gas channel downstream of the furnace hood.
(a) The total mass of each fluorinated
GHG product emitted annually from all
fluorinated GHG production processes
shall be estimated by using Equation L–
1 of this section:
n
GHGs to report.
15:41 Apr 09, 2009
Jkt 217001
Where:
EP = Total mass of each fluorinated GHG
product emitted annually from all
production processes (metric tons).
EPip = Total mass of the fluorinated GHG
product emitted from production process
i over the period p (metric tons, defined
in Equation L–3 of this section).
n = Number of concentration and flow
measurement periods for the year.
m = Number of production processes.
(b) The total mass of fluorinated GHG
by-product k emitted annually from all
fluorinated GHG production processes
shall be estimated by using Equation L–
2 of this section:
q
u
R ∗ MWP ∗ SCP
− P − ∑ ( C p ∗ WDj ) − ∑ LBkip
MWR ∗ SCR
j =1
k =1
Where:
EPip = Total mass of each fluorinated GHG
product emitted from production process
i over the period p (metric tons).
P = Total mass of the fluorinated GHG
produced by production process i over
the period p (metric tons).
R = Total mass of the reactant that is
consumed by production process i over
the period p (metric tons, defined in
Equation L–4).
MWR = Molecular weight of the reactant.
MWP = Molecular weight of the fluorinated
GHG produced.
SCR = Stoichiometric coefficient of the
reactant.
VerDate Nov<24>2008
(Eq. L-1)
p =1 i =1
(a) You must report the CO2, N2O, and
CH4 emissions from each on-site
stationary combustion unit. For these
stationary combustion units, you must
follow the applicable calculation
procedures, monitoring and QA/QC
methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of subpart
C of this part.
EPip =
m
E p = ∑ ∑ EPip
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a fluorinated greenhouse gas
production process and the facility
meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.122
Calculating GHG emissions.
SCP = Stoichiometric coefficient of the
fluorinated GHG produced.
CP = Concentration (mass fraction) of the
fluorinated GHG product in stream j of
destroyed wastes. If this concentration is
only a trace concentration, CP is equal to
zero.
WDj = Mass of wastes removed from
production process i in stream j and
destroyed over the period p (metric tons,
defined in Equation L–5 of this section).
LBkip = Yield loss related to by-product k for
production process i over the period p
(metric tons, defined in Equation L–6 of
this section).
q = Number of waste streams destroyed in
production process i.
PO 00000
Frm 00209
Fmt 4701
Sfmt 4702
(Eq. L-2)
p =1 i =1
Where:
EBk = Total mass of fluorinated GHG byproduct k emitted annually from all
production processes (metric tons).
EBkip = Total mass of fluorinated GHG byproduct k emitted from production
process i over the period p (metric tons,
defined in Equation L–8 on this section).
n = Number of concentration and flow
measurement periods for the year.
m = Number of production processes.
(c) The total mass of each fluorinated
GHG product emitted from production
process i over the period p shall be
estimated at least daily by calculating
the difference between the expected
production of the fluorinated GHG
based on the consumption of reactants
(e.g., HF and a chlorocarbon reactant)
and the measured production of the
fluorinated GHG, accounting for yield
losses related to by-products and
wastes. This calculation shall be
performed for each reactant, using
Equation L–3 of this section. Estimated
emissions shall equal the average of the
results obtained for each reactant.
(Eq. L-3)
u = Number of by-products generated in
production process i.
(d) The total mass of the reactant that
is consumed by production process i
over the period p shall be estimated by
using Equation L–4 of this section:
R = RF − RR
(Eq. L-4)
Where:
R = Total mass of the reactant that is
consumed by production process i over
the period p (metric tons).
RF = Total mass of the reactant that is fed into
production process i over the period p
(metric tons).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.052</MATH>
§ 98.121
§ 98.123
m
EP10AP09.051</MATH>
Definition of the source category.
The fluorinated gas production source
category consists of facilities that
produce a fluorinated GHG from any
raw material or feedstock chemical.
Producing a fluorinated GHG does not
include the reuse or recycling of a
fluorinated GHG or the generation of
HFC–23 during the production of
HCFC–22.
n
EBk = ∑ ∑ EBkip
EP10AP09.050</MATH>
§ 98.120
(b) You must report the total mass of
each fluorinated GHG emitted from each
fluorinated GHG production process
and from all fluorinated GHG
production processes at the facility.
EP10AP09.049</MATH>
Subpart L—Fluorinated Greenhouse
Gas Production
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
WDj = The mass of wastes removed from
production process i in stream j and
destroyed over the period p (metric
tons).
WFj = The total mass of wastes removed from
production process i in stream j and fed
(B
kip
* MWP * MEBk )
( MW
Bk
(g) If by-product k is responsible for
yield loss in production process i and
q
∑ cBjk ∗ S j
(Eq. L-7)
j
Where:
Bkip = Mass of by-product k generated by
production process i over the period p
(metric tons).
CBkj = Concentration (mass fraction) of the
by-product k in stream j of production
process i over the period p. If this
q
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. L-8)
§ 98.124 Monitoring and QA/QC
requirements.
(a) The total mass of fluorinated GHGs
produced over the period p shall be
estimated at least daily using the
methods and measurements set forth in
§§ 98.413(b) and 98.414.
(b) The total mass of each reactant fed
into the production process shall be
measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better.
(c) The total mass of each reactant
permanently removed from the
production process shall be measured at
least daily using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of 0.2 percent of
full scale or better. If the measured mass
includes more than trace concentrations
of materials other than the reactant, the
concentration of the reactant shall be
measured at least daily using equipment
and methods (e.g., gas chromatography)
PO 00000
(h) If by-product k is responsible for
yield loss, is a fluorinated GHG, occurs
in any process stream in more than trace
concentrations, and is not completely
recaptured or completely destroyed; the
total mass of by-product k emitted from
production process i over the period p
shall be estimated at least daily using
Equation L–8 of this section:
l =1
EBkip = Bkip − ∑ cBkj ∗ WDj − ∑ cBkl ∗ S Rl
Where:
EBkip = Mass of by-product k emitted from
production process i over the period p
(metric tons).
Bkip = Mass of by-product k generated by
production process i over the period p
(metric tons).
CBkj = Concentration (mass fraction) of the
by-product k in stream j of destroyed
wastes over the period p. If this
concentration is only a trace
concentration, CBj is equal to zero.
WDj = The mass of wastes that are removed
from production process i in stream j and
that are destroyed over the period p
(metric tons, defined in Equation L–5 of
this section).
CBkl = The concentration (mass fraction) of
the by-product k in stream l of
recaptured material over the period p. If
this concentration is only a trace
concentration, CBkl is equal to zero.
SRl = The mass of materials that are removed
from production process i in stream l
and that are recaptured over the period
p.
q = Number of waste streams destroyed in
production process i.
v = Number of streams recaptured in
production process i.
concentration is only a trace
concentration, CBkj is equal to zero.
Sj = Mass flow of process stream j of
production process i over the period p.
q = Number of streams in production process
i.
v
j =l
(f) Yield loss related to by-product k
for production process i over period p
shall be estimated using Equation L–6 of
this section:
(Eq. L-6)
* ME p )
occurs in any process stream in more
than trace concentrations, the mass of
by-product k generated by production
process i over the period p shall be
estimated using Equation L–7 of this
section:
Bkip =
into the destruction device over the
period p (metric tons).
DE = Destruction Efficiency of the
destruction device (fraction).
Frm 00210
Fmt 4701
Sfmt 4702
with an accuracy and precision of 5
percent or better at the concentrations of
the process samples. This concentration
(mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the reactant permanently
removed from the production process.
(d) If the waste permanently removed
from the production process and fed
into the destruction device contains
more than trace concentrations of the
fluorinated GHG product, the mass of
waste fed into the destruction device
shall be measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the product, the
concentration of the product shall be
measured at least daily using equipment
and methods (e.g., gas chromatography)
with an accuracy and precision of 5
percent or better at the concentrations of
the process samples.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.056</MATH>
LBkip =
Where:
LBkip = Yield loss related to by-product k for
production process i over the period p
(metric tons).
Bkip = Mass of by-product k generated by
production process i over the period p
(metric tons, defined in Equation L–7 of
this section).
MWP = Molecular weight of the fluorinated
GHG produced.
MWBk = Molecular weight of by-product k.
MEBk = Moles of the element shared by the
reactant, product, and by-product k per
mole of by-product k.
MEP = Moles of the element shared by the
reactant, product, and by-product k per
mole of the product.
(Eq. L-5)
EP10AP09.055</MATH>
(e) The mass of wastes removed from
production process i in stream j and
destroyed over the period p shall be
estimated using Equation L–5 of this
section:
WDj = WFj ∗ DE
EP10AP09.054</MATH>
RR = Total mass of the reactant that is
permanently removed from production
process i over the period p (metric tons).
EP10AP09.053</MATH>
16656
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(e) If a by-product is responsible for
yield loss and occurs in any process
stream in more than trace
concentrations, the mass flow of each
process stream that contains more than
trace concentrations of the by-product
shall be measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the by-product, the
concentration of the by-product shall be
measured at least daily using equipment
and methods (e.g., gas chromatography)
with an accuracy and precision of 5
percent or better at the concentrations of
the process samples.
(f) If a by-product is a fluorinated
GHG, occurs in more than trace
concentrations in any process stream,
occurs in more than trace
concentrations in any stream that is
recaptured or is fed into a destruction
device, and is not completely
recaptured or completely destroyed; the
mass flow of each stream that contains
more than trace concentrations of the
by-product and that is recaptured or is
fed into the destruction device or shall
be measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the by-product, the
concentration of the by-product shall be
measured at least daily using equipment
and methods (e.g., gas chromatography)
with an accuracy and precision of 5
percent or better at the concentrations of
the process samples.
(g) All flowmeters, scales, load cells,
and volumetric and density measures
used to measure quantities that are to be
reported under § 98.126 shall be
calibrated using suitable NIST-traceable
standards and suitable methods
published by a consensus standards
organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively,
calibration procedures specified by the
flowmeter, scale, or load cell
manufacturer may be used. Calibration
shall be performed prior to the first
reporting year. After the initial
calibration, recalibration shall be
performed at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
(h) All gas chromatographs used to
determine the concentration of
fluorinated greenhouse gases in process
streams shall be calibrated at least
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
monthly through analysis of certified
standards with known concentrations of
the same chemicals in the same ranges
(fractions by mass) as the process
samples. Calibration gases prepared
from a high-concentration certified
standard using a gas dilution system
that meets the requirements specified in
Test Method 205, 40 CFR Part 51,
Appendix M may also be used.
(i) For purposes of equation L–5, the
destruction efficiency can initially be
equated to the destruction efficiency
determined during a previous
performance test of the destruction
device or, if no performance test has
been done, the destruction efficiency
provided by the manufacturer of the
destruction device. Fluorinated GHG
production facilities that destroy
fluorinated GHGs shall conduct annual
measurements of mass flow and
fluorinated GHG concentrations at the
outlet of the thermal oxidizer in
accordance with EPA Method 18 at 40
CFR part 60, appendix A–6. Tests shall
be conducted under conditions that are
typical for the production process and
destruction device at the facility. The
sensitivity of the emissions tests shall be
sufficient to detect emissions equal to
0.01 percent of the mass of fluorinated
GHGs being fed into the destruction
device. If the test indicates that the
actual DE of the destruction device is
lower than the previously determined
DE, facilities shall either:
(1) Substitute the DE implied by the
most recent emissions test for the
previously determined DE in the
calculations in § 98.123, or
(2) Perform more extensive
performance testing of the DE of the
oxidizer and use the DE determined by
the more extensive testing in the
calculations in § 98.123.
(j) In their estimates of the mass of
fluorinated GHGs destroyed, fluorinated
GHG production facilities that destroy
fluorinated GHGs shall account for any
temporary reductions in the destruction
efficiency that result from any startups,
shutdowns, or malfunctions of the
destruction device, including departures
from the operating conditions defined in
state or local permitting requirements
and/or oxidizer manufacturer
specifications.
(k) Fluorinated GHG production
facilities shall account for fluorinated
GHG emissions that occur as a result of
startups, shutdowns, and malfunctions,
either recording fluorinated GHG
emissions during these events, or
documenting that these events do not
result in significant fluorinated GHG
emissions.
PO 00000
Frm 00211
Fmt 4701
Sfmt 4702
16657
§ 98.125 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation or if a required process
sample is not taken), a substitute data
value for the missing parameter shall be
used in the calculations, according to
the following requirements:
(1) For each missing value of the mass
of fluorinated GHG produced, the mass
of reactants fed into the production
process, the mass of reactants
permanently removed from the
production process, the mass flow of
process streams containing more than
trace concentrations of by-products that
lead to yield losses, or the mass of
wastes fed into the destruction device;
the substitute value of that parameter
shall be a secondary mass measurement
taken during the period the primary
mass measurement was not available.
For example, if the mass produced is
usually measured with a flowmeter at
the inlet to the day tank and that
flowmeter fails to meet an accuracy or
precision test, malfunctions, or is
rendered inoperable; then the mass
produced may be estimated by
calculating the change in volume in the
day tank and multiplying it by the
density of the product.
(2) For each missing value of
fluorinated GHG concentration, the
substitute data value shall be the
arithmetic average of the quality-assured
values of that parameter immediately
preceding and immediately following
the missing data incident. If no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
(3) If the methods specified in
paragraphs (a)(1) and (2) of this section
are likely to significantly under- or
overestimate the value of the parameter
during the period when data were
missing, you shall develop a best
estimate of the parameter, documenting
the methods used, the rationale behind
them, and the reasons why the methods
specified in (a)(1) and (2) would lead to
a significant under- or overestimate of
the parameter.
§ 98.126
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), you shall report
the following information for each
production process at the facility.
E:\FR\FM\10APP2.SGM
10APP2
16658
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(1) The total mass of the fluorinated
GHG produced in metric tons, by
chemical.
(2) The total mass of each reactant fed
into the production process in metric
tons, by chemical.
(3) The total mass of each reactant
permanently removed from the
production process in metric tons, by
chemical.
(4) The total mass of the fluorinated
GHG product removed from the
production process and destroyed.
(5) The mass of each by-product
generated.
(6) The mass of each by-product
destroyed at the facility.
(7) The mass of each by-product
recaptured and sent off-site for
destruction.
(8) The mass of each by-product
recaptured for other purposes.
(9) The mass of each fluorinated GHG
emitted.
(b) Where missing data have been
estimated pursuant to § 98.125, you
shall report the information specified in
paragraphs (b)(1) and (2) of this section.
(1) The reason the data were missing,
the length of time the data were missing,
the method used to estimate the missing
data, and the estimates of those data.
(2) Where the missing data have been
estimated pursuant to § 98.125(a)(3),
you shall also report the rationale for
the methods used to estimate the
missing data and why the methods
specified in § 98.125 (a)(1) and (2)
would lead to a significant under- or
overestimate of the parameter(s).
(c) A fluorinated GHG production
facility that destroys fluorinated GHGs
shall report the results of the annual
fluorinated GHG concentration
measurements at the outlet of the
destruction device, including:
(1) Flow rate of fluorinated GHG being
fed into the destruction device in kg/hr.
(2) Concentration (mass fraction) of
fluorinated GHG at the outlet of the
destruction device.
(3) Flow rate at the outlet of the
destruction device in kg/hr.
(4) Emission rate calculated from
paragraphs(c)(2) and (c)(3) of this
section in kg/hr.
(d) A fluorinated GHG production
facility that destroys fluorinated GHGs
shall submit a one-time report
containing the following information:
(1) Destruction efficiency (DE) of each
destruction unit.
(2) Test methods used to determine
the destruction efficiency.
(3) Methods used to record the mass
of fluorinated GHG destroyed.
(4) Chemical identity of the
fluorinated GHG(s) used in the
performance test conducted to
determine DE.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(5) Name of all applicable federal or
state regulations that may apply to the
destruction process.
(6) If any process changes affect unit
destruction efficiency or the methods
used to record mass of fluorinated GHG
destroyed, then a revised report must be
submitted to reflect the changes. The
revised report must be submitted to EPA
within 60 days of the change.
§ 98.127
Records that must be retained.
(a) In addition to the data required by
§§ 98.123 and 98.126, you shall retain
the following records:
(1) Dated records of the data used to
estimate the data reported under
§§ 98.123 and 98.126.
(2) Dated records documenting the
initial and periodic calibration of the
gas chromatographs, weigh scales,
flowmeters, and volumetric and density
measures used to measure the quantities
reported under this subpart, including
the industry standards or manufacturer
directions used for calibration pursuant
to § 98.124(g) and (h).
(b) In addition to the data required by
paragraph (a) of this section, the
designated representative of a
fluorinated GHG production facility that
destroys fluorinated GHGs shall keep
records of test reports and other
information documenting the facility’s
one-time destruction efficiency report
and annaul destruction device outlet
reports in § 98.126(c) and (d).
§ 98.128
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
HH of this part.
(c) Emissions of CH4 from on-site
wastewater treatment. You must follow
the requirements of subpart II of this
part.
§ 98.133
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart N—Glass Production
§ 98.140
Definition of the source category.
(a) A glass manufacturing facility
manufactures flat glass, container glass,
pressed and blown glass, or wool
fiberglass by melting a mixture of raw
materials to produce molten glass and
form the molten glass into sheets,
containers, fibers, or other shapes. A
glass manufacturing facility uses one or
more continuous glass melting furnaces
to produce glass.
(b) A glass melting furnace that is an
experimental furnace or a research and
development process unit is not subject
to this subpart.
§ 98.141
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a glass production process and
the facility meets the requirements of
either § 98.2(a)(1) or (2).
§ 98.142
GHGs to report.
Food processing facilities prepare raw
ingredients for consumption by animals
or humans. Food processing facilities
transform raw ingredients into food,
transform food into other forms for
consumption by humans or animals, or
transform food for further processing by
the food processing industry.
(a) You must report CO2 process
emissions from each continuous glass
melting furnace at your glass
manufacturing facility as required by
this subpart.
(b) You must report the CO2, N2O, and
CH4 emissions from fuel combustion at
each continuous glass melting furnace
and at any other on-site stationary fuel
combustion unit. For each stationary
fuel combustion unit, you must follow
the requirements of subpart C of this
part.
§ 98.131
§ 98.143
Subpart M—Food Processing
§ 98.130
Definition of the source category.
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a food processing operation
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.132
GHGs to report.
You must report:
(a) Emissions of CO2, N2O, and CH4
from on-site stationary combustion. You
must follow the requirements of subpart
C of this part.
(b) Emissions of CH4 from on-site
landfills. You must follow the
PO 00000
Frm 00212
Fmt 4701
Sfmt 4702
Calculating GHG emissions.
(a) If you operate and maintain a
continuous emission monitoring system
(CEMS) that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must estimate total CO2 emissions
according to the requirements in
§ 98.33.
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you shall calculate process emissions of
CO2 from each glass melting furnace
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
according to paragraphs (b)(1) through
(5) of this section, except as specified in
paragraph (c) of this section.
(1) For each carbonate-based raw
material charged to the furnace, obtain
from the supplier of the raw material the
carbonate-based mineral mass fraction.
(2) Determine the quantity of each
carbonate-based raw material charged to
the furnace.
(3) Apply the appropriate emission
factor for each carbonate-based raw
E CO 2 =
n
∑ MF • M
i
i
• EFi • Fi
16659
material charged to the furnace, as
shown in Table N–1 to this subpart.
(4) Use Equation N–1 of this subpart
to calculate process mass emissions of
CO2 for each furnace:
(Eq. N-1)
i =1
MFi = Mass fraction of carbonate-based
mineral i in carbonate-based raw
material i (dimensionless unit).
Mi = Mass of carbonate-based raw material i
charged to furnace (metric ton/yr).
EFi = Emission factor for carbonate-based raw
material i (metric ton CO2/metric ton
carbonate-based raw material).
k
∑E
i =1
Where:
CO2 = Total annual process CO2 emissions
from glass manufacturing facility (metric
tons/year).
ECO2i = Annual CO2 emissions from glass
melting furnace i (metric tons CO2/year).
k = Number of continuous glass melting
furnaces.
(c) As an alternative to data provided
by the raw material supplier, a value of
1.0 can be used for the mass fraction
(MFi) of carbonate-based mineral i in
Equation N–1 of this section.
§ 98.144 Monitoring and QA/QC
requirements.
(a) You shall determine annual
amounts of carbonate-based raw
materials charged to each continuous
glass melting furnace using calibrated
scales or weigh hoppers. Total annual
mass charged to glass melting furnaces
at the facility shall be compared to
records of raw material purchases for
the year.
(b) If raw material supplier data are
used to determine carbonate-based
mineral mass fractions according to
§ 98.143(b)(1), measurements of the
mass fraction of each carbonate-based
mineral in the carbonate-based raw
materials shall be made at least annually
to verify the mass fraction data provided
by the supplier of the raw material; such
measurements shall be based on
sampling and chemical analysis
conducted by a certified laboratory
using a suitable method published by a
consensus standards organization (e.g.,
ASTM Method D3682, Test Method for
Major and Minor Elements in Coal and
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
CO2 i
(Eq. N-2)
Coke Ash by Atomic Absorption
Method).
§ 98.145 Procedures for estimating
missing data.
(a) Missing data on the monthly
amounts of carbonate-based raw
materials charged to any continuous
glass melting furnace shall be replaced
by the average of the data from the
previous month and the following
month for each carbonate-based raw
material charged.
(b) Missing data on the mass fractions
of carbonate-based minerals in the
carbonate-based raw materials shall be
replaced using the assumption that the
mass fraction of each carbonate based
mineral is 1.0.
§ 98.146
Data reporting requirements.
You shall report the information
specified in paragraphs (a) through (d)
of this section for each continuous glass
melting furnace.
(a) Annual process emissions of CO2,
in metric tons/yr.
(b) Annual quantity of each carbonatebased raw material charged, in metric
tons/yr.
(c) Annual quantity of glass produced,
in metric tons/yr.
(d) If process CO2 emissions are
calculated based on data provided by
the raw material supplier according to
§ 98.143(a)(1), the carbonate-based
mineral mass fraction (as percent) for
each carbonate-based raw material
charged to a continuous glass melting
furnace.
PO 00000
Frm 00213
(5) You must determine the total
process CO2 emissions from continuous
glass melting furnaces at the facility
using Equation N–2 of this section:
Fmt 4701
Sfmt 4702
§ 98.147
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the records listed in paragraphs (a)
through (e) of this section.
(a) Total number of continuous glass
melting furnaces.
(b) Monthly glass production rate for
each continuous glass melting furnace.
(c) Monthly amount of each
carbonate-based raw material charged to
each continuous glass melting furnace.
(d) If process CO2 emissions are
calculated using data provided by the
raw material supplier according to
§ 98.143(b)(1), you must retain the
records in paragraphs (d)(1) and (2) of
this section.
(1) Data on carbonate-based mineral
mass fractions provided by the raw
material supplier.
(2) Results of all tests used to verify
the carbonate-based mineral mass
fraction for each carbonate-based raw
material charged to a continuous glass
melting furnace.
(e) All other documentation used to
support the reported GHG emissions.
§ 98.148
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE N–1 OF SUBPART N—CO2
EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS
Carbonate-based raw
material—mineral
Limestone—CaCO3 ..............
E:\FR\FM\10APP2.SGM
10APP2
CO2 Emission
factor a
0.440
EP10AP09.058</MATH>
CO 2 =
Fi = Fraction of calcination achieved for
carbonate-based raw material i, assumed
to be equal to 1.0 (dimensionless unit).
EP10AP09.057</MATH>
Where:
ECO2 = Process mass emissions of CO2 (metric
ton/yr) from the furnace.
n = Number of carbonate-based raw materials
charged to furnace.
16660
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
HFC–23 destruction process and the
TABLE N–1 OF SUBPART N—CO2
EMISSION FACTORS FOR CAR- facility meets the requirements of either
BONATE-BASED RAW MATERIALS— § 98.2(a)(1) or (2).
Continued
§ 98.152 GHGs to report.
0.415
a Emission factors in units of metric tons of
CO2 emitted per metric ton of carbonatebased raw material charged to the furnace.
Subpart O—HCFC–22 Production and
HFC–23 Destruction
§ 98.150
Definition of the source category.
The HCFC–22 production and HFC–
23 destruction source category consists
of HCFC–22 production processes and
HFC–23 destruction processes.
(a) An HCFC–22 production process
produces HCFC–22
(chlorodifluoromethane, or CHClF2)
from chloroform (CHCl3) and hydrogen
fluoride (HF).
(b) An HFC–23 destruction process is
any process in which HFC–23
undergoes destruction. An HFC–23
destruction process may or may not be
co-located with an HCFC–22 production
process at the same facility.
§ 98.151
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a HCFC–22 production or
§ 98.153
Calculating GHG emissions.
(a) The total mass of HFC–23
generated from each HCFC–22
production process shall be estimated
by using one of two methods, as
applicable:
(1) Where the mass flow of the
combined stream of HFC–23 and
another reaction product (e.g., HCl) is
measured, multiply the daily (or more
frequent) HFC–23 concentration
measurement (which may be the average
of more frequent concentration
measurements) by the daily (or more
frequent) mass flow of the combined
stream of HFC–23 and the other
product. To estimate annual HFC–23
production, sum the daily (or more
frequent) estimates of the quantities of
n
⎛c ⎞
G23 = ∑ ⎜ 23 ⎟ ∗ P22 ∗ 10−3
p =1 ⎝ c22 ⎠
Where:
G23 = Mass of HFC–23 generated annually
(metric tons).
c23 = Fraction HFC–23 by weight in HCFC–
22/HFC–23 stream.
c22 = Fraction HCFC–22 by weight in HCFC–
22/HFC–23 stream.
P22 = Mass of HCFC–22 produced over the
period p (kg).
p = Period over which masses and
concentrations are measured.
n = Number of concentration and mass
measurement periods for the year.
10¥3 = Conversion factor from kilograms to
metric tons.
Where:
E23 = Mass of HFC–23 emitted annually
(metric tons).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. O-3)
Where:
P22 = Mass of HCFC–22 produced over the
period p (kg).
O22 = mass of HCFC–22 that is measured
coming out of the Production process
over the period p (kg).
U22 = Mass of used HCFC–22 that is added
to the production process upstream of
E23 = G23 − ( S23 + OD23 + D23 )
Frm 00214
Fmt 4701
Sfmt 4702
the output measurement over the period
p (kg).
LF = Factor to account for the loss of HCFC–
22 upstream of the measurement. The
value for LF shall be determined
pursuant to § 98.154(e).
(c) For HCFC–22 production facilities
that do not use a thermal oxidizer or
have a thermal oxidizer that is not
directly connected to the HCFC–22
production equipment, HFC–23
emissions shall be estimated using
Equation O–4 of this section:
(Eq. O- 4)
G23 = Mass of HFC–23 generated annually
(metric tons).
S23 = Mass of HFC–23 packaged for sale
annually (metric tons).
PO 00000
(2) Where the mass of only a reaction
product other than HFC–23 (either
HCFC–22 or HCl) is measured, multiply
the ratio of the daily (or more frequent)
measurement of the HFC–23
concentration and the daily (or more
frequent) measurement of the other
product concentration by the daily (or
more frequent) mass produced of the
other product. To estimate annual HFC–
23 production, sum the daily (or more
frequent) estimates of the quantities of
HFC–23 produced over the year. This
calculation is summarized in Equation
O–2 of this section, assuming that the
other product is HCFC–22. If the other
product is HCl, HCl may be substituted
for HCFC–22 in Equations O–2 and O–
3 of this section.
(Eq. O - 2)
(b) The mass of HCFC–22 produced
over the period p shall be estimated by
using Equation O–3 of this section:
P22 = LF ∗ ( O22 − U 22 )
Where:
G23 = Mass of HFC–23 generated annually
(metric tons).
c23 = Fraction HFC–23 by weight in HFC–23/
other product stream.
Fp = Mass flow of HFC–23/other product
stream during the period p (kg).
p = Period over which mass flows and
concentrations are measured.
n = Number of concentration and flow
measurement periods for the year.
10¥3 = Conversion factor from kilograms to
metric tons.
OD23 = Mass of HFC–23 sent off-site for
destruction (metric tons).
D23 = Mass of HFC–23 destroyed on-site
(metric tons).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.062</MATH>
0.477
EP10AP09.061</MATH>
Dolomite—CaMg(CO3)2 ........
Sodium carbonate/soda
ash—Na2CO3 ....................
(Eq. O -1)
p =1
EP10AP09.060</MATH>
CO2 Emission
factor a
n
G23 = ∑ c23 ∗ Fp ∗ 10−3
EP10AP09.059</MATH>
Carbonate-based raw
material—mineral
(a) You must report the CO2, N2O, and
CH4 emissions from each on-site
stationary combustion unit. For these
stationary combustion units, you must
follow the applicable calculation
procedures, monitoring and QA/QC
methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of subpart
C of this part.
(b) You must report HFC–23
emissions from HCFC–22 production
processes and HFC–23 destruction
processes.
HFC–23 produced over the year. This
calculation is summarized in Equation
O–1 of this section:
16661
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
E23 = Mass of HFC–23 emitted annually
(metric tons).
EL = Mass of HFC–23 emitted annually from
equipment leaks, calculated using
Equation O–6 (metric tons).
EPV = Mass of HFC–23 emitted annually from
process vents, calculated using Equation
O–7 (metric tons).
(d) For HCFC–22 production facilities
that use a thermal oxidizer connected to
the HCFC–22 production equipment,
HFC–23 emissions shall be estimated
using Equation O–5 of this section:
E23 = EL + EPV + ED
(Eq. O-5)
ED = Mass of HFC–23 emitted annually from
thermal oxidizer (metric tons), calculated
using Equation O–9 of this section.
(e) The mass of HFC–23 emitted
annually from equipment leaks (for use
in Equation O–5 of this section) shall be
estimated by using Equation O–6 of this
section:
n
EL = ∑ ∑ c23 ∗ ( FGt ∗ N Gt + FLt ∗ N Lt ) ∗ 10−3
(Eq. O-6)
p =1 t
Where:
EL = Mass of HFC–23 emitted annually from
equipment leaks (metric tons).
c23 = Fraction HFC–23 by weight in the
stream(s) in the equipment.
FGt = The applicable leak rate specified in
table O–1 for each source of equipment
type and service t with a screening value
greater than or equal to 10,000 ppmv (kg/
hr/source).
NGt = The number of sources of equipment
type and service t with screening values
greater than or equal to 10,000 ppmv as
determined according to § 98.154(h).
FLt = The applicable leak rate specified in
table O–1 for each source of equipment
type and service t with a screening value
of less than 10,000 ppmv (kg/hr/source).
NLt = The number of sources of equipment
type and service t with screening values
less than 10,000 ppmv as determined
according to § 98.154(i).
p = One hour.
n = Number of hours during the year during
which equipment contained HFC–23.
t = Equipment type and service as specified
in Table O–1.
10¥3 = Factor converting kg to metric tons.
TABLE O–1 OF SUBPART O—EMISSION FACTORS FOR EQUIPMENT LEAKS
Emission factor (kg/hr/source)
Equipment type
Service
Valves ................................................................................................
Valves ................................................................................................
Pump seals ........................................................................................
Compressor seals ..............................................................................
Pressure relief valves ........................................................................
Connectors .........................................................................................
Open-ended lines ..............................................................................
Gas ..............................................
Light liquid ...................................
Light liquid ...................................
Gas ..............................................
Gas ..............................................
All ................................................
All ................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
⎞
−3
⎟ * l p ∗ 10
⎠
(h) The total mass of HFC–23 emitted
from destruction devices shall be
estimated by using Equation O–9 of this
section:
ED = FD − D
(Eq. O-9)
Where:
ED = Mass of HFC–23 emitted annually from
the destruction device (metric tons).
FD = Mass of HFC–23 fed into the destruction
device annually (metric tons).
D = Mass of HFC–23 destroyed annually
(metric tons).
PO 00000
Frm 00215
Fmt 4701
Sfmt 4702
§ 98.154 Monitoring and QA/QC
requirements.
These requirements apply to
measurements that are reported under
this subpart or that are used to estimate
reported quantities pursuant to § 98.153.
(a) The concentrations (fractions by
weight) of HFC–23 and HCFC–22 in the
product stream shall be measured at
least daily using equipment and
methods (e.g., gas chromatography) with
an accuracy and precision of 5 percent
or better at the concentrations of the
process samples.
(b) The mass flow of the product
stream containing the HFC–23 shall be
measured continuously using a flow
meter with an accuracy and precision of
1.0 percent of full scale or better.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.066</MATH>
D = Mass of HFC–23 destroyed annually
(metric tons).
FD = Mass of HFC–23 fed into the destruction
device annually (metric tons).
DE = Destruction Efficiency of the
destruction device (fraction).
EP10AP09.067</MATH>
(Eq. O-7)
EP10AP09.065</MATH>
(g) For facilities that destroy HFC–23,
the total mass of HFC–23 destroyed
shall be estimated by using Equation O–
8 of this section:
(Eq. O-8)
0.000131
0.000165
0.00187
0.0894
0.0447
0.0000810
0.00150
EP10AP09.064</MATH>
Where:
EPV = Mass of HFC–23 emitted annually from
process vents (metric tons).
ERT = The HFC–23 emission rate from the
process vents during the period of the
most recent test (kg/hr).
PRp = The HCFC–22 production rate during
the period p (kg/hr).
PRT = The HCFC–22 production rate during
the most recent test period (kg/hr).
lp = The length of the period p (hours).
10¥3= Factor converting kg to metric tons.
n = The number of periods in a year.
D = FD * DE
0.0782
0.0892
0.243
1.608
1.691
0.113
0.01195
estimated by using Equation O–7 of this
section:
n
⎛ PR p
EPV = ∑ ERT * ⎜
p=1
⎝ PRT
Where:
<10,000 ppmv
EP10AP09.063</MATH>
(f) The mass of HFC–23 emitted
annually from process vents (for use in
Equation O–5 of this section) shall be
≥10,000 ppmv
16662
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(c) The mass of HCFC–22 or HCl
coming out of the production process
shall be measured at least daily using
weigh scales, flowmeters, or a
combination of volumetric and density
measurements with an accuracy and
precision of 1.0 percent of full scale or
better.
(d) The mass of any used HCFC–22
added back into the production process
upstream of the output measurement in
paragraph (c) of this section shall be
measured at least daily (when being
added) using flowmeters, weigh scales,
or a combination of volumetric and
density measurements with an accuracy
and precision of 1.0 percent of full scale
or better.
(e) The loss factor LF in Equation O–
3 of this subpart for the mass of HCFC–
22 produced shall have the value 1.015
or another value that can be
demonstrated, to the satisfaction of the
Administrator, to account for losses of
HCFC–22 between the reactor and the
point of measurement at the facility
where production is being estimated.
(f) The mass of HFC–23 packaged for
sale shall be measured at least daily
(when being packaged) using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 1.0 percent of full scale or
better.
(g) The mass of HFC–23 sent off-site
for destruction shall be measured at
least daily (when being packaged) using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 1.0 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than HFC–23, the
concentration of the fluorinated GHG
shall be measured at least daily using
equipment and methods (e.g., gas
chromatography) with an accuracy and
precision of 5 percent or better at the
concentrations of the process samples.
This concentration (mass fraction) shall
be multiplied by the mass measurement
to obtain the mass of the HFC–23 sent
to another facility for destruction.
(h) The number of sources of
equipment type t with screening values
greater than or equal to 10,000 ppmv
shall be determined using EPA Method
21 at 40 CFR part 60, appendix A–7, and
defining a leak as follows:
(1) A leak source that could emit
HFC–23, and
(2) A leak source at whose surface a
concentration of fluorocarbons equal to
or greater than 10,000 ppm is measured.
(i) The number of sources of
equipment type t with screening values
less than 10,000 ppmv shall be the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
difference between the number of leak
sources of equipment type t that could
emit HFC–23 and the number of sources
of equipment type t with screening
values greater than or equal to 10,000
ppmv as determined under paragraph
(h) of this section.
(j) The mass of HFC–23 emitted from
process vents shall be estimated at least
monthly by conducting emissions tests
at process vents at least annually and by
incorporating the results of the most
recent emissions test into Equation O–
6 of this subpart. Emissions tests shall
be conducted in accordance with EPA
Method 18 at 40 CFR part 60, appendix
A–6, under conditions that are typical
for the production process at the
facility. The sensitivity of the tests shall
be sufficient to detect an emission rate
that would result in annual emissions of
200 kg of HFC–23 if sustained over one
year.
(k) For purposes of Equation O–8, the
destruction efficiency can initially be
equated to the destruction efficiency
determined during a previous
performance test of the destruction
device or, if no performance test has
been done, the destruction efficiency
provided by the manufacturer of the
destruction device. HFC–23 destruction
facilities shall conduct annual
measurements of mass flow and HFC–23
concentrations at the outlet of the
thermal oxidizer in accordance with
EPA Method 18 at 40 CFR part 60,
appendix A–6. Tests shall be conducted
under conditions that are typical for the
production process and destruction
device at the facility. The sensitivity of
the emissions tests shall be sufficient to
detect emissions equal to 0.01 percent of
the mass of HFC–23 being fed into the
destruction device. If the test indicates
that the actual DE of the destruction
device is lower than the previously
determined DE, facilities shall either:
(1) Substitute the DE implied by the
most recent emissions test for the
previously determined DE in the
calculations in § 98.153.
(2) Perform more extensive
performance testing of the DE of the
oxidizer and use the DE determined by
the more extensive testing in the
calculations in § 98.153.
(l) Designated representatives of
HCFC–22 production facilities shall
account for HFC–23 generation and
emissions that occur as a result of
startups, shutdowns, and malfunctions,
either recording HFC–23 generation and
emissions during these events, or
documenting that these events do not
result in significant HFC–23 generation
and/or emissions.
(m) The mass of HFC–23 fed into the
destruction device shall be measured at
PO 00000
Frm 00216
Fmt 4701
Sfmt 4702
least daily using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of 1.0 percent of
full scale or better. If the measured mass
includes more than trace concentrations
of materials other than HFC–23, the
concentrations of the HFC–23 shall be
measured at least daily using equipment
and methods (e.g., gas chromatography)
with an accuracy and precision of 5
percent or better at the concentrations of
the process samples. This concentration
(mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the HFC–23 destroyed.
(n) In their estimates of the mass of
HFC–23 destroyed, designated
representatives of HFC–23 destruction
facilities shall account for any
temporary reductions in the destruction
efficiency that result from any startups,
shutdowns, or malfunctions of the
destruction device, including departures
from the operating conditions defined in
state or local permitting requirements
and/or oxidizer manufacturer
specifications.
(o) All flowmeters, scales, and load
cells used to measure quantities that are
to be reported under § 98.156 shall be
calibrated using suitable NIST-traceable
standards and suitable methods
published by a consensus standards
organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively,
calibration procedures specified by the
flowmeter, scale, or load cell
manufacturer may be used. Calibration
shall be performed prior to the first
reporting year. After the initial
calibration, recalibration shall be
performed at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
(p) All gas chromatographs used to
determine the concentration of HFC–23
in process streams shall be calibrated at
least monthly through analysis of
certified standards (or of calibration
gases prepared from a highconcentration certified standard using a
gas dilution system that meets the
requirements specified in Test Method
205, 40 CFR part 51, appendix M) with
known HFC–23 concentrations that are
in the same range (fractions by mass) as
the process samples.
§ 98.155 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation or if a required process
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
sample is not taken), a substitute data
value for the missing parameter shall be
used in the calculations, according to
the following requirements:
(1) For each missing value of the
HFC–23 or HCFC–22 concentration, the
substitute data value shall be the
arithmetic average of the quality-assured
values of that parameter immediately
preceding and immediately following
the missing data incident. 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 each missing value of the
product stream mass flow or product
mass, the substitute value of that
parameter shall be a secondary product
measurement. If that measurement is
taken significantly downstream of the
usual mass flow or mass measurement
(e.g., at the shipping dock rather than
near the reactor), the measurement shall
be multiplied by 1.015 to compensate
for losses.
(3) Notwithstanding paragraphs (a)(1)
and (2) of this section, if the owner or
operator has reason to believe that the
methods specified in paragraphs (a)(1)
and (2) of this section are likely to
significantly under- or overestimate the
value of the parameter during the period
when data were missing (e.g., because
the monitoring failure was linked to a
process disturbance that is likely to
have significantly increased the HFC–23
generation rate), the designated
representative of the HCFC–22
production facility shall develop his or
her best estimate of the parameter,
documenting the methods used, the
rationale behind them, and the reasons
why the methods specified in (a)(1) and
(2) would probably lead to a significant
under- or overestimate of the parameter.
§ 98.156
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), the designated
representative of an HCFC–22
production facility shall report the
following information at the facility
level:
(1) The mass of HCFC–22 produced in
metric tons.
(2) The mass of reactants fed into the
process in metric tons of reactant.
(3) The mass (in metric tons) of
materials other than HCFC–22 and
HFC–23 (i.e., unreacted reactants, HCl
and other by-products) that occur in
more than trace concentrations and that
are permanently removed from the
process.
(4) The method for tracking startups,
shutdowns, and malfunctions and HFC–
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
23 generation/emissions during these
events.
(5) The names and addresses of
facilities to which any HFC–23 was sent
for destruction, and the quantities of
HFC–23 (metric tons) sent to each.
(6) The total mass of the HFC–23
generated in metric tons.
(7) The mass of any HFC–23 packaged
for sale in metric tons.
(8) The mass of any HFC–23 sent off
site for destruction in metric tons.
(9) The mass of HFC–23 emitted in
metric tons.
(10) The mass of HFC–23 emitted
from equipment leaks in metric tons.
(11) The mass of HFC–23 emitted
from process vents in metric tons.
(b) Where missing data have been
estimated pursuant to § 98.155, the
designated representative of the HCFC–
22 production facility or HCF–23
destruction facility shall report the
reason the data were missing, the length
of time the data were missing, the
method used to estimate the missing
data, and the estimates of those data.
(1) Where the missing data have been
estimated pursuant to § 98.155(a)(3), the
designated representative shall also
report the rationale for the methods
used to estimate the missing data and
why the methods specified in
§ 98.155(a)(1) and (2) would probably
lead to a significant under- or
overestimate of the parameter(s).
(c) In addition to the information
required by § 98.3(c), the designated
representative of a facility that destroys
HFC–23 shall report the following for
each HFC–23 destruction process:
(1) The mass of HFC–23 fed into the
thermal oxidizer.
(2) The mass of HFC–23 destroyed.
(3) The mass of HFC–23 emitted from
the thermal oxidizer.
(d) The designated representative of
each HFC–23 destruction facility shall
report the results of the facility’s annual
HFC–23 concentration measurements at
the outlet of the destruction device,
including:
(1) The flow rate of HFC–23 being fed
into the destruction device in kg/hr.
(2) The concentration (mass fraction)
of HFC–23 at the outlet of the
destruction device.
(3) The flow rate at the outlet of the
destruction device in kg/hr.
(4) The emission rate calculated from
paragraphs (c)(2) and (3) of this section
in kg/hr.
(e) The designated representative of
an HFC–23 destruction facility shall
submit a one-time report including the
following information:
(1) The destruction unit’s destruction
efficiency (DE).
(2) The methods used to determine
the unit’s destruction efficiency.
PO 00000
Frm 00217
Fmt 4701
Sfmt 4702
16663
(3) The methods used to record the
mass of HFC–23 destroyed.
(4) The name of other relevant federal
or state regulations that may apply to
the destruction process.
(5) If any changes are made that affect
HFC–23 destruction efficiency or the
methods used to record volume
destroyed, then these changes must be
reflected in a revision to this report. The
revised report must be submitted to EPA
within 60 days of the change.
§ 98.157
Records that must be retained.
(a) In addition to the data required by
§ 98.3(g), the designated representative
of an HCFC–22 production facility shall
retain the following records:
(1) The data used to estimate HFC–23
emissions.
(2) Records documenting the initial
and periodic calibration of the gas
chromatographs, weigh scales,
volumetric and density measurements,
and flowmeters used to measure the
quantities reported under this rule,
including the industry standards or
manufacturer directions used for
calibration pursuant to § 98.154(o) and
(p).
(b) In addition to the data required by
§ 98.3(g), the designated representative
of a HFC–23 destruction facility shall
retain the following records:
(1) Records documenting their onetime and annual reports in § 98.156(c),
(d), and (e).
(2) Records documenting the initial
and periodic calibration of the gas
chromatographs, weigh scales,
volumetric and density measurements,
and flowmeters used to measure the
quantities reported under this subpart,
including the industry standards or
manufacturer directions used for
calibration pursuant to § 98.154(o) and
(p).
§ 98.158
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart P—Hydrogen Production
§ 98.160
Definition of the source category.
(a) A hydrogen production source
category produces hydrogen gas that is
consumed at sites other than where it is
produced.
(b) This source category comprises
process units that produce hydrogen by
oxidation, reaction, or other
transformations of feedstocks.
(c) This source category includes
hydrogen production facilities located
within a petroleum refinery and that are
not owned or under the direct control of
the refinery owner and operator.
E:\FR\FM\10APP2.SGM
10APP2
16664
GHGs to report.
You must report:
(a) CO2 process emissions for each
hydrogen production process unit.
(b) CO2, CH4, and N2O emissions from
the combustion of fuels in each
hydrogen production unit and any other
stationary combustion units by
following the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
§ 98.163
Calculating GHG emissions.
You must determine CO2 emissions in
accordance with the procedures
specified in either paragraph (a) or (b)
of this section.
(a) Continuous emission monitoring
system. Any hydrogen process unit that
meets the conditions specified in
⎛ k 44
MW ⎞
CO 2 = ⎜ ∑
∗ ( Fdstk ) n ∗ (CC ) n ∗
⎟ ∗ 0.001
MVC ⎠
⎝ n =1 12
Where:
CO2 = Annual CO2 process emissions arising
from feedstock consumption (metric
tons).
(Fdstk)n = Volume of the gaseous feedstock
used in month n (scf of feedstock).
(CC)n = Average carbon content of the
gaseous feedstock, from the analysis
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock
used in month n (gallons of feedstock).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
0.001 = Conversion factor from kg to metric
tons.
(2) Liquid feedstock. You must
calculate the total CO2 process
emissions from liquid feedstock
according to Equation P–2 of this
section:
(Eq. P-2)
(CC)n = Average carbon content of the liquid
feedstock, from the analysis results for
month n (kg C per gallon of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
⎞
⎛ k 44
CO 2 = ⎜ ∑
∗(Fdstk) ∗(CC) ⎟ ∗ 0.001
n
n
12
⎠
⎝ n=1
Where:
CO2 = Annual CO2 emissions from feedstock
consumption in metric tons per month
(metric tons).
(Fdstk)n = Mass of solid feedstock used in
month n (kg of feedstock).
(CC)n = Average carbon content of the solid
feedstock, from the analysis results for
month n (kg C per kg of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
(Eq. P-1)
results for month n (kg C per kg of
feedstock).
MW = Molecular weight of the gaseous
feedstock (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to
carbon. and
⎞
⎛ k 44
CO 2 = ⎜ ∑
∗(Fdstk) ∗(CC) ⎟ ∗ 0.001
n
n
⎠
⎝ n=1 12
(a) Facilities that use CEMS must
comply with the monitoring and QA/QC
procedures specified in § 98.34(e).
(b) The quantity of gaseous or liquid
feedstock consumed must be measured
continuously using a flow meter. The
quantity of solid feedstock consumed
can be obtained from company records
and aggregated on a monthly basis.
(c) You must collect a sample of each
feedstock and analyze the carbon
content of each sample using
Frm 00218
Fmt 4701
Sfmt 4702
(3) Solid feedstock. You must
calculate the total CO2 process
emissions from solid feedstock
according to Equation P–3 of this
section:
(Eq. P-3)
§ 98.164 Monitoring and QA/QC
requirements.
PO 00000
§ 98.33(b)(5)(iii)(A), (B), and (C), or
§ 98.33(b)(5)(ii)(A) through (F) shall
calculate total CO2 emissions using a
continuous emissions monitoring
system according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4).
(b) Feedstock material balance
approach. If you do not measure total
emissions with a CEMS, you must
calculate the annual CO2 process
emissions from feedstock used for
hydrogen production.
(1) Gaseous feedstock. You must
calculate the total CO2 process
emissions from gaseous feedstock
according to Equation P–1 of this
section:
appropriate test methods incorporated
by reference in § 98.7. The minimum
frequency of the fuel sampling and
analysis is monthly.
(d) All fuel flow meters, gas
composition monitors, and heating
value monitors shall be calibrated prior
to the first reporting year, using a
suitable method published by a
consensus standards organization (e.g.,
ASTM, ASME, API, AGA, or others).
Alternatively, calibration procedures
specified by the flow meter
manufacturer may be used. Fuel flow
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.070</MATH>
§ 98.162
requirements, and recordkeeping
requirements of subpart C of this part.
(c) For CO2 collected and used on site
or transferred off site, you must follow
the calculation procedures, monitoring
and QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
PP of this part.
EP10AP09.069</MATH>
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a hydrogen production process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
EP10AP09.068</MATH>
§ 98.161
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
16665
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.165 Procedures for estimating
missing data.
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
for each process unit:
(a) Facilities that use CEMS must
comply with the procedures specified in
§ 98.36(a)(1)(iv).
(b) Annual total consumption of
feedstock for hydrogen production;
annual total of hydrogen produced; and
annual total of ammonia produced, if
applicable.
(c) Monthly analyses of carbon
content for each feedstock used in
hydrogen production (kg carbon/kg of
feedstock).
12
CO 2 = ∑
1
44
12
⎡
⎢( Fs )n
⎣
n
g n
Where:
CO2 = Annual CO2 mass emissions from the
indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fs)n = Mass of the solid fuel combusted in
month ‘‘n’’ (metric tons).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart Q—Iron and Steel Production
§ 98.170
Definition of the source category.
The iron and steel production source
category includes facilities with any of
the following processes: Taconite iron
ore processing, integrated iron and steel
manufacturing, cokemaking not
colocated with an integrated iron and
steel manufacturing process, and
electric arc furnace (EAF) steelmaking
not colocated with an integrated iron
and steel manufacturing process.
Integrated iron and steel manufacturing
means the production of steel from iron
ore or iron ore pellets. At a minimum,
an integrated iron and steel
manufacturing process has a basic
oxygen furnace for refining molten iron
into steel. Each cokemaking process and
EAF process located at a facility with an
integrated iron and steel manufacturing
process is part of the integrated iron and
steel manufacturing facility.
§ 98.171
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an iron and steel production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.172
GHGs to report.
(a) You must report combustionrelated CO2, CH4, and N2O emissions
from each stationary combustion unit
and follow the requirements in subpart
C of this part. Stationary combustion
units include, but are not limited to, by-
(C ) + ( F ) (C )
sf
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the following records:
(a) For all CEMS, you must comply
with the CEMS recordkeeping
requirements in § 98.37.
(b) Monthly analyses of carbon
content for each feedstock used in
hydrogen production.
§ 98.168
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation), a substitute data value for
the missing parameter shall be used in
the calculations, according to the
following requirements:
(a) For missing feedstock supply rates,
use the lesser of the maximum supply
rate that the unit is capable of
processing or the maximum supply rate
that the meter can measure.
(b) There are no missing data
procedures for carbon content. A re-test
must be performed if the data from any
monthly measurements are determined
to be invalid.
(c) For missing CEMS data, you must
use the missing data procedures in
§ 98.35.
§ 98.166
§ 98.167
gf
n
MW
MVC
0.001 + ( F1 )n
(C )
1f
n
Frm 00219
Fmt 4701
Sfmt 4702
§ 98.173
Calculating GHG emissions.
(a) For each taconite indurating
furnace, basic oxygen furnace, nonrecovery coke oven battery, sinter
process, EAF, argon-oxygen
decarburization vessel, and direct
reduction furnace, you must determine
CO2 emissions using the procedures in
paragraph (a)(1), (a)(2), or (3) of this
section as appropriate.
(1) Continuous emissions monitoring
system (CEMS). If you operate and
maintain a CEMS that measures CO2
emissions consistent with the
requirements in subpart C, you must
estimate total CO2 emissions according
to the requirements in § 98.33.
(2) Carbon mass balance method. For
the carbon balance method, calculate
the mass emissions rate of CO2 in each
calendar month for each process as
specified in paragraphs (a)(2)(i) through
(vii) of this section. The calculations are
based on the monthly mass of inputs
and outputs to each process and the
respective weight fraction of carbon. If
you have a process input or output that
contains carbon that is not included in
the Equations, you must account for the
carbon and mass rate of that process
input or output in your calculations.
(i) For taconite indurating furnaces,
estimate CO2 emissions using Equation
Q–1 of this section.
0.001 + ( O )n
(Csf)n = Carbon content of the solid fuel, from
the fuel analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction, e.g., 95% = 0.95).
(Fg)n = Volume of the gaseous fuel combusted
in month ‘‘n’’ (scf).
(Cgf)n = Average carbon content of the
gaseous fuel, from the fuel analysis
PO 00000
product recovery coke oven battery
combustion stacks, blast furnace stoves,
boilers, process heaters, reheat furnaces,
annealing furnaces, flares, flame
suppression, ladle reheaters, and other
miscellaneous combustion sources.
(b) You must report process-related
CO2 emissions from each taconite
indurating furnace; basic oxygen
furnace; non-recovery coke oven battery
combustion stack; sinter process; EAF;
argon-oxygen decarburization vessel;
and direct reduction furnace by
following the procedures in this
subpart.
(c) You must report CO2 emissions
from each coke pushing process by
following the procedures in this
subpart.
( Co ) − ( P )n
(C ) ⎤
⎥
⎦
p n
(Eq. Q-1)
results for month ‘‘n’’ (kg C per kg of
fuel).
MW = Molecular weight of the gaseous fuel
(kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
0.001 = Conversion factor from kg to metric
tons.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.071</MATH>
meters, gas composition monitors, and
heating value monitors shall be
recalibrated either annually or at the
minimum frequency specified by the
manufacturer.
(e) You must document the
procedures used to ensure the accuracy
of the estimates of feedstock
consumption.
16666
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(C0)n = Carbon content of the greenball
(taconite) pellets, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
(P)n = Mass of fired pellets produced by the
furnace in month ‘‘n’’ (metric tons).
(Fl)n = Volume of the liquid fuel combusted
in month ‘‘n’’ (gallons).
(Clf)n = Carbon content of the liquid fuel,
from the fuel analysis results for month
‘‘n’’ (kg C per gallon of fuel).
(O)n = Mass of greenball (taconite) pellets fed
to the furnace in month ‘‘n’’ (metric
tons).
12
CO 2 = ∑
1
44
12
( C Iron )n + ( Scrap )n
⎡( Iron )
n
⎣
(C
Where:
CO2 = Annual CO2 mass emissions from the
basic oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Iron)n = Mass of molten iron charged to the
furnace in month ‘‘n’’ (metric tons).
(CIron)n = Carbon content of the molten iron,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to
the furnace in month ‘‘n’’ (metric tons).
(CScrap)n = Average carbon content of the
ferrous scrap, from the carbon analysis
12
CO 2 = ∑
1
n
12
CO 2 = ∑
1
⎡( Coal )n
⎣
( C Coal )n − ( Coke )n ( CCoke )n ⎤
⎦
(Coal)n = Mass of coal charged to the battery
in month ‘‘n’’ (metric tons).
(CCoal)n = Carbon content of the coal, from the
carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(Coke)n = Mass of coke produced by the
battery in month ‘‘n’’ (metric tons).
44
12
⎡( Fg )
n
⎣
(C )
gf
n
MW
MVC
Flux n
( CSlag )n ⎤
⎦
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace in month ‘‘n’’ (metric tons).
(CFlux)n = Average carbon content of the flux
materials, from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials
(e.g., coal, coke) charged to the furnace
in month ‘‘n’’ (metric tons).
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
44
12
Where:
CO2 = Annual CO2 mass emissions from the
non-recovery coke oven battery (metric
tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(ii) For basic oxygen process furnaces,
estimate CO2 emissions using Equation
Q–2 of this section.
) + ( Flux ) ( C )
Scrap n
( CCarbon )n − ( Steel )n ( CSteel )n − ( Slag )n
+ ( Carbon )n
(Cp)n = Carbon content of the fired pellets,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
0.001 +
(Eq. Q- 2)
(Steel)n = Mass of molten steel produced by
the furnace in month ‘‘n’’ (metric tons).
(CSteel)n = Average carbon content of the steel,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(Slag)n = Mass of slag produced by the
furnace in month ‘‘n’’ (metric tons).
(CSlag)n = Average carbon content of the slag,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(iii) For non-recovery coke oven
batteries, estimate CO2 emissions using
Equation Q–3 of this section.
(Eq. Q-3)
3
(CCoke)n = Carbon content of the coke, from
the carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(iv) For sinter processes, estimate CO2
emissions using Equation Q–4 of this
section.
(Eq. Q-4)
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00220
Fmt 4701
Sfmt 4702
for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Sinter)n = Mass of sinter produced in month
‘‘n’’ (metric tons).
(CSinter)n = Carbon content of the sinter
pellets, from the carbon analysis results
for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(v) For EAFs, estimate CO2 emissions
using Equation Q–5 of this section.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.073</MATH>
MW = Molecular weight of the gaseous fuel
(kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
0.001 = Conversion factor from kg to metric
tons.
(Feed)n = Mass of sinter feed material in
month ‘‘n’’ (metric tons).
(CFeed)n = Carbon content of the sinter feed
material, from the carbon analysis results
EP10AP09.072</MATH>
Where:
CO2 = Annual CO2 mass emissions from the
sinter process (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fg)n = Volume of the gaseous fuel combusted
in month ‘‘n’’ (scf).
(Cgf)n = Average carbon content of the
gaseous fuel, from the fuel analysis
results for month ‘‘n’’ (kg C per kg of
fuel).
EP10AP09.074</MATH>
( Feed )n ( CFeed ) − ( Sinter )n ( CSinter )n ⎤
⎦
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(C )
f
n
( C Iron )n + ( Scrap )n
⎡( Iron )
n
⎣
+ ( Electrode )n
12
CO 2 = ∑
1
Where:
CO2 = Annual CO2 mass emissions from the
argon-oxygen decarburization vessel
(metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
12
CO 2 = ∑
1
( CElectrode )n + ( Carbon )n ( CC ) − ( Steel )n
(Flux)n = Mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace in month ‘‘n’’ (metric tons).
(CFlux)n = Average carbon content of the flux
materials, from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Electrode)n= Mass of carbon electrode
consumed in month ‘‘n’’ (metric tons).
(CElectrode)n = Average carbon content of the
carbon electrode, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
(Carbon)n = Mass of carbonaceous materials
(e.g., coal, coke) charged to the furnace
in month ‘‘n’’ (metric tons).
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon
44
12
[( C Steelin )n − ( CSteelout )n ]
( Steel )n
(C )
gf
MW
MVC
n
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
0.001 + ( Ore )n
(vi) For argon-oxygen decarburization
vessels, estimate CO2 emissions using
Equation Q–6 of this section.
(CSteelout)n = Average carbon content of the
molten steel after decarburization, from
the carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(Core )
(Eq. Q-7)
( CNM )n ⎤
⎦
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
0.001 = Conversion factor from kg to metric
tons.
(Ore)n = Mass of iron ore or iron ore pellets
fed to the furnace in month ‘‘n’’ (metric
tons).
(COre)n = Carbon content of the iron ore, from
the carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(Carbon)n = Mass of carbonaceous materials
(e.g., coal, coke) charged to the furnace
in month ‘‘n’’ (metric tons).
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon
analysis results for month ‘‘n’’ (percent
PO 00000
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
(Steel)n = Mass of molten steel produced by
the furnace in month ‘‘n’’ (metric tons).
(CSteel)n = Average carbon content of the steel,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(Slag)n = Mass of slag produced by the
furnace in month ‘‘n’’ (metric tons).
(CSlag)n = Average carbon content of the slag,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
( CCarbon )n + (Other )n ( COther )n
− ( Iron) n ( CIron )n − ( NM ) n
Where:
CO2 = Annual CO2 mass emissions from the
direct reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fg)n = Volume of the gaseous fuel combusted
on day ‘‘n’’ or in month ‘‘n’’, as
applicable (scf).
(Cgf)n = Average carbon content of the
gaseous fuel, from the fuel analysis
results for month ‘‘n’’ (kg C per kg of
fuel).
MW = Molecular weight of the gaseous fuel
(kg/kg-mole).
(Eq. Q-5)
(Eq. Q-6)
(Steel)n = Mass of molten steel charged to the
vessel in month ‘‘n’’ (metric tons).
(CSteelin)n = Carbon content of the molten steel
before decarburization, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
+ (Carbon) n
n
Slag n
44 ⎡
( Fg )n
12 ⎢
⎣
(vii) For direct reduction furnaces,
estimate CO2 emissions using Equation
Q–7 of this section.
) + ( Flux )
Scrap n
(C )
( CSteel )n − ( Slag )n
Where:
CO2 = Annual CO2 mass emissions from the
EAF (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Iron)n = Mass of direct reduced iron (if any)
charged to the furnace in month ‘‘n’’
(metric tons).
(CIron)n = Carbon content of the molten iron,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to
the furnace in month ‘‘n’’ (metric tons).
(CScrap)n = Average carbon content of the
ferrous scrap, from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(C
Frm 00221
Fmt 4701
Sfmt 4702
by weight, expressed as a decimal
fraction).
(Other)n = Mass of other materials charged to
the furnace in month ‘‘n’’ (metric tons).
(COther)n = Average carbon content of the
other materials charged to the furnace,
from the carbon analysis results for
month ‘‘n’’ (percent by weight, expressed
as a decimal fraction).
(Iron)n = Mass of iron produced in month ‘‘n’’
(metric tons).
(CIron)n = Carbon content of the iron, from the
carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(NM)n = Mass of non-metallic materials
produced by the furnace in month ‘‘n’’
(metric tons).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.077</MATH>
1
EP10AP09.076</MATH>
44
12
EP10AP09.075</MATH>
12
CO 2 = ∑
16667
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(CNM)n = Average carbon content of the nonmetallic materials, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
(3) Site-specific emission factor
method. You must conduct a
performance test and measure CO2
emissions from all exhaust stacks for the
process and measure either the feed rate
of materials into the process or the
production rate during the test as
described in paragraphs (a)(3)(i) through
(iv) of this section.
(i) You must measure the production
rate or feed rate, as applicable, during
CO 2 = 5.18 x 10−7 CCO 2
Where:
CO2 = CO2 mass emission rate (metric tons/
hr).
5.18 × 10 7 = Conversion factor (tons/scf% CO2).
CCO2 = Hourly CO2 concentration (% CO2).
Q = Hourly stack gas volumetric flow rate
(scfh).
%H2O = Hourly moisture percentage in the
stack gas.
(iii) You must calculate a site-specific
emission factor for the process in metric
tons of CO2 per metric ton of feed or
production, as applicable, by dividing
the average hourly CO2 emission rate
during the test by the average hourly
feed or production rate during the test.
(iv) You must calculate CO2 emissions
for the process by multiplying the
emission factor by the total amount of
feed or production, as applicable, for the
reporting period.
(b) You must determine emissions of
CO2 from the coke pushing process in
mtCO2e by multiplying the metric tons
of coal charged to the coke ovens during
the reporting period by 0.008.
§ 98.174 Monitoring and QA/QC
requirements.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with subpart C of
this part, you must meet the monitoring
and QA/QC requirements of § 98.34(e).
(b) If you determine CO2 emissions
using the carbon balance procedure in
§ 98.173(a)(2), you must:
(1) For each process input and output
other than fuels, determine the mass
rate of each process input and output
and record the totals for each process
input and output for each calendar
month. Determine the mass rate of fuels
using the procedures for combustion
units in § 98.34.
(2) For each process input and output
other than fuels, sample each process
input and output weekly and prepare a
monthly composite sample for carbon
analysis. For each process input that is
a fuel, determine the carbon content
using the procedures for combustion
units in § 98.34.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
⎛ 100 − % H 2 O ⎞
Q ⎜
⎟
100
⎝
⎠
(3) For each process input and output
other than fuels, the carbon content
must be analyzed by an independent
certified laboratory using test method
ASTM C25–06 (‘‘Standard Test Methods
for Chemical Analysis of Limestone,
Quicklime, and Hydrated Lime’’).
(3) For each process input and output
other than fuels, the carbon content
must be analyzed by an independent
certified laboratory using the test
methods specified in this paragraph.
(A) Use ASTM C25–06 (‘‘Standard
Test Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime’’) for:
(i) Limestone, dolomite, and slag;
ASTM D5373–08 (‘‘Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke’’)
for coal, coke, and other carbonaceous
materials; ASTM E1915–07a (‘‘Standard
Test Methods for Analysis of Metal
Bearing Ores and Related Materials by
Combustion Infrared-Absorption
Spectrometry’’) for iron ore, taconite
pellets, and other iron-bearing materials.
(ii) ASTM E1019–03 (‘‘Standard Test
Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel
and in Iron, Nickel, and Cobalt Alloys’’)
for iron and ferrous scrap.
(iii) ASTM E1019–03 (‘‘Standard Test
Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel
and in Iron, Nickel, and Cobalt Alloys’’),
ASTM CS–104 (‘‘Carbon Steel of
Medium Carbon Content’’), ISO/TR
15349–1:1998 (‘‘Unalloyed steel—
Determination of low carbon content.
Part 1’’), or ISO/TR 15349–3: 1998
(‘‘Unalloyed steel—Determination of
low carbon content. Part 3’’) as
applicable for steel.
(c) If you determine CO2 emissions
using the site-specific emission factor
procedure in § 98.173(a)(3), you must:
(1) Conduct an annual performance
test under normal process operating
conditions and at a production rate no
less than 90 percent of the process rated
capacity.
PO 00000
Frm 00222
Fmt 4701
Sfmt 4702
the test and calculate the average rate
for the test period in metric tons per
hour.
(ii) You must calculate the hourly CO2
emission rate using Equation Q–8 and
determine the average hourly CO2
emission rate for the test.
(Eq. Q-8)
(2) For the furnace exhaust from basic
oxygen furnaces, EAFs, argon-oxygen
decarburization vessels, and direct
reduction furnaces, sample the furnace
exhaust for at least nine complete
production cycles that start when the
furnace is being charged and end after
steel or iron and slag have been tapped.
For EAFs that produce both carbon steel
and stainless or specialty (low carbon)
steel, develop an emission factor for the
production of both types of steel.
(3) For taconite indurating furnaces,
non-recovery coke batteries, and sinter
processes, sample for at least 9 hours.
(4) Conduct the stack test using EPA
Method 3A in 40 CFR part 60, Appendix
A–2 to measure the CO2 concentration,
Method 2, 2A, 2C, 2D, or 2F in appendix
A–1 or Method 26, appendix A–2 of 40
CFR part 60 to determine the stack gas
volumetric flow rate, and Method 4 in
appendix A–3 of 40 CFR part 60 to
determine the moisture content of the
stack gas.
(5) Conduct a new performance test
and calculate a new site-specific
emission factor if your fuel type or fuel/
feedstock mix changes, the process
changes in a manner that affects energy
efficiency by more than 10 percent, or
the process feed materials change in a
manner that changes the carbon content
of the fuel or feed by more than 10
percent.
(6) The results of a performance test
must include the analysis of samples,
determination of emissions, and raw
data. The performance test report must
contain all information and data used to
derive the emission factor.
(d) For CH4, and N2O emissions, you
must meet the monitoring and QA/QC
requirements of § 98.34.
(e) For a coke pushing process,
determine the metric tons of coal
charged to the coke ovens and record
the totals for each pushing process for
each calendar month. Coal charged to
coke ovens can be measured using
weigh belts or a combination of
measuring volume and bulk density.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.078</MATH>
16668
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
There are no allowances for missing
data for facilities that estimate
emissions using the carbon balance
procedure in § 98.173(a)(2) or the siteemission factor procedure in
§ 98.133(a)(3); 100 percent data
availability is required.
§ 98.176
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information required
in paragraphs (a) through (g) of this
section for coke pushing and for each
taconite indurating furnace; basic
oxygen furnace; non-recovery coke oven
battery; sinter process; EAF; argonoxygen decarburization vessel; and
direct reduction furnace, as applicable:
(a) Annual CO2 emissions by calendar
quarters.
(b) Annual total for all process inputs
and outputs when the carbon balance is
used for specific processes by calendar
quarters (short tons).
(c) Annual production quantity (in
metric tons) for taconite pellets, coke,
sinter, iron, and raw steel by calendar
quarters.
(d) Production capacity (in tons per
year) for the production of taconite
pellets, coke, sinter, iron, and raw steel.
(e) Annual operating hours for
taconite furnaces, coke oven batteries,
sinter production, blast furnaces, direct
reduced iron furnaces, and electric arc
furnaces.
(f) Site-specific emission factor for all
process units for which the site-specific
emission factor approach is used.
(g) Facilities that use CEMS must also
comply with the data reporting
requirements specified in § 98.36(d)(iv).
§ 98.177
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (f) of
this section, as applicable.
(a) Annual CO2 emissions as
measured or determined for each
calendar quarter.
12
E CO2 = ∑
n =1
44
12
⎡( Lead )
n
⎣
VerDate Nov<24>2008
§ 98.178
15:41 Apr 09, 2009
Jkt 217001
§ 98.181
§ 98.182
§ 98.183
Definition of the source category.
The lead production source category
consists of primary lead smelters and
secondary lead smelters. A primary lead
smelter is a facility engaged in the
production of lead metal from lead
sulfide ore concentrates through the use
of pyrometallurgical techniques. A
secondary lead smelter is a facility at
which lead-bearing scrap materials
( C ) + ( Flux ) ( C ) + ( Carbon ) ( C
n
Flux n
n
(CLead)n = Carbon content of the lead ore, from
the carbon analysis results for month ‘‘n’’
(percent by weight, expressed as a
decimal fraction).
(Scrap)n = Mass of lead scrap charged to the
furnace in month ‘‘n’’ (metric tons).
(CScrap)n = Average carbon content of the lead
scrap, from the carbon analysis results
for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
PO 00000
Frm 00223
Fmt 4701
Sfmt 4702
Calculating GHG emissions.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must estimate total CO2 emissions
according to the requirements in
§ 98.33.
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must determine using the procedure
specified in paragraphs (b)(1) and (2) of
this section the total CO2 emissions
from the smelting furnaces at your
facility used for lead production.
(1) For each smelting furnace at your
facility used for lead production, you
must determine the mass of carbon in
each carbon-containing material, other
than fuel, that is fed, charged, or
otherwise introduced into the smelting
furnaces used at your facility for lead
production for each calendar month and
estimate total CO2 process emissions
from the affected units at your facility
using Equation R–1 of this section.
Carbon containing input materials
include carbonaceous reducing agents.
Definitions.
Scrap n
GHGs to report.
(a) You must report the CO2 process
emissions from each smelting furnace
used for lead production as required by
this subpart.
(b) You must report the CO2, CH4, and
N2O emissions from each stationary
combustion unit following the
requirements specified in subpart C of
this part.
Subpart R—Lead Production
§ 98.180
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a lead production process and
the facility meets the requirements of
either § 98.2(a)(1) or (2).
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
( CLead )n + ( Scrap )n
Where:
CO2 = Total annual CO2 process emissions
from the individual smelting furnace
(metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Lead)n = Mass of lead ore charged to the
smelting furnace in month ‘‘n’’ (metric
tons).
(including but not limited to, lead-acid
batteries) are recycled by smelting into
elemental lead or lead alloys.
(b) Monthly total for all process
inputs and outputs for each calendar
quarter when the carbon balance is used
for specific processes.
(c) Monthly analyses of carbon
content for each calendar quarter when
the carbon balance is used for specific
processes.
(d) Site-specific emission factor for all
process units for which the site-specific
emission factor approach is used.
(e) Annual production quantity for
taconite pellets, coke, sinter, iron, and
raw steel with records for each calendar
quarter.
(f) Facilities must keep records that
include a detailed explanation of how
company records or measurements are
used to determine all sources of carbon
input and output and the metric tons of
coal charged to the coke ovens (e.g.,
weigh belts, a combination of measuring
volume and bulk density). The owner or
operator also must document the
procedures used to ensure the accuracy
of the measurements of fuel usage
including, but not limited to, calibration
of weighing equipment, fuel flow
meters, coal usage including, but not
limited to, calibration of weighing
equipment and other measurement
devices. The estimated accuracy of
measurements made with these devices
must also be recorded, and the technical
basis for these estimates must be
provided.
) + ( Other )n ( COther )n ⎤
⎦
Carbon n
(Eq. R-1)
.
(Flux)n = Mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace in month ‘‘n’’ (metric tons).
(CFlux)n = Average carbon content of the flux
materials, from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials
(e.g., coal, coke) charged to the furnace
in month ‘‘n’’ (metric tons).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.079</MATH>
§ 98.175 Procedures for estimating
missing data.
16669
16670
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(2) You must determine the total CO2
emissions from the smelting furnaces
using Equation R–2 of this section.
k
CO 2 = ∑ E CO2k
(Eq. R-2)
1
Where:
CO2 = Total annual CO2 emissions, metric
tons/year.
ECO2k = Annual CO2 emissions from smelting
furnace k calculated using Equation R–
1 of this subpart, metric tons/year.
k = Total number of smelting furnaces at
facility used for the lead production.
§ 98.184 Monitoring and QA/QC
requirements.
If you determine CO2 emissions using
the carbon input procedure in
§ 98.183(b), you must meet the
requirements specified in paragraphs (a)
through (c) of this section.
(a) Determine the mass of each solid
carbon-containing input material by
direct measurement of the quantity of
the material placed in the unit or by
calculations using process operating
information, and record the total mass
for the material for each calendar
month.
(b) For each input material identified
in paragraph (a) of this section, you
must determine the average carbon
content of the material for each calendar
month using information provided by
your material supplier or by collecting
and analyzing a representative sample
of the material.
(c) For each input material identified
in paragraph (a) of this section for
which the carbon content is not
provided by your material supplier, the
carbon content of the material must be
analyzed by an independent certified
laboratory each calendar month using
the test methods and their QA/QC
procedures in § 98.7. Use ASTM E1941–
04 (‘‘Standard Test Method for
Determination of Carbon in Refractory
and Reactive Metals and Their Alloys’’)
for analysis of lead bearing ore, lead
scrap, and lead ingot; ASTM D5373–02
(‘‘Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Laboratory
Samples of Coal and Coke’’) for analysis
of carbonaceous reducing agents, and
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
ASTM C25–06 (‘‘Standard Test Methods
for Chemical Analysis of Limestone,
Quicklime, and Hydrated Lime’’) for
analysis of flux materials such as
limestone or dolomite.
§ 98.187
Records that must be retained.
For the carbon input procedure in
§ 98.183(b), a complete record of all
measured parameters used in the GHG
emissions calculations is required (e.g.,
raw materials carbon content values,
etc.). Therefore, whenever a qualityassured value of a required parameter is
unavailable, a substitute data value for
the missing parameter shall be used in
the calculations.
(a) For each missing value of the
carbon content the substitute data value
shall be the arithmetic average of the
quality-assured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
(b) For missing records of the mass of
carbon-containing input material
consumption, the substitute data value
shall be the best available estimate of
the mass of the input material. The
owner or operator shall document and
keep records of the procedures used for
all such estimates.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (d)
of this section.
(a) Monthly facility production
quantity for each lead product (in metric
tons).
(b) Number of facility operating hours
each month.
(c) If you use the carbon input
procedure, record for each carboncontaining input material consumed or
used (other than fuel), the information
specified in paragraphs (c)(1) and (2) of
this section.
(1) Monthly material quantity (in
metric tons).
(2) Monthly average carbon content
determined for material and records of
the supplier provided information or
analyses used for the determination.
(d) You must keep records that
include a detailed explanation of how
company records of measurements are
used to estimate the carbon input to
each smelting furnace. You also must
document the procedures used to ensure
the accuracy of the measurements of
materials fed, charged, or placed in an
affected unit including, but not limited
to, calibration of weighing equipment
and other measurement devices. The
estimated accuracy of measurements
made with these devices must also be
recorded, and the technical basis for
these estimates must be provided.
§ 98.186
§ 98.188
§ 98.185 Procedures for estimating
missing data.
Data Reporting Procedures.
In addition to the information
required by § 98.3(c) of this part, each
annual report must contain the
information specified in paragraphs (a)
through (e) of this section.
(a) Total annual CO2 emissions from
each smelting furnace operated at your
facility for lead production (metric tons
and the method used to estimate
emissions).
(b) Facility lead product production
capacity (metric tons).
(c) Annual facility production
quantity (metric tons).
(d) Number of facility operating hours
in calendar year.
(e) If you use the carbon input
procedure, report for each carboncontaining input material consumed or
used (other than fuel), the following
information:
(1) Annual material quantity (in
metric tons).
(2) Annual weighted average carbon
content determined for material and the
method used for the determination (e.g.,
supplier provided information, analyses
of representative samples you
collected).
PO 00000
Frm 00224
Fmt 4701
Sfmt 4702
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart S—Lime Manufacturing
§ 98.190
Definition of the source category.
Lime manufacturing processes use a
rotary lime kiln to produce a lime
product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide,
hydrated lime, dolomitic quicklime,
dolomitic hydrate, or other products)
from limestone or dolomite by means of
calcination. The lime manufacturing
source category consists of marketed
lime manufacturing facilities and nonmarketed lime manufacturing facilities.
§ 98.191
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a lime manufacturing process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.192
GHGs to report.
(a) You must report CO2 process
emissions from each lime kiln as
specified in this subpart.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.080</MATH>
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
(Other)n = Mass of any other materials
charged to the furnace in month ‘‘n’’
(metric tons).
(COther)n = Average carbon content of any
other materials from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
EFk = Emission factor for kiln k for lime type
i, metric tons CO2/metric ton lime.
SRCaO = Stoichiometric ratio of CO2 and CaO
for lime type i (see Table S–1 of this
subpart), metric tons CO2/ metric tons
CaO.
(SR
CaO , i
(M
d ,i
/ M lime,i ) × Cd,i × Fd,i
ϕ
12
ι =1
n
(4) You must determine the total CO2
process emissions for the facility using
Equation S–4 of this section:
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
2000
2205
z
CO 2 = ∑ E k
(Eq. S-4)
k =1
Where:
CO2 = Annual CO2 process emissions from
lime production (metric tons/year).
Ek = Annual CO2 emissions from lime
production at kiln k (metric tons/year).
z = Number of kilns for lime production.
§ 98.194 Monitoring and QA/QC
requirements.
(a) Determine the quantity of each
type of lime produced at each kiln and
the quantity of each type of calcined byproduct/waste produced for each lime
type, such as LKD, at the kiln on a
monthly basis. The quantity of each
type of calcined by-product/waste
produced at the kiln must include
material that is sold or used in a
product, inventoried, or disposed of.
The quantity of lime types and LKD
produced monthly by each kiln must be
determined by direct weight
measurement using the same plant
PO 00000
Frm 00225
Fmt 4701
Sfmt 4702
§ 98.194(b), metric tons MgO/ metric ton
lime.
(2) You must calculate the correction
factor for by-product/waste products at
the kiln (monthly) using Equation S–2
of this section:
(Eq. S-2)
Md,i = Weight of by-product/waste product
not recycled to the kiln from lime type
i, (tons of lime).
Mlime,i= Weight of lime produced at the kiln
from lime type i, (tons of lime).
Cd,i = Fraction of original carbonate in the
LKD for lime type i, (fraction).
E k ∑ = ∑ ( EK k , n M k,n CFlkd,k,n ) 0.97 )
Where:
Ek = Annual CO2 process emissions from
lime production at kiln k (metric tons/
year).
EFk,n = Emission factor for lime in calendar
month n(tons CO2/tons carbonate) from
Equation S–1.
Mk,n = Weight or mass of lime produced in
calendar month n (tons/calendar month)
from Equation S–3.
CFlkd,k,n = Correction factor for LKD for lime
in calendar month n from Equation S–2.
0.97 = Default correction factor for the
proportion of hydrated lime (Assuming
90 percent of hydrated lime produced is
high-calcium lime with a water content
of 28 percent).
2000/2205
= Conversion factor for tons to metric tons.
= Number of lime types produced at kiln
k.
(Eq. S-1)
SRMgO= Stoichiometric ratio of CO2 and MgO
for lime type i (See Table S–1 of this
subpart), metric tons CO2/ metric tons
MgO.
CaOi= Calcium oxide content for lime type i
determined according to § 98.194(b),
metric tons CaO/ton lime.
MgOi = Magnesium oxide content for lime
type i determined according to
CFlkd , k = 1 +
Where:
CFlkd,k = Correction factor for by-products/
waste products (such as lime kiln dust,
LKD) at kiln k.
× CaOi ) + ( SR MgO,i × MgOi )
Fd,i = Fraction of calcination of the original.
carbonate in the LKD of lime type i,
assumed to be 1.00 (fraction).
(3) You must calculate annual CO2
process emissions for each kiln using
Equation S–3 of this section:
(Eq. S-3)
instruments used for accounting
purposes, such as weigh hoppers or belt
weigh feeders.
(b) You must determine the chemical
composition (percent total CaO and
percent total MgO) of each type of lime
and each type of calcined by-product/
waste produced from each lime type by
an off-site laboratory analysis on a
monthly basis. This determination must
be performed according to the
requirements of ASTM C25–06,
‘‘Standard Test Methods for Chemical
Analysis of Limestone, Quicklime, and
Hydrated Lime’’ (incorporated by
reference—see § 98.7) and the
procedures in ‘‘CO2 Emissions
Calculation Protocol for the Lime
Industry English Units Version’’,
February 5, 2008 Revision (incorporated
by reference—see § 98.7).
(c) You must use the most recent
analysis of calcium oxide and
magnesium oxide content of each lime
product in monthly calculations.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.084</MATH>
EFk,i =
EP10AP09.083</MATH>
Calculating GHG emissions.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
products/wastes produced at each kiln
according to the procedures in
paragraphs (b)(1) through (4) of this
section.
(1) You must calculate a monthly
emission factor for each kiln for each
type of lime produced using Equation
S–1 of this section. Calcium oxide and
magnesium oxide content must be
analyzed monthly for each kiln:
EP10AP09.082</MATH>
§ 98.193
you must estimate total CO2 emissions
according to the requirements in
§ 98.33.
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you shall calculate CO2 process
emissions based on the production of
each type of lime and calcined by-
EP10AP09.081</MATH>
(b) You must report CO2, N2O, and
CH4 emissions from fuel combustion at
each lime kiln and any other stationary
combustion unit. You must follow the
requirements of subpart C of this part.
16671
16672
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(d) You must follow the quality
assurance/quality control procedures
(including documentation) in the
National Lime Association’s ‘‘CO2
Emissions Calculation Protocol for the
Lime Industry-English Units Version’’,
February 5, 2008 Revision (incorporated
by reference—see § 98.7).
(3) Annual lime production capacity
(in metric tons) per facility;
(4) All monthly emission factors, and;
(5) Number of operating hours in
calendar year.
(b) Facilities that use CEMS must also
comply with the data reporting
requirements specified in § 98.36.
§ 98.195 Procedures for estimating
missing data.
§ 98.197
For the procedure in § 98.193(b), a
complete record of all measured
parameters used in the GHG emissions
calculations is required (e.g., raw
materials carbon content values, etc.).
Therefore, whenever a quality-assured
value of a required parameter is
unavailable, a substitute data value for
the missing parameter shall be used in
the calculations.
(a) For each missing value of quantity
of lime types, CaO and MgO content,
and quantity of LKD the substitute data
value shall be the arithmetic average of
the quality-assured values of that
parameter immediately preceding and
immediately following the missing data
incident. 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.
(b) For missing records of mass of raw
material consumption, the substitute
data value shall be the best available
estimate of the mass of inputs. The
owner or operator shall document and
keep records of the procedures used for
all such estimates.
§ 98.196
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a)(1) through (5) of this
section for each lime kiln:
(1) Annual CO2 process emissions;
(2) Annual lime production (in metric
tons);
(a) Any site where magnesium metal
is produced through smelting (including
electrolytic smelting), refining, or
remelting operations.
(b) Any site where molten magnesium
is used in alloying, casting, drawing,
extruding, forming, or rolling
operations.
Records that must be retained.
(a) In addition to the records required
by § 98.3(g), you must retain the
following records specified in
paragraphs (a)(1) through (4) of this
section for each lime kiln:
(1) Annual calcined by-products/
waste products (by lime type summed
from monthly data.
(2) Lime production (by lime type) per
month (metric tons).
(3) Calculation of emission factors.
(4) Results of chemical composition
analysis (by lime product) per month.
(5) Monthly correction factors for byproducts/waste products for each kiln.
(b) Facilities that use CEMS must also
comply with the recordkeeping
requirements specified in § 98.37.
§ 98.201
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a magnesium production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.202
GHGs to report.
(a) You must report emissions of the
following gases in kilograms and metric
tons CO2e per year resulting from their
use as cover gases or carrier gases in
magnesium production or processing:
(1) Sulfur hexafluoride (SF6).
(2) HFC–134a.
(3) The fluorinated ketone, FK 5–1–
12.
§ 98.198 Definitions.
(4) Any other fluorinated GHGs.
All terms used in this subpart have
(5) Carbon dioxide (CO2).
the same meaning given in the Clean Air
Act and subpart A of this part.
(b) You must report CO2, N2O, and
CH4 emissions from each combustion
TABLE S–1 OF SUBPART S—BASIC unit on site by following the calculation
PARAMETERS FOR THE CALCULATION procedures, monitoring and QA/QC
OF EMISSION FACTORS FOR LIME methods, missing data procedures,
PRODUCTION
reporting requirements, and
recordkeeping requirements of subpart
Stoichiometric
C of this part.
Variable
ratio
SRCaO ................................
SRMgO ...............................
0.7848
1.0918
Subpart T—Magnesium Production
§ 98.200
Definition of source category.
The magnesium production and
processing source category consists of
the following facilities:
E GHG = ESF6 + E134 a + E FK + E CO 2 + E OG
§ 98.203
Calculating GHG emissions.
(a) Calculate CO2e GHG emissions
from magnesium production or
processing using Equation T–1 of this
section. For Equation T–1 of this
section, use the procedures of either
paragraph (b) or (c) of this section to
estimate consumption of cover gas or
carrier gas.
(Eq. T-1)
ESF6 = CSF6 × 23.9
E134 a = C134 a × 1.3
E FK = CFK × 0.001
E CO2 = CCO 2 × 0.001
E OG = COG × GWPOG /1000
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
ESF6 = SF6 emissions from magnesium
production and processing (mtCO2e).
PO 00000
Frm 00226
Fmt 4701
Sfmt 4702
E134a = HFC–134a emissions from magnesium
production and processing (mtCO2e).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.186</MATH>
Where:
EGHG = GHG emissions from magnesium
production and processing (mtCO2e).
16673
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
C = Consumption of any cover gas or carrier
gas in kg over the period (e.g., 1 year).
IB = Inventory of any cover gas or carrier gas
stored in cylinders or other containers at
the beginning of the period (e.g., 1 year),
including heels, in kg.
IE = Inventory of any cover gas or carrier gas
stored in cylinders or other containers at
the end of the period (e.g., 1 year),
including heels, in kg.
A = Acquisitions of any cover gas or carrier
gas during the period (e.g., 1 year)
through purchases or other transactions,
including heels in cylinders or other
containers returned to the magnesium
production or processing facility, in kg.
D = Disbursements of cover gas or carrier gas
to sources and locations outside the
facility through sales or other
transactions during the period, including
heels in cylinders or other containers
returned by the magnesium production
or processing facility to the gas
distributor, in kg.
(c) To estimate consumption of cover
gases or carrier gases by monitoring
changes in the masses of individual
containers as their contents are used,
consumption of each cover gas or carrier
gas shall be estimated using Equation T–
3 of this section:
n
CGHG = ∑ Q p
(Eq. T-3)
p =1
Where:
CGHG = The consumption of the cover gas
over the period (kg).
Qp = The mass of the cover gas used over the
period (kg).
n = The number of periods in the year.
(d) For purposes of Equation T–3 of
this section, the mass of the cover gas
used over the period p shall be
estimated by using Equation T–4 of this
section:
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
§ 98.204 Monitoring and QA/QC
requirements.
(a) Consumption of cover gases and
carrier gases may be estimated by
monitoring the changes in container
weights and inventories using Equation
T–2 of this subpart, by monitoring the
changes in individual container weights
as the contents of each container are
used using Equations T–3 and T–4 of
this subpart, or by monitoring the mass
flow of the pure cover gas or carrier gas
into the cover gas distribution system.
Consumption must be estimated at least
annually.
(b) When estimating consumption by
monitoring the mass flow of the pure
cover gas or carrier gas into the cover
gas distribution system, you must use
gas flow meters with an accuracy of one
percent of full scale or better.
(c) When estimating consumption
using Equation T–2 of this subpart, you
must ensure that all the quantities
required by Equation T–2 of this subpart
have been measured using scales or load
cells with an accuracy of one percent of
full scale or better, accounting for the
tare weights of the containers. You may
accept gas masses or weights provided
by the gas supplier (e.g., for the contents
of containers containing new gas or for
the heels remaining in containers
returned to the gas supplier); however,
you remain responsible for the accuracy
of these masses and weights under this
subpart.
(d) When estimating consumption
using Equations T–3 and T–4 of this
subpart, you must monitor and record
container identities and masses as
follows:
(1) Track the identities and masses of
containers leaving and entering storage
with check-out and check-in sheets and
procedures. The masses of cylinders
returning to storage shall be measured
immediately before the cylinders are put
back into storage.
(2) Ensure that all the quantities
required by Equations T–3 and T–4 of
this subpart have been measured using
scales or load cells with an accuracy of
one percent of full scale or better,
accounting for the tare weights of the
containers. You may accept gas masses
or weights provided by the gas supplier
(e.g., for the contents of cylinders
containing new gas or for the heels
remaining in cylinders returned to the
PO 00000
Frm 00227
Fmt 4701
Sfmt 4702
§ 98.205 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emission
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable, a
substitute data value for the missing
parameter will be used in the
calculations as specified in paragraph
(b) of this section.
(b) Replace missing data on the
consumption of cover gases by
multiplying magnesium production
during the missing data period by the
average cover gas usage rate from the
most recent period when operating
conditions were similar to those for the
period for which the data are missing.
Calculate the usage rate for each cover
gas using Equation T–5 of this section:
R GHG = CGHG / Mg
(Eq. T-5)
Where:
RGHG = The usage rate for a particular cover
gas over the period.
CGHG = The consumption of that cover gas
over the period (kg).
Mg = The magnesium produced or fed into
the casting process over the period
(metric tons).
§ 98.206
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must include the following information
for the magnesium production and
processing facility:
(a) Total GHG emissions for your
facility by gas in metric tons and CO2e.
(b) Type of production process (e.g.
primary, secondary, die casting).
(c) Magnesium production amount in
metric tons for each process type.
(d) Cover gas flow rate and
composition.
(e) Amount of CO2 used as a carrier
gas during the reporting period.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.088</MATH>
(Eq. T-2)
Where:
Qp = The mass of the cover gas used over the
period (kg).
MB = The mass of the contents of the cylinder
at the beginning of period p.
ME = The mass of the contents of the cylinder
at the end of period p.
gas supplier); however, you remain
responsible for the accuracy of these
masses or weights under this subpart.
(e) All flowmeters, scales, and load
cells used to measure quantities that are
to be reported under this subpart shall
be calibrated using suitable NISTtraceable standards and suitable
methods published by a consensus
standards organization (e.g., ASTM,
ASME, ASHRAE, or others).
Alternatively, calibration procedures
specified by the flowmeter, scale, or
load cell manufacturer may be used.
Calibration shall be performed prior to
the first reporting year. After the initial
calibration, recalibration shall be
performed at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
EP10AP09.087</MATH>
C = IB − IE + A − D
(Eq. T-4)
EP10AP09.086</MATH>
(b) To estimate consumption of cover
gases or carrier gases by monitoring
changes in container masses and
inventories, consumption of each cover
gas or carrier gas shall be estimated
using Equation T–2 of this section:
Qp = M B − M E
EP10AP09.085</MATH>
EFK = FK 5–1–12 emissions from magnesium
production and processing (mtCO2e).
ECO2 = CO2 emissions from magnesium
production and processing (mtCO2e).
EOG = Emissions of other fluorinated GHGs
from magnesium production and
processing (mtCO2e).
CSF6 = Consumption of SF6 (kg).
C134a = Consumption of HFC–134a (kg).
CFK = Consumption of FK 5–1–12 (kg).
CCO2 = Consumption of CO2 (kg).
COG = Consumption of other fluorinated
GHGs (kg).
GWPOG = The Global Warming Potential of
the other fluorinated GHG provided in
Table A–1 in subpart A of this part.
16674
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.207
(a) Check-out and weigh-in sheets and
procedures for cylinders.
(b) Accuracy certifications and
calibration records for scales.
(c) Residual gas amounts in cylinders
sent back to suppliers.
(d) Invoices for gas purchases and
sales.
§ 98.208
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart U—Miscellaneous Uses of
Carbonate
§ 98.210
Records that must be retained.
In addition to the records specified in
§ 98.3(g), you must retain the following
information for the magnesium
production or processing facility:
Definitions.
Definition of the source category.
(a) This source category consists of
any equipment that uses limestone,
dolomite, ankerite, magnesite, silerite,
rhodochrosite, sodium carbonate, or any
i
E CO2 = ∑ M i
EFi
Fi
1
Where:
ECO2 = Annual CO2 mass emissions from
consumption of carbonates (metric tons).
Mi = Annual Mass of carbonate type i
consumed (tons).
EFi = Emission factor for the carbonate type
i, as specified in Table U–1 to this
subpart, metric tons CO2/metric ton
carbonate consumed.
Fi = Fraction calcination achieved for each
particular carbonate type i.
i = number of the carbonate types.
2000/2205 = Conversion factor to convert
tons to metric tons.
As an alternative to measuring the
calcination fraction (Fi), a value of 1.0
can be used in Equation U–1 of this
section.
§ 98.214 Monitoring and QA/QC
requirements.
(a) The total mass of carbonate
consumed can be determined by direct
weight measurement using the same
plant instruments used for accounting
purposes, such as weigh hoppers or belt
weigh feeders, or purchase records.
(b) Determine on an annual basis the
calcination fraction for each carbonate
consumed based on sampling and
chemical analysis conducted by a
certified laboratory using a suitable
method such as using an x-ray
fluorescence test or other enhanced
testing method published by a
consensus standards organization (e.g.,
ASTM, ASME, API, etc.).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
2000
2205
There are no missing data procedures
for miscellaneous uses of carbonates. A
complete record of all measured
parameters used in the GHG emissions
calculations is required. A re-test must
be performed if the data from any
measurements are determined to be
invalid.
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (d) of this
section at the facility level.
(a) Annual CO2 emissions from
miscellaneous carbonate use (in metric
tons).
(b) Annual carbonate consumption
(by carbonate type in tons).
(c) Annual fraction calcinations.
(d) Average annual mass fraction of
carbonate-based mineral in carbonatebased raw material by carbonate type.
§ 98.217
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (c) of
this section.
(a) Records of monthly carbonate
consumption (by carbonate type). You
must also document the procedures
used to ensure the accuracy of monthly
carbonate consumption.
(b) Annual chemical analysis of mass
fraction of carbonate-based mineral in
PO 00000
Frm 00228
Fmt 4701
Sfmt 4702
§ 98.211
Reporting threshold.
You must report GHG emissions from
miscellaneous uses of carbonate if your
facility meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.212
GHGs to report.
You must report CO2 emissions
aggregated for all miscellaneous
carbonate use at the facility.
§ 98.213
Calculating GHG emissions.
Calculate process emissions of CO2
using Equation U–1 of this section.
(Eq. U-1)
§ 98.215 Procedures for estimating
missing data.
§ 98.216
other carbonate in a manufacturing
process.
(b) This source category does not
include carbonates consumed for
producing cement, glass, ferroalloys,
iron and steel, lead, lime, pulp and
paper, or zinc.
carbonate-based raw material by
carbonate type.
(c) Records of all carbonate purchases
and deliveries.
§ 98.218
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE U–1 OF SUBPART U—CO2
EMISSION FACTORS FOR COMMON
CARBONATES
Mineral name—carbonate
CO2 emission
factor
(tons CO2/ton
carbonate)
Limestone—CaCO3 ..........
Magnesite—MgCO3 ..........
Dolomite—CaMg(CO3)2 ....
Siderite—FeCO3 ...............
Ankerite—Ca(Fe,Mg,Mn)
(CO3)2 ............................
Rhodochrosite—MnCO3 ...
Sodium Carbonate/Soda
Ash—Na2CO3 ................
0.43971
0.52197
0.47732
0.37987
0.44197
0.38286
0.41492
Subpart V—Nitric Acid Production
§ 98.220
Definition of source category.
A nitric acid production facility uses
oxidation, condensation, and absorption
to produce a weak nitric acid (30 to 70
percent in strength).
§ 98.221
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a nitric acid production
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.089</MATH>
(f) For any missing data, you must
report the length of time the data were
missing, the method used to estimate
emissions in their absence, and the
quantity of emissions thereby estimated.
(g) The facility’s cover gas usage rate.
(h) If applicable, an explanation of
any change greater than 30 percent in
the facility’s cover gas usage rate (e.g.,
installation of new melt protection
technology or leak discovered in the
cover gas delivery system that resulted
in increased consumption).
(i) A description of any new melt
protection technologies adopted to
account for reduced GHG emissions in
any given year.
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
GHGs to report.
(a) You must report N2O process
emissions from each nitric acid
production line as required by this
subpart.
(b) You must report CO2, CH4, and
N2O emissions from each stationary
combustion unit. You must follow the
requirements of subpart C of this part.
n
EFN2O =
Where:
EFN2O = Site-specific N2O emissions factor (lb
N2O/ton nitric acid produced, 100
percent acid basis).
CN2O = N2O concentration during
performance test (ppm N2O).
§ 98.224 Monitoring and QA/QC
requirements.
(a) You must conduct a new
performance test and calculate a new
site-specific emissions factor at least
annually. You must also conduct a new
performance test whenever the
production rate of a production line is
changed by more than 10 percent from
the production rate measured during the
most recent performance test. The new
emissions factor may be calculated
using all available performance test data
(i.e., averaged with the data from
previous years), except in cases where
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
∑
P
1
(Eq. V-1)
n
EFN 2 O ∗ Pa ∗ (1 − DFN ) ∗ AFN
2205
§ 98.225 Procedures for estimating
missing data.
Procedures for estimating missing
data are not provided for N2O process
Frm 00229
Fmt 4701
Sfmt 4702
(e) You must calculate N2O emissions
for each nitric acid production line by
multiplying the emissions factor by the
total annual production from that
production line, according to Equation
V–2 of this section:
(Eq. V-2)
process modifications have occurred or
operating conditions have changed.
Only the data consistent with the period
after the changes were implemented
shall be used.
(b) Each facility must conduct the
performance test(s) according to a test
plan and EPA Method 320 in 40 CFR
part 63, Appendix A or ASTM D6348–
03 (incorporated by reference—see
§ 98.7). All QA/QC procedures specified
in the reference test methods and any
associated performance specifications
apply. The report must include the
items in paragraphs (b)(1) through (3) of
this section.
(1) Analysis of samples,
determination of emissions, and raw
data.
(2) All information and data used to
derive the emissions factor(s).
(3) The production rate during each
test and how it was determined. The
production rate can be determined
through sales records or by direct
measurement using flow meters or
weigh scales.
PO 00000
40 CFR part 63, appendix A or ASTM
D6348–03 incorporated by reference in
§ 98.7 to measure the N2O concentration
in conjunction with the applicable EPA
Methods in 40 CFR part 60, Appendices
A–1 through A–4. Conduct three
emissions test runs of 1 hour each.
(c) You must measure the production
rate during the test(s) and calculate the
production rate for the test period in
tons (100 percent acid basis) per hour.
(d) You must calculate a site-specific
emission factor for each nitric acid
production line according to Equation
V–1 of this section:
CN2O = ∗1.14 × 10−7 ∗ Q
1.14×10¥7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas
(dscf/hr).
P = Production rate during performance test
(tons nitric acid produced per hour (100
percent acid basis)).
n = Number of test runs.
EN2O =
Where:
EN2O = N2O mass emissions per year (metric
tons of N2O).
EFN2O = Site-specific N2O emission factor for
the production line (lb N2O/ton acid
produced, 100 percent acid basis).
Pa = Total production for the year from the
production line (ton acid produced, 100
percent acid basis).
DFN = Destruction factor of N2O abatement
technology, ’as specified by the
abatement device manufacturer (percent
of N2O removed from air stream).
AFN = Abatement factor of N2O abatement
technology (percent of year that
abatement technology was used).
2205 = Conversion factor (lb/metric ton).
Calculating GHG emissions.
You must determine annual N2O
process emissions from each nitric acid
production line using a site-specific
emission factor according to paragraphs
(a) through (e) of this section.
(a) You must conduct an annual
performance test to measure N2O
emissions from the absorber tail gas vent
for each nitric acid production line. You
must conduct the performance test(s)
under normal process operating
conditions.
(b) You must conduct the emissions
test(s) using either EPA Method 320 in
emissions from nitric acid production
lines. A complete record of all measured
parameters used in the GHG emissions
calculations is required.
§ 98.226
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (h) of this
section for each nitric acid production
line:
(a) Annual nitric acid production
capacity (metric tons).
(b) Annual nitric acid production
(metric tons).
(c) Number of operating hours in the
calendar year (hours).
(d) Emission factor(s) used (lb N2O/
ton of nitric acid produced).
(e) Type of nitric acid process used.
(f) Abatement technology used (if
applicable).
(g) Abatement utilization factor
(percent of time that abatement system
is operating).
(h) Abatement technology efficiency.
§ 98.227
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the records specified in paragraphs (a)
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.091</MATH>
§ 98.222
§ 98.223
EP10AP09.090</MATH>
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
16675
16676
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.228
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart W—Oil and Natural Gas
Systems
§ 98.230
Definition of the source category.
This source category consists of the
following facilities:
(a) Offshore petroleum and natural gas
production facilities.
(b) Onshore natural gas processing
facilities.
(c) Onshore natural gas transmission
compression facilities.
(d) Underground natural gas storage
facilities.
(e) Liquefied natural gas storage
facilities.
(f) Liquefied natural gas import and
export facilities.
§ 98.231
Reporting threshold.
You must report GHG emissions from
oil and natural gas systems if your
facility meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.232
GHGs to report.
(a) You must report CO2 and CH4
emissions in metric tons per year from
sources specified in § 98.232(a)(1)
through (23) at offshore petroleum and
natural gas production facilities,
onshore natural gas processing facilities,
onshore natural gas transmission
compression facilities, underground
natural gas storage facilities, liquefied
natural gas storage facilities and
liquefied natural gas import and export
facilities.
(1) Acid gas removal (AGR) vent
stacks.
(2) Blowdown vent stacks.
(3) Centrifugal compressor dry seals.
(4) Centrifugal compressor wet seals.
(5) Compressor fugitive emissions.
(6) Compressor wet seal degassing
vents.
(7) Dehydrator vent stacks.
(8) Flare stacks.
(9) Liquefied natural gas import and
export facilities fugitive emissions.
(10) Liquefied natural gas storage
facilities fugitive emissions.
(11) Natural gas driven pneumatic
pumps.
(12) Natural gas driven pneumatic
manual valve actuator devices.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(13) Natural gas driven pneumatic
valve bleed devices.
(14) Non-pneumatic pumps.
(15) Offshore platform pipeline
fugitive emissions.
(16) Open-ended lines (oels).
(17) Pump seals.
(18) Platform fugitive emissions.
(19) Processing facility fugitive
emissions.
(20) Reciprocating compressor rod
packing.
(21) Storage station fugitive
emissions.
(22) Storage tanks.
(23) Storage wellhead fugitive
emissions.
(24) Transmission station fugitive
emissions.
(b) You must report the CO2, CH4, and
N2O emissions for stationary
combustion sources, by following the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
C of this part.
§ 98.233
Calculating GHG emissions.
(a) Estimate emissions using either an
annual direct measurement, as specified
in § 98.234, or an engineering estimation
method specified in this section. You
may use the engineering estimation
method only for sources for which a
method is specified in this section.
(b) You may use engineering
estimation methods described in this
section to calculate emissions from the
following fugitive emissions sources:
(1) Acid gas removal vent stacks.
(2) Natural gas driven pneumatic
pumps.
(3) Natural gas driven pneumatic
manual valve actuator devices.
(4) Natural gas driven pneumatic
valve bleed devices.
(5) Blowdown vent stacks.
(6) Dehydrator vent stacks.
(c) A combination of engineering
estimation described in this section and
direct measurement described in
§ 98.234 shall be used to calculate
emissions from the following fugitive
emissions sources:
(1) Flare stacks.
(2) Storage tanks.
(3) Compressor wet seal degassing
vents.
(d) You must use the methods
described in § 98.234 (d) or (e) to
conduct annual leak detection of
fugitive emissions from all sources
listed in § 98.232(a). If fugitive
emissions are detected, engineering
estimation methods may be used for
sources listed in paragraphs (b) and (c)
of this section. If engineering estimation
is used, emissions must be calculated
PO 00000
Frm 00230
Fmt 4701
Sfmt 4702
using the appropriate method from
paragraphs (d)(1) through (9) of this
section:
(1) Acid gas removal vent stack.
Calculate acid gas removal vent stack
fugitive emissions using simulation
software packages, such as ASPENTM or
AMINECalcTM. Any standard simulation
software may be used provided it
accounts for the following parameters:
(i) Natural gas feed temperature,
pressure, and flow rate.
(ii) Acid gas content of feed natural
gas.
(iii) Acid gas content of outlet natural
gas.
(iv) Unit operating hours, excluding
downtime for maintenance or standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature,
circulation rate and weight.
(vii) If the acid gas removal unit is
capturing CO2 and transferring it off
site, then refer to subpart OO of this part
for calculating transferred CO2.
(2) Natural gas driven pneumatic
pump. Calculate fugitive emissions from
a natural gas driven pneumatic pump as
follows:
(i) Calculate fugitive emissions using
manufacturer data.
(A) Obtain from the manufacturer
specific pump model natural gas
emission per unit volume of liquid
pumped at operating pressures.
(B) Maintain a log of the amount of
liquid pumped annually from
individual pumps.
(C) Calculate the natural gas fugitive
emissions for each pump using Equation
W–1 of this section.
Es,n = Fs ∗ V
(Eq. W-1)
Where:
Es,n = Natural gas fugitive emissions at
standard conditions.
Fs = Natural gas driven pneumatic pump gas
emission in ‘‘emission per volume of
liquid pumped at discharge pressure’’
units at standard conditions, as provided
by the manufacturer.
V = Volume of liquid pumped annually.
(D) Both CH4 and CO2 volumetric and
mass fugitive emissions shall be
calculated from volumetric natural gas
fugitive emissions using calculations in
paragraphs (f) and (g) of this section.
(ii) If manufacturer data for Fs are not
available, follow the method in § 98.234
(i)(1).
(3) Natural gas driven pneumatic
manual valve actuator devices.
Calculate fugitive emissions from a
natural gas driven pneumatic manual
valve actuator device as follows:
(i) Calculate fugitive emissions using
manufacturer data.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.092</MATH>
through (c) of this section for each nitric
acid production line:
(a) Records of significant changes to
process.
(b) Annual test reports of N2O
emissions.
(c) Calculations of the site-specific
emissions factor(s).
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Ea,n = N ∗ Vv
(Eq. W-4)
Where:
Ea,n = Natural gas fugitive emissions at
ambient conditions from blowdowns.
N = Number of blowdowns for the equipment
in reporting year.
Vv = Total volume of blowdown equipment
chambers (including, but not limited to,
pipelines and vessels) between isolation
valves.
(iv) Calculate natural gas volumetric
fugitive emissions at standard
conditions using calculations in
paragraph (e) of this section.
(v) Calculate both CH4 and CO2
volumetric and mass fugitive emissions
Ea,i = Va × (1 − η ) × X i + (1 − K ) ∗η ∗ Va ∗ Y j ∗ R j,i
Where:
Ea,i = Annual fugitive emissions from flare
stack.
Va = Volume of natural gas sent to flare stack
determined from § 98.234(j)(1).
h = Percent of natural gas combusted by flare
(default is 95 percent for non-steam
aspirated flares and 98 percent for steam
aspirated or air injected flares).
Xi = Concentration of GHG i in the flare gas
determined from § 98.234(j)(1).
Yj = Concentration of natural gas
hydrocarbon constituents j (such as
methane, ethane, propane, butane, and
pentanes plus).
Rj,i = Number of carbon atoms in the natural
gas hydrocarbon constituent j; 1 for
methane, 2 for ethane, 3 for propane, 4
for butane, and 5 for pentanes plus).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
K = ‘‘1’’ when GHG i is CH4 and ‘‘0’’ when
GHG i is CO2.
(iv) Calculate GHG volumetric fugitive
emissions at standard conditions using
Equation W–6 of this section.
Es,i =
Ea,i ∗ ( 460 + Ts ) ∗ Pa
( 460 + Ta ) ∗ Ps
(Eq. W-6)
Where:
Es,i = Natural gas volumetric fugitive
emissions at standard temperature and
pressure (STP) conditions.
Ea,i = Natural gas volumetric fugitive
emissions at actual conditions.
Ts = Temperature at standard conditions (°F).
PO 00000
Frm 00231
Fmt 4701
Sfmt 4702
(Eq. W-5)
Ta = Temperature at actual emission
conditions (°F).
Ps = Absolute pressure at standard conditions
(inches of Hg).
Pa = Absolute pressure at ambient conditions
(inches of Hg).
(v) Calculate both CH4 and CO2 mass
fugitive emissions from volumetric CH4
and CO2 fugitive emissions using
calculations in paragraph (g) of this
section.
(8) Storage tanks. Calculate fugitive
emissions from a storage tank as
follows:
(i) Calculate the total annual
hydrocarbon vapor fugitive emissions
using Equation W–7 of this section:
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.097</MATH>
(D) Calculate both CH4 and CO2
volumetric and mass fugitive emissions
from volumetric natural gas fugitive
emissions using calculations in
paragraphs (f) and (g) of this section.
(ii) Follow the method in
§ 98.234(i)(2) if manufacturer data are
not available.
(4) Natural gas driven pneumatic
valve bleed devices. Calculate fugitive
emissions from a natural gas driven
pneumatic valve bleed device as
follows:
(i) Calculate fugitive emissions using
manufacturer data.
(A) Obtain from the manufacturer
specific pneumatic device model
natural gas bleed rate during normal
operation.
(B) Calculate the natural gas fugitive
emissions for each valve bleed device
using Equation W–3 of this section.
(C) Calculate both CH4 and CO2 volumetric
and mass fugitive emissions from volumetric
natural gas fugitive emissions using
calculations in paragraphs (f) and (g) of this
section.
(ii) Follow the method in § 98.234(i)(3) if
manufacturer data are not available.
(5) Blowdown vent stacks. Calculate
fugitive emissions from blowdown vent
stacks as follows:
(i) Calculate the total volume (including,
but not limited to pipelines and vessels)
between isolation valves (Vv in Equation W–
4 of this subpart).
(ii) Retain logs of the number of
blowdowns for each equipment type.
(iii) Calculate the total annual fugitive
emissions using the following Equation W–
4 of this section:
EP10AP09.096</MATH>
Where:
Es,n = Natural gas fugitive emissions at
standard conditions.
As = Natural gas driven pneumatic valve
actuator natural gas emission in
‘‘emission per actuation’’ units at
standard conditions, as provided by the
manufacturer.
N = Number of times the pneumatic device
was actuated in a way that vented
natural gas to the atmosphere through
the reporting period.
Where:
Es,n = Natural gas fugitive emissions at
standard conditions.
Bs = Natural gas driven pneumatic device
bleed rate in ‘‘emission per unit time’’
units at standard conditions, as provided
by the manufacturer.
T = Amount of time the pneumatic device
has been operational through the
reporting period.
from volumetric natural gas fugitive
emissions using calculations in
paragraphs (f) and (g) of this section.
(6) Dehydrator vent stacks. Calculate
fugitive emissions from a dehydrator
vent stack using a simulation software
packages, such as GLYCalcTM. Any
standard simulation software may be
used provided it accounts for the
following parameters:
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type
(natural gas pneumatic/air pneumatic/
electric).
(v) Absorbent circulation rate.
(vi) Absorbent type: Including, but not
limited to, triethylene glycol (TEG),
diethylene glycol (DEG) or ethylene
glycol (EG).
(vii) Use of stripping natural gas.
(viii) Use of flash tank separator (and
disposition of recovered gas).
(ix) Hours operated.
(x) Wet natural gas temperature,
pressure, and composition.
(7) Flare stacks. Calculate fugitive
emissions from a flare stack as follows:
(i) Determine flare combustion
efficiency from manufacturer. If not
available, assume that flare combustion
efficiency is 95 percent for non-steam
aspirated flares and 98 percent for steam
aspirated or air injected flares.
(ii) Calculate volume of natural gas
sent to flare from velocity measurement
in § 98.234(j) using manufacturer’s
manual for the specific meter used to
measure velocity.
(iii) Calculate GHG volumetric
fugitive emissions at actual conditions
using Equation W–5 of this section:
EP10AP09.095</MATH>
(Eq. W-2)
(Eq. W-3)
EP10AP09.094</MATH>
Es,n = As ∗ N
Es,n = Bs ∗ T
EP10AP09.093</MATH>
(A) Obtain from the manufacturer
specific pneumatic device model
natural gas emission per actuation.
(B) Maintain a log of the number of
times the pneumatic device was
actuated throughout the reporting
period.
(C) Calculate the natural gas fugitive
emissions for each manual valve
actuator using Equation W–2 of this
section.
16677
16678
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(Eq. W-8)
Where:
Es,i = GHG i (either CH4 or CO2) volumetric
fugitive emissions at standard
conditions.
Es,h = Hydrocarbon vapor volumetric fugitive
emissions at standard conditions.
Mi = Mole percent of a particular GHG i in
the hydrocarbon vapors; hydrocarbon
vapor analysis shall be conducted in
accordance with ASTM D1945–03.
(iv) Estimate CH4 and CO2 mass
fugitive emissions from GHG volumetric
fugitive emissions using calculations in
paragraph (g) of this section.
(9) Compressor wet seal degassing
vents. Calculate fugitive emissions from
compressor wet seal degassing vents as
follows:
(i) Calculate volume of natural gas
sent to vent from velocity measurement
in § 98.234(j) using manufacturer’s
manual for the specific meter used to
measure velocity.
(ii) Calculate natural gas volumetric
fugitive emissions at standard
conditions using calculations in
paragraph (e) of this section.
(iii) Calculate both CH4 and CO2
volumetric and mass fugitive emissions
from volumetric natural gas fugitive
emissions using calculations in
paragraphs (f) and (g) of this section.
(e) Calculate natural gas volumetric
fugitive emissions at standard
conditions by converting ambient
temperature and pressure of natural gas
fugitive emissions to standard
temperature and pressure natural using
Equation W–9 of this section.
Es,n =
Ea,n ∗ ( 460 + Ts ) ∗ Pa
( 460 + Ta ) ∗ Ps
(Eq. W-9)
Where:
Es,n = Natural gas volumetric fugitive
emissions at standard temperature and
pressure (STP) conditions.
Ea,n = Natural gas volumetric fugitive
emissions at actual conditions.
Ts = Temperature at standard conditions (°F).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. W-10)
(2) For Equation W–10 of this section,
the mole percent, Mi, shall be the
annual average mole percent for each
facility, as specified in paragraphs
(f)(2)(i) through (vi) of this section.
(i) GHG mole percent in produced
natural gas for offshore petroleum and
natural gas production facilities.
(ii) GHG mole percent in feed natural
gas for all fugitive emissions sources
upstream of the de-methanizer and GHG
mole percent in facility specific residue
gas to transmission pipeline systems for
all fugitive emissions sources
downstream of the de-methanizer for
onshore natural gas processing facilities.
(iii) GHG mole percent in
transmission pipeline natural gas that
passes through the facility for onshore
natural gas transmission compression
facilities.
(iv) GHG mole percent in natural gas
stored in underground natural gas
storage facilities.
(v) GHG mole percent in natural gas
stored in LNG storage facilities.
(vi) GHG mole percent in natural gas
stored in LNG import and export
facilities.
(g) Calculate GHG mass fugitive
emissions at standard conditions by
converting the GHG volumetric fugitive
emissions into mass fugitive emissions
using Equation W–11 of this section.
Masss,i = Es,i ∗ ρ i
(Eq. W-11)
Where:
Masss,i = GHG i (either CH4 or CO2) mass
fugitive emissions at standard
conditions.
Es,i = GHG i (either CH4 or CO2) volumetric
fugitive emissions at standard
conditions.
ri = Density of GHG i;1.87 kg/m3 for CO2 and
0.68 kg/m3 for CH4.
PO 00000
Frm 00232
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.102</MATH>
Es,i = Es,h ∗ M i
Es,i = Es,n ∗ M i
Where:
Es,i = GHG i (either CH4 or CO2) volumetric
fugitive emissions at standard
conditions.
Es,n = Natural gas volumetric fugitive
emissions at standard conditions.
Mi = Mole percent of GHG i in the natural
gas.
(a) You must use the methods
described in paragraphs (d) or (e) in this
section to conduct annual leak detection
of fugitive emissions from all sources
listed in § 98.232(a), whether in
operation or on standby. If fugitive
emissions are detected for sources listed
in paragraph (b) of this section, you
must use the measurement methods
described in paragraph(c) of this section
to measure emissions from each source
with fugitive emissions.
(b) You shall use detection
instruments described in paragraphs (d)
and (e) of this section to monitor the
following fugitive emissions:
(1) Centrifugal compressor dry seals
fugitive emissions.
(2) Centrifugal compressor wet seals
fugitive emissions.
(3) Compressor fugitive emissions.
(4) LNG import and export facility
fugitive emissions.
(5) LNG storage station fugitive
emissions.
(6) Non-pneumatic pumps fugitive
emissions.
(7) Open-ended lines (OELs) fugitive
emissions.
(8) Pump seals fugitive emissions.
(9) Offshore platform pipeline fugitive
emissions.
(10) Platform fugitive emissions.
(11) Processing facility fugitive
emissions.
(12) Reciprocating compressor rod
packing fugitive emissions.
(13) Storage station fugitive
emissions.
(14) Transmission station fugitive
emissions.
(15) Storage wellhead fugitive
emissions.
(c) You shall use a high volume
sampler, described in paragraph (f) of
this section, to measure fugitive
emissions from the sources detected in
§ 98.234(b), except as provided in
paragraphs (c)(1) and (2) of this section:
(1) Where high volume samplers
cannot capture all of the fugitive
emissions, you shall use calibrated bags
described in paragraph (g) of this
section or meters described in paragraph
(h) of this section to measure the
following fugitive emissions:
(i) Open-ended lines (OELs).
(ii) Centrifugal compressor dry seals
fugitive emissions.
(iii) Centrifugal compressor wet seals
fugitive emissions.
(iv) Compressor fugitive emissions.
(v) Pump seals fugitive emissions.
(vi) Reciprocating compressor rod
packing fugitive emissions.
(vii) Flare stacks and storage tanks,
except that you shall use meters in
EP10AP09.101</MATH>
(ii) Estimate hydrocarbon vapor
volumetric fugitive emissions at
standard conditions using calculations
in paragraph (e) of this section.
(iii) Estimate CH4 and CO2 volumetric
fugitive emissions from volumetric
hydrocarbon fugitive emissions using
Equation W–8 of this section.
(f) Calculate GHG volumetric fugitive
emissions at standard conditions as
specified in paragraphs (f)(1) and (2) of
this section.
(1) Estimate CH4 and CO2 fugitive
emissions from natural gas fugitive
emissions using Equation W–10 of this
section.
§ 98.234 Monitoring and QA/QC
requirements.
EP10AP09.100</MATH>
Where:
Ea,h = Hydrocarbon vapor fugitive emissions
at actual conditions.
Q = Storage tank total annual throughput.
ER = Measured hydrocarbon vapor emissions
rate per throughput (e.g. cubic feet/
barrel) determined from § 98.234(j)(2).
Ta = Temperature at actual emission
conditions (°F).
Ps = Absolute pressure at standard conditions
(inches of Hg).
Pa = Absolute pressure at ambient conditions
(inches of Hg).
EP10AP09.099</MATH>
(Eq. W-7)
EP10AP09.098</MATH>
Ea,h = Q × ER
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
combination with engineering
estimation methods to calculate fugitive
emissions.
(2) Use hot wire anemometer to
calculate fugitive emissions from
centrifugal compressor wet seal
degassing vents and flares where it is
unsafe or too high a flow rate to use
calibrated bags.
(d) Infrared Remote Fugitive
Emissions Detection.
(1) Use infrared fugitive emissions
detection instruments that can identify
specific equipment sources as emitting.
Such instruments must have the
capability to trace a fugitive emission
back to the specific point where it
escapes the process and enters the
atmosphere.
(2) If you are using instruments that
visually display an image of fugitive
emissions, you shall inspect the
emissions source from multiple angles
or locations until the entire source has
been viewed without visual obstructions
at least once annually.
(3) If you are using any other infrared
detection instruments, such as those
based on infrared laser reflection, you
shall monitor all potential emission
points at least once annually.
(4) Perform fugitive emissions
detection under favorable conditions,
including but not limited to during
daylight hours, in the absence of
precipitation, in the absence of high
wind, and, for active laser devices, in
front of appropriate reflective
backgrounds within the detection range
of the instrument.
(5) Use fugitive emissions detection
and measurement instrument manuals
to determine optimal operating
conditions.
(e) Use organic vapor analyzers
(OVAs) and toxic vapor analyzers
(TVAs) for all fugitive emissions
detection that are safely accessible at
close-range.
(1) Check each potential emissions
source, all joints, connections, and other
potential paths to the atmosphere for
emissions.
(2) Evaluate the lag time between the
instrument sensing and alerting caused
by the residence time of a sample in the
probe shall be evaluated; upon alert, the
instrument shall be slowly retraced over
the source to pinpoint the location of
fugitive emissions.
(3) Use Method 21 of 40 CFR part 60,
appendix A–7, Determination of
Volatile Organic Compound Leaks to
calibrate OVAs and TVAs.
(f) Use a high volume sampler to
measure only cold and steady emissions
within the capacity of the instrument.
(1) A trained technician shall conduct
measurements. The technician shall be
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
conversant with all operating
procedures and measurement
methodologies relevant to using a high
volume sampler, including, but not
limited to, positioning the instrument
for complete capture of the fugitive
emissions without creating backpressure
on the source.
(2) If the high volume sampler, along
with all attachments available from the
manufacturer, is not able to capture all
the emissions from the source then you
shall use anti-static wraps or other aids
to capture all emissions without
violating operating requirements as
provided in the instrument
manufacturer’s manual.
(3) Estimate CH4 and CO2 volumetric
and mass emissions from volumetric
natural gas emissions using the
calculations in § 98.233(f) and (g).
(4) Calibrate the instrument at 2.5
percent methane with 97.5 percent air
and 100 percent CH4 by using calibrated
gas samples and by following
manufacturer’s instructions for
calibration.
(g) Use calibrated bags (also known as
vent bags) only where the emissions are
at near-atmospheric pressures and the
entire fugitive emissions volume can be
captured for measurement.
(1) Hold the bag in place enclosing the
emissions source to capture the entire
emissions and record the time required
for completely filling the bag.
(2) Perform three measurements of the
time required to fill the bag; report the
emissions as the average of the three
readings.
(3) Estimate natural gas volumetric
emissions at standard conditions using
calculations in § 98.233(e).
(4) Estimate CH4 and CO2 volumetric
and mass emissions from volumetric
natural gas emissions using the
calculations in § 98.233(f) and (g).
(5) Obtain consistent results when
measuring the time it takes to fill the
bag with fugitive emissions.
(h) Channel all emissions from a
single source directly through the meter
when using metering (e.g., rotameters,
turbine meters, and others).
(1) Use an appropriately sized meter
so that the flow does not exceed the full
range of the meter in the course of
measurement and conversely has
sufficient momentum for the meter to
register continuously in the course of
measurement.
(2) Estimate natural gas volumetric
fugitive emissions at standard
conditions using calculations in
§ 98.233(f).
(3) Estimate CH4 and CO2 volumetric
and mass fugitive emissions from
volumetric natural gas fugitive
PO 00000
Frm 00233
Fmt 4701
Sfmt 4702
16679
emissions using calculations in
§ 98.233(f) and (g).
(4) Calibrate the meter using either
one of the two methods provided as
follows:
(i) Develop calibration curves by
following the manufacturer’s
instruction.
(ii) Weigh the amount of gas that
flows through the meter into or out of
a container during the calibration
procedure using a master weigh scale
(approved by National Institute of
Standards and Technology (NIST) or
calibrated using standards traceable by
NIST). Determine correction factors for
the flow meter according to the
manufacturer’s instructions. Record
deviations from the correct reading at
several flow rates. Plot the data points,
comparing the flowmeter output to the
actual flowrate as determined by the
master weigh scale and use the
difference as a correction factor.
(i) Where engineering estimation as
described in § 98.233 is not possible,
use direct measurement methods as
follows:
(1) If manufacturer data on pneumatic
pump natural gas emission are not
available, conduct a one-time
measurement to determine natural gas
emission per unit volume of liquid
pumped using a calibrated bag for each
pneumatic pump, when it is pumping
liquids. Determine the volume of liquid
being pumped from the manufacturer’s
manual to provide the amount of natural
gas emitted per unit of liquid pumped.
(i) Record natural gas conditions
(temperature and pressure) and convert
natural gas emission per unit volume of
liquid pumped at actual conditions into
natural gas emission per pumping cycle
at standard conditions using Equation
W–9 of § 98.233.
(ii) Calculate annual fugitive
emissions from the pump using
Equation W–1, by replacing the
manufacturer’s data on emission
(variable Fs) in the Equation with the
standard conditions natural gas
emission calculated in § 98.234(i)(1)(i).
(iii) Estimate CH4 and CO2 volumetric
and mass fugitive emissions from
volumetric natural gas fugitive
emissions using calculations in
§ 98.233(f) and (g).
(2) If manufacturer data on pneumatic
manual valve actuator device natural
gas emission are not available, conduct
a one-time measurement to determine
natural gas emission per actuation using
a calibrated bag for each pneumatic
device per actuation.
(i) Record natural gas conditions
(temperature and pressure) and convert
natural gas emission at actual
conditions into natural gas emission per
E:\FR\FM\10APP2.SGM
10APP2
16680
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
actuation at standard conditions using
Equation W–9 of this subpart.
(ii) Calculate annual fugitive
emissions from the pneumatic device
using Equation W–2 of this section, by
replacing the manufacturer’s data on
emission (variable As) in the Equation
with the standard conditions natural gas
emission calculated in § 98.234(i)(2)(i).
(iii) Estimate CH4 and CO2 volumetric
and mass emissions from volumetric
natural gas fugitive emissions using the
calculations in § 98.233(f) and (g).
(3) If manufacturer data on natural gas
driven pneumatic valve bleed rate is not
available, conduct a one-time
measurement to determine natural gas
bleed rate using a high volume sampler
or calibrated bag or meter for each
pneumatic device.
(i) Record natural gas conditions
(temperature and pressure) to convert
natural gas bleed rate at actual
conditions into natural gas bleed rate at
standard conditions using Equation W–
9 of this subpart.
(ii) Calculate annual fugitive
emissions from the pneumatic device
using Equation W–3 of this subpart, by
replacing the manufacturer’s data on
bleed rate (variable B) in the equation
with the standard conditions bleed rate
calculated in § 98.234(i)(3)(i).
(iii) Estimate CH4 and CO2 volumetric
and mass fugitive emissions from
volumetric natural gas fugitive
emissions using calculations in
§ 98.233(f) and (g).
(j) Parameters for calculating
emissions from flare stacks, compressor
wet seal degassing vents, and storage
tanks.
(1) Estimate fugitive emissions from
flare stacks and compressor wet seal
degassing vents as follows:
(i) Insert flow velocity measuring
device (such as hot wire anemometer or
pitot tube) directly upstream of the flare
stack or compressor wet seal degassing
vent to determine the velocity of gas
sent to flare or vent.
(ii) Record actual temperature and
pressure conditions of the gas sent to
flare or vent.
(iii) Sample representative gas to the
flare stack or compressor wet seal
degassing vent every quarter to evaluate
the composition of GHGs present in the
stream. Record the average of the most
recent four gas composition analyses,
which shall be conducted using ASTM
D1945–03 (incorporated by reference,
see § 98.7).
(2) Estimate fugitive emissions from
storage tanks as follows:
(i) Measure the hydrocarbon vapor
emissions from storage tanks using a
flow meter described in paragraph (h) of
this section for a test period that is
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
representative of the normal operating
conditions of the storage tank
throughout the year and which includes
a complete cycle of accumulation of
hydrocarbon liquids and pumping out
of hydrocarbon liquids from the storage
tank.
(ii) Record the net (related to working
loss) and gross (related to flashing loss)
input of the storage tank during the test
period.
(iii) Record temperature and pressure
of hydrocarbon vapors emitted during
the test period.
(iv) Collect a sample of hydrocarbon
vapors for composition analysis
(k) Component fugitive emissions
sources that are not safely accessible
within the operator’s arm’s reach from
the ground or stationary platforms are
excluded from the requirements of this
section.
(1) Determine annual emissions
assuming that the fugitive emissions
were continuous from the beginning of
the reporting period or last recorded
zero detection in the current reporting
period and continuing until the fugitive
emissions is repaired.
§ 98.235 Procedures for estimating
missing data.
There are no missing data procedures
for this source category. A complete
record of all measured parameters used
in the GHG emissions calculations is
required. If data are lost or an error
occurs during annual emissions
measurements, you must repeat the
measurement activity for those sources
until a valid measurement is obtained.
§ 98.236
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must report emissions data as specified
in this section.
(a) Annual emissions reported
separately for each of the operations
listed in paragraphs (a)(1) through (6) of
this section. Within each operation,
emissions from each source type must
be reported in the aggregate. For
example, an underground natural gas
storage facility with multiple
reciprocating compressors must report
emissions from all reciprocating
compressors as an aggregate number.
(1) Offshore petroleum and natural
gas production facilities.
(2) Onshore natural gas processing
facilities.
(3) Onshore natural gas transmission
compression facilities.
(4) Underground natural gas storage
facilities.
(5) Liquefied natural gas storage
facilities.
(6) Liquefied natural gas import and
export facilities.
PO 00000
Frm 00234
Fmt 4701
Sfmt 4702
(b) Emissions reported separately for
standby equipment.
(c) Emissions calculated for these
sources shall assume no CO2 capture
and transfer off site.
(d) Activity data for each aggregated
source type level for which emissions
are being reported.
(e) Engineering estimate of total
component count.
(f) Total number of compressors and
average operating hours per year for
compressors for each operation listed in
paragraphs (a)(1) through (6) of this
section.
(g) Minimum, maximum and average
throughput for each operation listed in
paragraphs (a)(1) through (6) of this
section.
(h) Specification of the type of any
control device used, including flares, for
any source type listed in 98.232(a).
(i) For offshore petroleum and natural
gas production facilities, the number of
connected wells, and whether they are
producing oil, gas, or both.
(j) Detection and measurement
instruments used.
§ 98.237
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the following records:
(a) Dates on which measurements
were conducted.
(b) Results of all emissions detected,
whether quantification was made
pursuant to § 98.234(k) and
measurements.
(c) Calibration reports for detection
and measurement instruments used.
(d) Inputs and outputs of calculations
or emissions computer model runs used
for engineering estimation of emissions.
§ 98.238
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart X—Petrochemical Production
§ 98.240
Definition of the source category.
(a) The petrochemical production
source category consists of any facility
that produces acrylonitrile, carbon
black, ethylene, ethylene dichloride,
ethylene oxide, or methanol as an
intended product, except as specified in
paragraph (b) of this section.
(b) An integrated process is part of the
petrochemical source category only if
the petrochemical is the primary
product of the integrated process.
§ 98.241
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a petrochemical production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.243
52 j or k
Cg = ∑
⎡
∑ ⎢( F ) ∗ ( CC )
⎢
gf
n =1 i=1
gf
i,n
⎣
Where:
Cg = Annual net contribution to estimated
emissions from carbon (C) in gaseous
feedstocks (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i
introduced in week ‘‘n’’ (standard cubic
feet, scf).
j or k
n=1
15:41 Apr 09, 2009
Jkt 217001
i,n
∗
( MW )
f
i
MVC
− ( Pgp ) ∗ ( CCgp ) ∗
i,n
i,n
(CCgf)i,n = Average carbon content of the
gaseous feedstock i for week ‘‘n’’ (kg C
per kg of feedstock).
(MWf)i = Molecular weight of gaseous
feedstock i (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
(Pgp)i,n = Volume of gaseous product i
produced in week ‘‘n’’ (scf).
52
i =1
Cl = ∑
VerDate Nov<24>2008
Calculating GHG emissions.
(a) Determine process-based GHG
emissions in accordance with the
procedures specified in either paragraph
(a)(1) or (2) of this section, and if
applicable, comply with the procedures
in paragraph (b) of this section.
(1) Continuous emission monitoring
system (CEMS).
(i) If you operate and maintain a
CEMS that measures total CO2
emissions from process vents and
combustion sources according to
subpart C of this part, you must estimate
total CO2 emissions according to the
Tier 4 Calculation Methodology
requirements in § 98.33(a)(4). For each
flare, estimate CO2, CH4, and N2O
emissions using the methodology
specified in § 98.253(b)(1) and (2).
(ii) If you elect to install CEMS to
comply with this subpart, you must
route all process vent emissions to one
or more stacks and use a CEMS on each
stack (except flare stacks) to measure
CO2 emissions. You must estimate total
CO2 emissions according to the Tier 4
Calculation Methodology requirements
in § 98.33(a)(4). For each flare, estimate
CO2, CH4, and N2O emissions using the
methodology specified in § 98.253(b)(1)
and (2) of subpart Y of this part.
(2) Mass balance for each
petrochemical process unit. Estimate the
emissions of CO2 from each process
unit, for each calendar week as
described in paragraphs (a)(2)(i) through
(v) of this section.
(i) Measure the volume of each
gaseous and liquid feedstock and
product continuously with a flow meter
by following the procedures outlined in
§ 98.244(b)(2). Fuels used for
combustion purposes are not considered
to be feedstocks.
∑ (F )
lf
PO 00000
i,n
∗ ( CClf
Frm 00235
)
i,n
− ( Plp ) ∗ ( CClp )
Fmt 4701
i,n
Sfmt 4725
i,n
(ii) Measure the mass rate of each
solid feedstock and product by
following the procedures outlined in
§ 98.244(b)(1) and record the total for
each calendar week.
(iii) Collect a sample of each feedstock
and product at least once per week and
determine the carbon content of each
sample according to the procedures in
§ 98.244(b)(3).
(iv) If you determine that the weekly
average concentration of a specific
compound in a feedstock or product is
always greater than 99.5 percent by
volume (or mass for liquids and solids),
then as an alternative to the sampling
and analysis specified in paragraph
(a)(2)(iii) of this section, you may
calculate the carbon content assuming
100 percent of that feedstock or product
is the specific compound during periods
of normal operation. You must maintain
records of any determination made in
accordance with this paragraph along
with all supporting data, calculations,
and other information. This alternative
may not be used for products during
periods of operation when offspecification product is produced. You
must reevaluate determinations made
under this paragraph after any process
change that affects the feedstock or
product composition. You must keep
records of the process change and the
corresponding composition
determinations. If the feedstock or
product composition changes so that the
average weekly concentration falls
below 99.5 percent, you are no longer
permitted to use this alternative
method.
(v) Estimate CO2 mass emissions for
each petrochemical process unit using
Equations X–1 through X–4 of this
section:
( MW ) ⎤
⎥
p i
MVC ⎥
⎦
(Eq. X-1)
(CCgp)i,n = Average carbon content of gaseous
product i, including streams containing
CO2 recovered for sale or use in another
process, for week ‘‘n’’ (kg C per kg of
product).
(MWp)i = Molecular weight of gaseous
product i (kg/kg-mole).
j = Number of feedstocks.
k = Number of products.
(Eq. X-2)
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.104</MATH>
GHGs to report.
You must report the information in
paragraphs (a) through (d) of this
section:
(a) CO2 emissions from each
petrochemical process unit, following
the methods and procedures in
§§ 98.243 through 98.248. You must
include the volume of any CO2 captured
from process off-gas in the reported CO2
emissions.
(b) CO2, CH4, and N2O emissions from
stationary combustion units. For each
stationary combustion unit, you must
follow the calculation methods and
other requirements specified in subpart
C of this part. If you determine CO2
process-based emissions in accordance
with § 98.243(a)(2), then for each
stationary combustion unit that burns
off-gas from a petrochemical process,
estimate CO2, CH4, and N2O emissions
for the combustion of supplemental fuel
in accordance with subpart C of this
part. In addition, estimate CH4 and N2O
emissions from combusting off-gas
according to the requirements in
§ 98.33(c)(2) and (3) using the emission
factors for Refinery Gas in Table C–3 in
subpart C of this part.
(c) CO2 captured. You must follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements specified in
subpart PP of this part.
(d) CH4 emissions for each on-site
wastewater treatment system. For
wastewater treatment systems, you must
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements specified in subpart II of
this part.
EP10AP09.103</MATH>
§ 98.242
16681
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(Flf)i,n = Volume of liquid feedstock i
introduced in week ‘‘n’’ (gallons).
(CClf)i,n = Average carbon content of liquid
feedstock i for week ‘‘n’’ (kg C per gallon
of feedstock).
52
j or k
n =1
i =1
Cs = ∑
∑ (F )
sf
Where:
Cs = Annual net contribution to estimated
emissions from carbon in solid
feedstocks (kg/yr).
i,n
∗ ( CCsf
Where:
CO2 = Annual CO2 mass emissions from
process operations and fuel gas
combustion (metric tons/year).
0.001 = Conversion factor from kg to metric
tons.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of carbon (C) (kg/kgmole).
(b) If you have an integrated process
unit that is determined to be part of the
petrochemical production source
category, comply with paragraph (a) of
this section by including terms for
additional carbon-containing products
in Equations X–1 through X–3 of this
section as necessary.
§ 98.244 Monitoring and QA/QC
requirements.
(a) Each facility that uses CEMS to
estimate emissions from process vents
must comply with the procedures
specified in § 98.34(e).
(b) Facilities that use the mass balance
methodology in § 98.243(a)(2) must
comply with paragraphs (b)(1) through
(3) of this section.
(1) Measure the mass rate of each
solid feedstock and product (e.g., using
belt scales or weighing at the loadout
points of your process unit) and record
the total for each calendar week. You
must document procedures used to
ensure the accuracy of the
measurements of the feedstock and
product flows including, but not limited
to, calibration of all weighing
equipment and other measurement
devices. The estimated accuracy of
measurements made with these devices
shall be recorded, and the technical
basis for these estimates shall be
recorded.
(2) Measure the volume of each
gaseous and liquid feedstock and
15:41 Apr 09, 2009
Jkt 217001
i,n
− ( Psp ) ∗ ( CCsp ) ⎤
i,n
i,n ⎦
(Fsf)i,n = Mass of solid feedstock i introduced
in week ‘‘n’’ (kg).
(CCsf)i,n = Average carbon content of solid
feedstock i for week ‘‘n’’ (kg C per kg of
feedstock).
CO 2 = 0.001 ∗
VerDate Nov<24>2008
)
44
∗ ( C g + Cl + Cs )
12
Frm 00236
Fmt 4701
Sfmt 4702
(Eq. X-3)
(Psp)i,n = Mass of solid product i produced in
week ‘‘n’’ (kg).
(CCsp)i,n = Average carbon content of solid
product i in week ‘‘n’’ (kg C per kg of
product).
(Eq. X-4)
product for each process unit
continuously with a flow meter. All
feedstock and product flow meters must
be calibrated prior to the first reporting
year, using any applicable method
incorporated by reference in § 98.7(b)(1)
through (6), (c)(1), (f)(3)(i) through (ii),
or (g)(1). You should use the flow meter
accuracy test procedures in appendix D
to part 75 of this chapter. Alternatively,
calibration procedures specified by the
equipment manufacturer may be used.
Flow meters and gas composition
monitors shall be recalibrated annually
or at the frequency specified by another
applicable rule or the manufacturer,
whichever is more frequent.
(3) Collect a sample of each feedstock
and product for each process unit at
least once per week and determine the
carbon content of each sample using an
applicable ASTM method incorporated
by reference in § 98.7(a)(15), (23), or
(24). Alternatively, you may determine
the composition of the sample using a
gas chromatograph and then calculate
the carbon content based on the
composition and molecular weights for
compounds in the sample. Determine
the composition of gas and liquid
samples using either: ASTM D1945–03
incorporated by reference in § 98.7 (a)(8)
of subpart A of this part; ASTM D6060–
96(2001) incorporated by reference in
§ 98.7; ASTM D2502–88(2004)e1
incorporated by reference in § 98.7;
method UOP539–97 incorporated by
reference in § 98.7; or EPA Method 18,
40 CFR part 60, appendix A–6; or
Methods 8031, 8021, or 8015 in ‘‘Test
Methods for Evaluating Solid Waste,
Physical/Chemical Methods,’’ EPA
Publication No. SW–846, Third Edition,
September 1986, as amended by Update
I, November 15, 1992. Calibrate the gas
PO 00000
(Plp)i,n = Volume of liquid product i produced
in week ‘‘n’’ (gallons).
(CClp)i,n = Average carbon content of liquid
product i, including organic liquid
wastes, for week ‘‘n’’ (kg C per gallon of
product).
chromatograph using the procedures in
the method prior to each use. For coal
used as a feedstock, the samples for
carbon content determinations shall be
taken at a location that is representative
of the coal feedstock used during the
corresponding weekly period. For
carbon black products, samples shall be
taken of each grade or type of product
produced during the weekly period.
Samples of coal feedstock or carbon
black product for carbon content
determinations may be either grab
samples collected and analyzed weekly
or a composite of samples collected
more frequently and analyzed weekly.
§ 98.245 Procedures for estimating
missing data.
(a) For missing feedstock flow rates,
product flow rates, and carbon contents,
use the same procedures as for missing
flow rates and carbon contents for fuels
as specified in § 98.35.
(b) For missing CO2 concentration,
stack gas flow rate, and moisture
content for CEMS on any process vent
stack, follow the applicable procedures
specified in § 98.35.
§ 98.246
Data reporting requirements.
(a) Facilities using the mass balance
methodology in § 98.243(a)(2) must
report the information specified in
paragraphs (a)(1) through (9) of this
section for each type of petrochemical
produced, reported by process unit.
(1) Identification of the petrochemical
process.
(2) Annual CO2e emissions calculated
using Equation X–4 of this subpart.
(3) Methods used to determine
feedstock and product flows and carbon
contents.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.106</MATH>
Where:
Cl = Annual net contribution to estimated
emissions from carbon in liquid
feedstocks (kg/yr).
EP10AP09.105</MATH>
16682
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(4) Number of actual and substitute
data points for each measured
parameter.
(5) Annual quantity of each feedstock
consumed.
(6) Annual quantity of each product
and by-product produced, including all
products from integrated processes that
are part of the petrochemical production
source category.
(7) Each carbon content measurement
for each feedstock, product, and byproduct.
(8) All calculations, measurements,
equipment calibrations, certifications,
and other information used to assess the
uncertainty in emission estimates and
the underlying volumetric flow rates,
mass flow rates, and carbon contents of
feedstocks and products.
(9) Identification of any combustion
units that burned process off-gas.
(b) Each facility that uses CEMS to
determine emissions from process vents
must report the verification data
specified in § 98.36(d)(1)(iv).
§ 98.247
Records that must be retained.
In addition to the recordkeeping
requirements in § 98.3(g), you must
retain the following records:
(a) The CEMS recordkeeping
requirements in § 98.37, if you operate
a CEMS on process vents.
(b) Results of feedstock or product
composition determinations conducted
in accordance with § 98.243(a)(2)(iv).
(c) Start and end times and calculated
carbon contents for time periods when
off-specification product is produced, if
you comply with the alternative
methodology in § 98.243(a)(2)(iv) for
determining carbon content of feedstock
or product.
§ 98.248
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart Y—Petroleum Refineries
§ 98.250
Definition of source category.
(a) A petroleum refinery is any facility
engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, asphalt (bitumen)
or other products through distillation of
petroleum or through redistillation,
cracking, or reforming of unfinished
petroleum derivatives.
(b) This source category consists of
the following sources at petroleum
refineries: Catalytic cracking units; fluid
coking units; delayed coking units;
catalytic reforming units; coke calcining
units; asphalt blowing operations;
blowdown systems; storage tanks;
process equipment components
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(compressors, pumps, valves, pressure
relief devices, flanges, and connectors)
in gas service; marine vessel, barge,
tanker truck, and similar loading
operations; flares; land disposal units;
sulfur recovery plants. hydrogen plants
(non-merchant plants only).
§ 98.251
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a petroleum refineries process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.252
GHGs to report.
You must report:
(a) CO2, CH4, and N2O combustion
emissions from stationary combustion
sources and from each flare. For each
stationary combustion unit, you must
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements specified in subpart C of
this part.
(b) CO2, CH4, and N2O coke burn-off
emissions from each catalytic cracking
unit, fluid coking unit, and catalytic
reforming unit.
(c) CO2 emissions from sour gas sent
off site for sulfur recovery operations.
You must follow the calculation
procedures from § 98.253(f) of this
subpart and the monitoring and QA/QC
methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of this
subpart of this part.
(d) CO2 process emissions from each
on-site sulfur recovery plant.
(e) CO2, CH4, and N2O emissions from
each coke calcining unit.
(f) CO2 emissions from asphalt
blowing operations controlled using a
combustion device and CH4 emissions
from asphalt blowing operations not
controlled by a combustion device.
(g) CH4 fugitive emissions from
equipment leaks, storage tanks, loading
operations, delayed coking units, and
uncontrolled blowdown systems.
(h) CO2, CH4, and N2O emissions from
each process vent not specifically
included in paragraphs (a) through (g) of
this section.
(i) CH4 emissions from on-site
landfills. You must follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
HH of this part.
(j) CO2 and CH4 emissions from onsite wastewater treatment. You must
follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
PO 00000
Frm 00237
Fmt 4701
Sfmt 4702
16683
requirements, and recordkeeping
requirements of subpart II of this part.
(k) CO2 and CH4 emissions from nonmerchant hydrogen production. You
must follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of subpart P of this part.
§ 98.253
Calculating GHG emissions.
(a) For stationary combustion sources,
if you operate and maintain a CEMS that
measures total CO2 emissions according
to subpart C of this part, you must
estimate total CO2 emissions according
to the requirements in § 98.33(a)(4).
(b) For flares, calculate GHG
emissions according to the requirements
in paragraphs (b)(1) and (2) of this
section for combustion systems fired
with refinery fuel gas.
(1) Calculate the CO2 emissions
according to the applicable
requirements in paragraphs (b)(1)(i)
through (iii) of this section.
(i) Flow measurement. If you have a
continuous flow monitor on the flare,
you must use the measured flow rates
when the monitor is operational, to
calculate the flare gas flow. If you do not
have a continuous flow monitor on the
flare, you must use engineering
calculations, company records, or
similar estimates of volumetric flare gas
flow.
(ii) Carbon content. If you have a
continuous higher heating value
monitor or carbon content monitor on
the flare or if you monitor these
parameters at least daily, you must use
the measured heat value or carbon
content value in calculating the CO2
emissions from the flare. If you monitor
carbon content, calculate the CO2
emissions from the flare using the
applicable equation in § 98.33(a). If you
monitor heat content, calculate the CO2
emissions from the flare using the
applicable equation in § 98.33(a) and the
default emission factor of 60 kilograms
CO2/MMBtu on a higher heating value
basis.
(iii) Startup, shutdown, malfunction.
If you do not measure the higher heating
value or carbon content of the flare gas
at least daily, determine the quantity of
gas discharged to the flare separately for
periods of routine flare operation and
for periods of start-up, shutdown, or
malfunction, and calculate the CO2
emissions as specified in paragraphs
(b)(1)(iii)(A) through (C) of this section.
(A) For periods of start-up, shutdown,
or malfunction, use engineering
calculations and process knowledge to
estimate the carbon content of the flared
gas for each start-up, shutdown, or
malfunction event.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
for the refinery fuel gas for the heating
value of the flare gas.
44
∗ ( FlareSSM ) p ∗ (CC ) p
12
CO2 = FlareN ∗ HHV ∗ (0.001 ∗ EmF ) + ∑
p =1
Where:
CO2 = Annual CO2 emissions for a specific
fuel type (metric tons/year).
FlareN = Annual volume of flare gas
combusted during normal operations
from company records, (million (MM)
standard cubic feet per year, MMscf/
year).
HHV = Higher heating value for refinery fuel
or flare gas from company records
(British thermal units per scf, Btu/scf =
MMBtu/MMscf).
EmF = Default CO2 emission factor of 60
kilograms CO2/MMBtu (HHV basis).
0.001 = Unit conversion factor (metric tons
per kilogram, mt/kg).
n = Number of start-up, shutdown, and
malfunction events during the reporting
year.
p = Start-up, shutdown, and malfunction
event index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
FlareSSM = Volume of flare gas combusted
during a start-up, shutdown, or
malfunctions from engineering
calculations, (MMscf/event).
(CC)p = Average carbon content of the
gaseous fuel, from the fuel analysis
results or engineering calculations for
the event (gram C per scf = metric tons
C per MMscf).
(2) Calculate CH4 and N2O emissions
according to the requirements in
§ 98.33(c)(2) using the emission factors
for Refinery Gas in Table C–3 in subpart
C of this part.
(c) For catalytic cracking units and
traditional fluid coking units, calculate
the GHG emissions using the applicable
methods described in paragraphs (c)(1)
through (4) of this section.
(1) For catalytic cracking units and
fluid coking units that use a continuous
CO2 CEMS for the final exhaust stack,
calculate the combined CO2 emissions
from each catalytic cracking or fluid
coking unit and CO boiler (if present)
using the CEMS according to the Tier 4
n
CO2 = ∑ ( Qr )n ∗
( %CO
Qr =
Where:
Qr = Volumetric flow rate of exhaust gas from
the fluid catalytic cracking unit
regenerator or fluid coking unit burner
prior to the combustion of other fossil
fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid
catalytic cracking unit regenerator or
fluid coking unit burner, as determined
from control room instrumentation
(dscfh).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
+ %CO
)
n
100%
1
Where:
CO2 = Annual CO2 mass emissions (metric
tons/year).
Qr = Volumetric flow rate of exhaust gas from
the fluid catalytic cracking unit
regenerator or fluid coking unit burner
prior to the combustion of other fossil
fuels (dry standard cubic feet per hour,
dscfh).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream
from the fluid catalytic cracking unit
2
∗
44
∗ 0.001
MVC
regenerator or fluid coking unit burner
(percent by volume—dry basis).
%CO = Hourly average percent CO
concentration in the exhaust gas stream
from the fluid catalytic cracking unit
regenerator or fluid coking unit burner
(percent by volume—dry basis). When
no auxiliary fuel is burned and a
continuous CO monitor is not required,
assume %CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
( 79 ∗ Q + (100 − %O ) ∗ Q )
a
oxy
oxy
100 − %CO2 − %CO − %O2
Frm 00238
Fmt 4701
Sfmt 4702
Calculation Methodology requirements
in § 98.33(a)(4). For units that do not
have a CO boiler or other postcombustion device, Equation Y–3 of this
section may be used as an alternative to
a continuous flow monitor, if one is not
already present.
(2) For catalytic cracking units and
fluid coking units that do not use a
continuous CO2 CEMS for the final
exhaust stack, you must continuously
monitor the O2, CO, and CO2
concentrations in the exhaust stack from
the catalytic cracking unit regenerator or
fluid coking unit burner prior to the
combustion of other fossil fuels and
calculate the CO2 emissions according
to the requirements of paragraphs
(c)(2)(i) through (iii) of this section:
(i) Calculate the CO2 emissions from
each catalytic cracking unit and fluid
coking unit using Equation Y–2 of this
section.
(Eq. Y-2)
0.001 = Conversion factor (metric ton/kg).
n = Number of hours in calendar year.
(ii) Either continuously monitor the
volumetric flow rate of exhaust gas from
the fluid catalytic cracking unit
regenerator or fluid coking unit burner
prior to the combustion of other fossil
fuels or calculate the volumetric flow
rate of this exhaust gas stream using
Equation Y–3 of this section.
(Eq. Y-3)
Qoxy = Volumetric flow rate of oxygen
enriched air to the fluid catalytic
cracking unit regenerator or fluid coking
unit burner as determined from control
room instrumentation (dscfh).
%O2 = Hourly average percent oxygen
concentration in exhaust gas stream from
the fluid catalytic cracking unit
regenerator or fluid coking unit burner
(percent by volume—dry basis).
%Ooxy = O2 concentration in oxygen enriched
gas stream inlet to the fluid catalytic
PO 00000
(Eq. Y-1)
cracking unit regenerator or fluid coking
unit burner based on oxygen purity
specifications of the oxygen supply used
for enrichment (percent by volume—dry
basis).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream
from the fluid catalytic cracking unit
regenerator or fluid coking unit burner
(percent by volume—dry basis).
%CO = Hourly average percent CO
concentration in the exhaust gas stream
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.109</MATH>
n
(C) Calculate the CO2 emissions using
Equation Y–1 of this section.
EP10AP09.108</MATH>
(B) For periods of normal operation,
use the average heating value measured
EP10AP09.107</MATH>
16684
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Where:
CH4 = Annual methane emissions from coke
burn-off (metric tons CH4/year).
CO2 = Emission rate of CO2 from coke burnoff calculated in paragraphs (c)(1), (c)(2),
Where:
N2O = Annual nitrous oxide emissions from
coke burn-off (mt N2O/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C–1 of
subpart C of this part (kg CO2/MMBtu).
EmF2 = Default N2O emission factor for
petroleum coke from Table C–3 of
subpart C of this part (kg N2O/MMBtu).
(d) For fluid coking units that use the
flexicoking design, the GHG emissions
from the resulting use of the low value
n
CO 2 = ∑ ( CBQ ) ∗ CF ∗
n
1
Where:
CO2 = Annual CO2 emissions (metric tons/
year).
CBQ = Coke burn-off quantity per
regeneration cycle (kg coke/cycle).
CF = Site-specific fraction carbon content of
produced coke, use 0.94 if site-specific
fraction carbon content is unavailable (kg
C per kg coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
n = Number of regeneration cycles in the
calendar year.
0.001 = Conversion factor (mt/kg).
(f) For on-site sulfur recovery plants,
calculate CO2 process emissions from
sulfur recovery plants according to the
requirements in paragraphs (f)(1)
through (4) of this section. Except as
Where:
CO2 = Annual CO2 emissions (metric tons/
year).
FSG = Volumetric flow rate of sour gas feed
to the sulfur recovery plant (scf/year).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
MFC = Mole fraction of carbon in the sour gas
to the sulfur recovery plant (kg-mole C/
kg-mole gas); default = 0.20.
0.001 = Conversion factor, kg to metric tons.
15:41 Apr 09, 2009
Jkt 217001
44
∗ 0.001
12
(Eq. Y-6)
provided in paragraph (f)(4) of this
section, combustion emissions from the
sulfur recovery plant (e.g., from fuel
combustion in the Claus burner or the
tail gas treatment incinerator) must be
reported under subpart C of this part.
For the purposes of this subpart, the
sour gas stream for which monitoring is
required according to paragraphs (f)(1)
through (3) of this section is not
considered a fuel.
(1) Flow measurement. If you have a
continuous flow monitor on the sour gas
feed to the sulfur recovery plant, you
must use the measured flow rates when
the monitor is operational to calculate
the sour gas flow rate. If you do not have
a continuous flow monitor on the sour
CO 2 = FSG ∗
VerDate Nov<24>2008
(Eq. Y-5)
44
∗ MFC ∗ 0.001
MVC
(Eq. Y-7)
(4) As an alternative to the monitoring
methods in paragraphs (f)(1) through (3)
of this section, you may use a
continuous flow monitor and CO2 CEMS
in the final exhaust stack from the sulfur
recovery plant according to the
requirements in § 98.33(a)(4) to
calculate the combined process and
combustion emissions for the sulfur
recovery plant. You must monitor fuel
use in the Claus burner, tail gas
incinerator, or other combustion sources
PO 00000
Frm 00239
Fmt 4701
Sfmt 4702
gas feed to the sulfur recovery plant,
you must use engineering calculations,
company records, or similar estimates of
volumetric sour gas flow.
(2) Carbon content. If you have a
continuous compositional or carbon
content monitor on the sour gas feed to
the sulfur recovery plant or if you
monitor these parameters on a routine
basis, you must use the measured
carbon content value. Alternatively, you
may develop a site-specific carbon
content factor or use the default factor
of 0.20.
(3) Calculate the CO2 emissions from
each sulfur recovery plant using
Equation Y–7 of this section.
that discharge via the final exhaust stack
from the sulfur recovery plant and
calculate the combustion emissions
from the fuel use according to subpart
C of this part. You must report the
process emissions from the sulfur
recovery plant as the difference in the
CO2 CEMS emissions and the calculated
combustion emissions associated with
the sulfur recovery plant final exhaust
stack.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.113</MATH>
(Eq. Y-4)
⎛
EmF1 ⎞
N 2 O = ⎜ CO 2 ∗
⎟
EmF2 ⎠
⎝
EP10AP09.112</MATH>
⎛
EmF1 ⎞
CH 4 = ⎜ CO 2 ∗
⎟
EmF2 ⎠
⎝
(4) Calculate N2O emissions using
Equation Y–5 of this section.
fuel gas must be accounted for only
once. Typically, these emissions will be
accounted for using the methods
described in subpart C of this part for
combustion sources. Alternatively, you
may use the methods in paragraph (c) of
this section provided that you do not
otherwise account for the subsequent
combustion of this low value fuel gas.
(e) For catalytic reforming units,
calculate the CO2 emissions using either
the methods described in paragraphs
(e)(1) or (2) of this section and calculate
the CH4 and N2O emissions using the
Equations Y–4 and Y–5 of this section,
respectively.
(1) Calculate CO2 emissions from the
catalytic reforming unit catalyst
regenerator using the methods in
paragraphs (c)(1) or (2) of this section,
or
(2) Calculate CO2 emissions from the
catalytic reforming unit catalyst
regenerator using Equation Y–6 of this
section.
EP10AP09.111</MATH>
(iii) If a CO boiler or other postcombustion device is used, calculate the
GHG emissions from the fuel fired to the
CO boiler or post-combustion device
using the methods for stationary
combustion sources in paragraph (a) of
this section and report this separately
for the combustion unit.
(3) Calculate CH4 emissions using
Equation Y–4 of this section.
(e)(1), (e)(2), (g)(1), or (g)(2) of this
section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C–1 of
subpart C of this part (kg CO2/MMBtu).
EmF2 = Default CH4 emission factor for
petroleum coke from Table C–3 of
subpart C of this part (kg CH4/MMBtu).
EP10AP09.110</MATH>
from the fluid catalytic cracking unit
regenerator or fluid coking unit burner
(percent by volume—dry basis). When
no auxiliary fuel is burned and a
continuous CO monitor is not required,
assume %CO to be zero.
16685
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
44
∗ ( M in ∗ CCGC − ( M out + M dust ) ∗ CCMPC )
12
Mdust = Annual mass of petroleum coke dust
collected in the dust collection system of
the coke calcining unit from facility
records (metric ton petroleum coke dust/
year).
CCMPC = Average mass fraction carbon
content of marketable petroleum coke
produced by the coke calcining unit from
facility measurement data (metric ton
carbon/metric ton petroleum coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(3) For all coke calcining units, use
the CO2 emissions from the coke
16
⎛
⎞
CH 4 = ⎜ QAB ∗ EFAB ∗
∗ 0.001⎟
MVC
⎝
⎠
44
⎛
⎞
CO 2 = ⎜ QAB ∗ EFAB ∗
∗ 1 ∗ 0.001⎟
MVC
⎝
⎠
Where:
CO2 = Annual CO2 emissions (metric ton/
year).
QAB = Quantity of asphalt blown (MMbbl/
year).
EFAB = Default emission factor (2,555,000 scf
CH4/MM bbl).
44 = Molecular weight of CO2 (kg/kg-mole).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
1 = Assumed conversion efficiency (kg-mole
CO2/kg-mole CH4).
0.001 = Conversion factor (metric tons/kg).
(i) For delayed coking units, calculate
the CH4 emissions from the
N = Total number of vessel openings for all
delayed coking unit vessels of the same
dimensions during the year.
H = Height of coking unit vessel (feet).
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
PO 00000
Frm 00240
Fmt 4701
Sfmt 4702
(2) For controlled asphalt blowing
operations, calculate CO2 emissions
using Equation Y–10 of this section,
provided these emissions are not
already included in the flare emissions
calculated in paragraph (b) of this
section.
(Eq. Y-10)
⎛
⎞
π ∗ D2
16
CH 4 = ⎜ N ∗ H ∗
∗
∗ MFCH 4 ∗ 0.001⎟
4
MVC
⎝
⎠
Where:
CH4 = Annual methane emissions from the
delayed coking unit vessel opening
(metric ton/year).
calcining unit calculated in paragraphs
(g)(1) or (2), as applicable, and calculate
CH4 using Equation Y–4 of this section
and N2O emissions using Equation Y–5
of this section.
(h) For asphalt blowing operations,
calculate GHG emissions according to
the applicable provisions in paragraphs
(h)(1) and (2) of this section.
(1) For uncontrolled asphalt blowing
operations, calculate CH4 emissions
using Equation Y–9 of this section.
(Eq. Y-9)
EFAB = Emission factor for asphalt blowing
from facility-specific test data (scf CH4/
MMbbl); use 2,555,000 scf CH4/MMbbl if
facility-specific test data are unavailable.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
Where:
CH4 = Annual methane emissions from
uncontrolled asphalt blowing (metric
tons CH4/year).
QAB = Quantity of asphalt blown (million
barrels per year, MMbbl/year).
(Eq. Y-8)
depressurization of the coking unit
vessel to atmosphere using the process
vent method in paragraph (j) of this
section and calculate the CH4 emissions
from the subsequent opening of the
vessel for coke cutting operations using
Equation Y–11 of this section.
(Eq. Y-11)
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
MFCH4 = Mole fraction of methane in coking
vessel gas (kg-mole CH4/kg-mole gas);
default value is 0.03.
0.001 = Conversion factor (metric ton/kg).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.117</MATH>
Where:
CO2 = Annual CO2 emissions (metric tons/
year).
Min = Annual mass of green coke fed to the
coke calcining unit from facility records
(metric tons/year).
CCGC = Average mass fraction carbon content
of green coke from facility measurement
data (metric ton carbon/metric ton green
coke).
Mout = Annual mass of marketable petroleum
coke produced by the coke calcining unit
from facility records (metric tons
petroleum coke/year).
(i) Calculate the CO2 emissions for
any auxiliary fuel fired to the calcining
unit using the applicable methods in
subpart C of this part.
(ii) Calculate the CO2 emissions from
the coke calcining process using
Equation Y–8 of this section.
EP10AP09.116</MATH>
CO 2 =
combusted using the CEMS according to
the requirements in § 98.33(a)(4).
(2) For coke calcining units that do
not use a continuous CO2 CEMS for the
final exhaust stack, calculate CO2
emissions from the coke calcining unit
according to the requirements in
paragraphs (g)(2)(i) and (ii) of this
section.
EP10AP09.115</MATH>
(g) For coke calcining units, calculate
GHG emissions according to the
applicable provisions in paragraphs
(g)(1) through (3) of this section.
(1) For coke calcining units that use
a continuous CO2 CEMS for the final
exhaust stack, calculate the combined
CO2 emissions from the coke calcining
process and any auxiliary fuel
EP10AP09.114</MATH>
16686
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
the Equation Y–12 of this section. You
must use Equation Y–12 for catalytic
reforming unit depressurization and
MFx = Mole fraction of GHG x in process
vent.
MWx = Molecular weight of GHG x (kg/kgmole); use 44 for CO2 or N2O and 16 for
CH4.
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
VTn = Venting time, (hours per event).
Where:
CH4 = Methane emission rate from blowdown
systems (mt CH4/year).
QRef = Quantity of crude oil plus the quantity
of intermediate products received from
off site that are processed at the facility
(MMbbl/year).
EFBD = Methane emission factor for
uncontrolled blown systems (scf CH4/
MMbbl); default is 137,000.
(k) For uncontrolled blowdown
systems, you must either use the
methods for process vents in paragraph
(j) of this section or calculate CH4
emissions using Equation Y–13 of this
section.
(Eq. Y-13)
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(l) For equipment leaks, calculate CH4
emissions using the method specified in
either paragraph (l)(1) or (l)(2) of this
section.
(1) Use process-specific methane
composition data (from measurement
data or process knowledge) and any of
the emission estimation procedures
provided in the Protocol for Equipment
Leak Emissions Estimates (EPA–453/R–
95–017, NTIS PB96–175401).
(2) Use Equation Y–14 of this section.
CH 4 = ( 0.4 ∗ N CD + 0.2 ∗ N PU 1 + 0.1 ∗ N PU 2 + 4.3 ∗ N H 2 + 6 ∗ N FGS )
Where:
CH4 = Annual methane emissions from
fugitive equipment leaks (metric tons/
year)
NCD = Number of atmospheric crude oil
distillation columns at the facility.
NPU1 = Cumulative number of catalytic
cracking units, coking units (delayed or
fluid), hydrocracking, and full-range
distillation columns (including
depropanizer and debutanizer
distillation columns) at the facility.
NPU2 = Cumulative number of hydrotreating/
hydrorefining units, catalytic reforming
units, and visbreaking units at the
facility.
NH2 = Total number of hydrogen plants at the
facility.
NFGS = Total number of fuel gas systems at
the facility.
(m) For storage tanks, calculate CH4
emissions using the applicable methods
in paragraphs (m)(1) and (2) of this
section.
(1) For storage tanks other than those
processing unstabilized crude oil, you
must either calculate CH4 emissions
from storage tanks that have a vaporphase methane concentration of 0.5
volume percent or more using tankspecific methane composition data
(from measurement data or product
knowledge) and the TANKS Model
(Version 4.09D) or estimate CH4
emissions from storage tanks using
Equation Y–15 of this section.
CH 4 = ( 0.1 ∗ QRe f
)
CH 4 = ( 995,000 ∗ Qun ∗ ΔP ) ∗ MFCH 4 ∗
Where:
CH4 = Annual methane emissions from
storage tanks (metric tons/year).
Qun = Quantity of unstabilized crude oil
received at the facility (MMbbl/year).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. Y-15)
16
∗ 0.001
MVC
DP = Pressure differential from the previous
storage pressure to atmospheric pressure
(pounds per square inch, psi).
MFCH4 = Mole fraction of CH4 in vent gas
from the unstabilized crude oil storage
tank from facility measurements (kg-
PO 00000
Frm 00241
Fmt 4701
Sfmt 4702
(Eq. Y-14)
Where:
CH4 = Annual methane emissions from
storage tanks (metric tons/year).
0.1 = Default emission factor for storage tanks
(metric ton CH4/MMbbl).
QRef = Quantity of crude oil plus the quantity
of intermediate products received from
off site that are processed at the facility
(MMbbl/year).
(2) For storage tanks that process
unstabilized crude oil, calculate CH4
emissions from the storage of
unstabilized crude oil using either tankspecific methane composition data
(from measurement data or product
knowledge) and direct measurement of
the gas generation rate or by using
Equation Y–16 of this section.
(Eq. Y-16)
mole CH4/kg-mole gas); use 0.27 as a
default if measurement data are not
available.
995,000 = Correlation Equation factor (scf gas
per MMbbl per psi)
16 = Molecular weight of CH4 (kg/kg-mole).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.122</MATH>
16
⎛
⎞
CH 4 = ⎜ QRe f ∗ EFBD ∗
∗ 0.001⎟
MVC
⎝
⎠
0.001 = Conversion factor (metric ton/kg)
EP10AP09.121</MATH>
Where:
Ex = Annual emissions of each GHG from
process vent (metric ton/yr).
N = Number of venting events per year.
VRn = Volumetric flow rate of process vent
(scf per hour per event).
44 = Molecular weight of CO2 (kg/kg-mole).
(Eq. Y-12)
EP10AP09.120</MATH>
n =1
MWx
∗ VTn ∗ 0.001
MVC
EP10AP09.119</MATH>
N
Ex = ∑ VRn ∗ MFx ∗
purge vents when methane is used as
the purge gas.
EP10AP09.118</MATH>
(j) For each process vent not covered
in paragraphs (a) through (i) of this
section, calculate GHG emissions using
16687
16688
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(n) For crude oil, intermediate, or
product loading operations for which
the equilibrium vapor-phase
concentration of methane is 0.5 volume
percent or more, calculate CH4
emissions from loading operations using
product-specific, vapor-phase methane
composition data (from measurement
data or process knowledge) and the
emission estimation procedures
provided in Section 5.2 of the AP–42:
‘‘Compilation of Air Pollutant Emission
Factors, Volume 1: Stationary Point and
Area Sources’’. For loading operations
in which the equilibrium vapor-phase
concentration of methane is less than
0.5 volume percent, report zero methane
emissions.
§ 98.254 Monitoring and QA/QC
requirements.
(a) All fuel flow meters, gas
composition monitors, and heating
value monitors that are used to provide
data for the GHG emissions calculations
shall be calibrated prior to the first
reporting year, using a suitable method
published by a consensus standards
organization (e.g., ASTM, ASME, API,
AGA, etc.). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Fuel flow
meters, gas composition monitors, and
heating value monitors shall be
recalibrated either annually or at the
minimum frequency specified by the
manufacturer.
(b) The owner or operator shall
document the procedures used to ensure
the accuracy of the estimates of fuel
usage, gas composition, and heating
value including but not limited to
calibration of weighing equipment, fuel
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.
(c) All CO2 CEMS and flow rate
monitors used for direct measurement of
GHG emissions must comply with the
QA procedures in § 98.34(e).
§ 98.255 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required (e.g.,
concentrations, flow rates, fuel heating
values, carbon content values).
Therefore, 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
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
substitute data value for the missing
parameter shall be used in the
calculations.
(a) For each missing value of the heat
content, carbon content, or molecular
weight of the fuel, the substitute data
value shall be the arithmetic average of
the quality-assured values of that
parameter immediately preceding and
immediately following the missing data
incident. 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.
(b) For missing oil and gas flow rates,
use the standard missing data
procedures in section 2.4.2 of appendix
D to part 75 of this chapter.
(c) For missing CO2, CO, or O2, CH4,
and N2O concentrations, stack gas flow
rate, and stack gas moisture content
values, use the applicable initial
missing data procedures in § 98.35 of
subpart C of this part.
(d) For hydrogen plants, use the
missing data procedures in subpart P of
this part.
(e) For petrochemical production
units, use the missing data procedures
in subpart X of this part.
(f) For on-site landfills, use the
missing data procedures in subpart HH
of this part.
(g) For on-site wastewater treatment
systems, use the missing data
procedures in subpart II of this part.
§ 98.256
Data reporting requirements.
In addition to the reporting
requirements of § 98.3(c), you must
report the information specified in
paragraphs (a) through (e) of this
section.
(a) For combustion sources, including
flares, use the data reporting
requirements in § 98.36.
(b) For hydrogen plants, use the data
reporting requirements in subpart P of
this part.
(c) For petrochemical production
units, use the data reporting
requirements in subpart X of this part.
(d) For on-site landfills, use the data
reporting requirements in subpart HH of
this part.
(e) For on-site wastewater treatment
systems, use the data reporting
requirements in subpart II of this part.
(f) For catalytic cracking units,
traditional fluid coking units, catalytic
reforming units, sulfur recovery plants,
and coke calcining units, owners and
operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit
(fluid catalytic cracking unit, thermal
catalytic cracking unit, traditional fluid
PO 00000
Frm 00242
Fmt 4701
Sfmt 4702
coking unit, catalytic reforming unit,
sulfur recovery plant, or coke calcining
unit).
(3) Maximum rated throughput of the
unit, in bbl/stream day, metric tons
sulfur produced/stream day, or metric
tons coke calcined/stream day, as
applicable.
(4) The calculated CO2, CH4, and N2O
annual emissions for each unit,
expressed in metric tons of each
pollutant emitted.
(5) A description of the method used
to calculate the CO2 emissions for each
unit (e.g., reference section and
Equation number).
(g) For fluid coking unit of the
flexicoking type, the owner or operator
shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the
unit, in bbl/stream day.
(4) Indicate whether the GHG
emissions from the low heat value gas
are accounted for in subpart C of this
part or § 98.253(c).
(5) If the GHG emissions for the low
heat value gas are calculated at the
flexicoking unit, also report the
calculated annual CO2, CH4, and N2O
emissions for each unit, expressed in
metric tons of each pollutant emitted.
(h) For asphalt blowing operations,
the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) The quantity of asphalt blown.
(3) The type of control device used to
reduce methane (and other organic)
emissions from the unit.
(4) The calculated annual CO2, CH4,
and N2O emissions for each unit,
expressed in metric tons of each
pollutant emitted.
(i) For process vents subject to
§ 98.253(j), the owner or operator shall
report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated
with the emissions.
(3) The type of control device used to
reduce methane (and other organic)
emissions from the unit, if applicable.
(4) The calculated annual CO2, CH4,
and N2O emissions for each unit,
expressed in metric tons of each
pollutant emitted.
(j) For equipment leaks, storage tanks,
uncontrolled blowdown systems,
delayed coking units, and loading
operations, the owner or operator shall
report:
(1) The total quantity (in Million bbl)
of crude oil plus the quantity of
intermediate products received from offsite that are processed at the facility in
the reporting year.
(2) The method used to calculate
equipment leak emissions and the
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(9) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for loading
operations.
(k) If you have a CEMS that measures
CO2 emissions but that is not required
to be used for reporting GHG emissions
under this subpart (i.e., a CO2 CEMS on
a process heater stack but the
combustion emissions are calculated
based on the fuel gas consumption), you
must identify the emission source that
has the CEMS and report the CO2
emissions as measured by the CEMS for
that emissions source.
§ 98.258
Subpart Z—Phosphoric Acid
Production
§ 98.260
n =1
p
CO2 = ∑ Em
(Eq. Z-2)
m =1
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Definition of the source category.
The phosphoric acid production
source category consists of facilities
with a wet-process phosphoric acid
process line used to produce phosphoric
acid. A wet-process phosphoric acid
process line is any system of operation
z
(c) You must determine the total
emissions from the facility using
Equation Z–2 of this section:
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Em = ∑
Where:
Em = Annual CO2 mass emissions from a wetprocess phosphoric acid process line m
(metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
ICn = Inorganic carbon content of the batch
of phosphate rock used during month n,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
Pn = Mass of phosphate rock consumed in
month n by wet-process phosphoric acid
process line m (tons).
m = Each wet-process phosphoric acid
process line.
z = Number of months during which the
process line m operates.
2000/2205 = Conversion factor to convert
tons to metric tons.
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records of
all parameters monitored under
§ 98.255.
44
2000
∗ [ ICn ∗ Pn ] ∗
12
2205
§ 98.264 Monitoring and QA/QC
requirements.
(a) Determine the inorganic carbon
content of each batch of phosphate rock
consumed in the production of
phosphoric acid using the applicable
test method in section IX of the ‘‘Book
of Methods Used and Adopted by the
Association of Florida Phosphate
Chemists’’, Seventh Edition, 1991.
(b) If more than one batch of
phosphate rock is consumed in a month,
use the highest inorganic carbon content
measured during that month in
Equation Z–1 of this subpart.
Frm 00243
Fmt 4701
Sfmt 4702
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a phosphoric acid production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.262
GHGs to report.
(a) You must report CO2 process
emissions from each wet-process
phosphoric acid production line.
(b) You must report CO2, N2O, and
CH4 emissions from each stationary
combustion unit. You must follow the
calculation methods and all other
requirements of subpart C of this part.
§ 98.263
Calculating GHG emissions.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must estimate total CO2 emissions
according to the requirements in
§ § 98.33(a) and 98.35.
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must calculate process emissions of
CO2 from each wet-process phosphoric
acid process line using Equation Z–1 of
this section:
(Eq. Z-1)
Where:
CO2 = Annual process CO2 emissions from
phosphoric acid production
facility(metric tons/year)
Em = Annual process CO2 emissions from
wet-process phosphoric acid process line
m (metric tons/year)
p = Number of wet-process phosphoric acid
process lines.
PO 00000
§ 98.261
(c) Record the mass of phosphate rock
consumed each month in each wetprocess phosphoric acid process line.
§ 98.265 Procedures for estimating
missing data.
There are no missing data procedures
for wet-process phosphoric acid
production facilities estimated
according to § 98.263(b). A complete
record of all measured parameters used
in the GHG emissions calculations is
required. A re-test must be performed if
the data from the measurement are
determined to be unacceptable.
§ 98.266
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (e) of this
section for each wet-process phosphoric
acid production line:
(a) Annual phosphoric acid
production by origin of the phosphate
rock (metric tons).
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.124</MATH>
§ 98.257
that manufactures phosphoric acid by
reacting phosphate rock and acid.
EP10AP09.123</MATH>
calculated, cumulative CH4 emissions
(in metric tons of each pollutant
emitted) for all equipment leak sources.
(3) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for all storage tanks,
except for those used to process
unstabilized crude oil.
(4) The quantity of unstabilized crude
oil received during the calendar year
and the cumulative CH4 emissions (in
metric tons of each pollutant emitted)
for storage tanks used to process
unstabilized crude oil.
(5) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for uncontrolled
blowdown systems.
(6) The total number of delayed
coking units at the facility, the number
of delayed coking drums per unit, the
dimensions and annual number of cokecutting cycles for each drum, and the
cumulative annual CH4 emissions (in
metric tons of each pollutant emitted)
for delayed coking units.
(7) The quantity and types of
materials loaded that have an
equilibrium vapor-phase concentration
of methane of 0.5 volume percent or
greater, and the type of vessels in which
the material is loaded.
(8) The type of control system used to
reduce emissions from the loading of
material with an equilibrium vaporphase concentration of methane of 0.5
volume percent or greater, if any.
16689
16690
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.267
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (h)
of this section for each wet-process
phosphoric acid production facility:
(a) Total annual CO2 emissions from
all wet-process phosphoric acid process
lines (in metric tons).
(b) Phosphoric acid production (by
origin of the phosphate rock) and
concentration.
(c) Phosphoric acid production
capacity (in metric tons/year).
(d) Number of wet-process phosphoric
acid process lines.
(e) Monthly phosphate rock
consumption (by origin of phosphate
rock).
(f) Measurements of percent inorganic
carbon in phosphate rock for each batch
consumed for phosphoric acid
production.
(g) Records of all phosphate rock
purchases and/or deliveries (if vertically
integrated with a mine).
(h) Documentation of the procedures
used to ensure the accuracy of monthly
phosphate rock consumption.
§ 98.268
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart AA—Pulp and Paper
Manufacturing
§ 98.270
Definition of source category.
(a) The pulp and paper manufacturing
source category consists of facilities that
produce market pulp (i.e., stand-alone
pulp facilities), manufacture pulp and
paper (i.e., integrated facilities), produce
paper products from purchased pulp,
produce secondary fiber from recycled
paper, convert paper into paperboard
products (e.g., containers), and operate
coating and laminating processes.
(b) The emission units for which GHG
emissions must be reported are listed in
paragraphs (b)(1) through (6) of this
section:
(1) Chemical recovery furnaces at
kraft and sodamills (including recovery
furnaces that burn spent pulping liquor
produced by both the kraft and
semichemical process).
(2) Chemical recovery combustion
units at sulfite facilities.
(3) Chemical recovery combustion
units at stand-alone semichemical
facilities.
(4) Pulp mill lime kilns at kraft and
soda facilities.
(5) Systems for adding makeup
chemicals (CaCO3, Na2CO3).
§ 98.271
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a pulp and paper
manufacturing process and the facility
meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.272
GHGs to report.
You must report the emissions listed
in paragraphs (a) through (h) of this
section:
(a) CO2, biogenic CO2, CH4, and N2O
emissions from each kraft or soda
chemical recovery furnace.
(b) CO2, biogenic CO2, CH4, and N2O
emissions from each sulfite chemical
recovery combustion unit.
(c) CO2, biogenic CO2, CH4, and N2O
emissions from each semichemical
chemical recovery combustion unit.
(d) CO2, biogenic CO2, CH4, and N2O
emissions from each kraft or soda pulp
mill lime kiln.
(e) CO2 emissions from addition of
makeup chemicals (CaCO3, Na2CO3).
(f) Emissions of CO2, N2O, and CH4
from any other on-site stationary fuel
combustion units (boilers, gas turbines,
thermal oxiders, and other sources). You
12
(
must follow the calculation procedures,
monitoring and QA/QC methods,
missing data procedures, reporting
requirements, and recordkeeping
requirements of subpart C of this part.
(g) Emissions of CH4 from on-site
landfills. You must follow the
calculation procedures, monitoring and
QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
HH of this part.
(h) Emissions of CH4 from on-site
wastewater treatment. You must follow
the calculation procedures, monitoring
and QA/QC methods, missing data
procedures, reporting requirements, and
recordkeeping requirements of subpart
II of this part.
§ 98.273
Calculating GHG emissions.
(a) For each chemical recovery
furnace located at a kraft or soda
facility, you must determine CO2,
biogenic CO2, CH4, and N2O emissions
using the procedures in paragraphs
(a)(1) through (3) of this section. CH4
and N2O emissions must be calculated
as the sum of emissions from
combustion of fossil fuels and
combustion of biomass in spent liquor
solids.
(1) Calculate fossil fuel-based CO2
emissions from direct measurement of
fossil fuels consumed and default
emissions factors according to the Tier
1 methodology for stationary
combustion sources in § 98.33(a)(1).
(2) Calculate fossil fuel-based CH4 and
N2O emissions from direct measurement
of fossil fuels consumed, default HHV,
and default emissions factors and
convert to metric tons of CO2 equivalent
according to the methodology for
stationary combustion sources in
§ 98.33(c)(2) and (3).
(3) Calculate biogenic CO2, CH4, and
N2O emissions from biomass using
measured quantities of spent liquor
solids fired, site-specific HHV, and
default or site-specific emissions factors,
according to Equation AA–1 of this
section:
)
CO 2 , CH 4 , or N 2 O from biomass = ∑ 1 x 10−3 (907) ( Solids) p ∗ ( HHV ) p ∗ EF
p =1
Where:
CH4, or N2O, from Biomass = Biogenic CO2,
CH4, or N2O mass emissions from spent
liquor solids combustion (metric tons).
(Solids)p = Mass of spent liquor solids
combusted per month p (short tons per
month).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(HHV)p = High heat value of the spent liquor
solids for month p (mmBtu per mass).
EF = Default emission factor for CO2, CH4, or
N2O, from Table AA–1 of this subpart (kg
CO2, CH4, or N2O per mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
PO 00000
Frm 00244
Fmt 4701
Sfmt 4702
(Eq. AA-1)
907 = Conversion factor from tons to
kilograms.
(b) For each chemical recovery
combustion unit located at a sulfite or
stand-alone semichemical facility, you
must determine CO2, CH4, and N2O
emissions using the procedures in
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.125</MATH>
(b) Annual phosphoric acid
production by concentration of
phosphoric acid produced (metric tons).
(c) Annual phosphoric acid
production capacity.
(d) Annual arithmetic average percent
inorganic carbon in phosphate rock
from batch records.
(e) Annual average phosphate rock
consumption from monthly
measurement records (in metric tons).
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
paragraphs (b)(1) through (4) of this
section:
(1) Calculate fossil CO2 emissions
from fossil fuels from direct
measurement of fossil fuels consumed
and default emissions factors according
to the Tier 1 Calculation Methodology
for stationary combustion sources in
§ 98.33(a)(1).
(2) Calculate CH4 and N2O emissions
from fossil fuels from direct
measurement of fossil fuels consumed,
default HHV, and default emissions
factors and convert to metric tons of CO2
equivalent according to the
16691
methodology for stationary combustion
sources in § 98.33(c)(2).
(3) Calculate biogenic CO2 emissions
using measured quantities of spent
liquor solids fired and the carbon
content of the spent liquor solids,
according to Equation AA–2 of this
section:
12
(4) Calculate CH4 and N2O emissions
from biomass using Equation AA–1 and
the default CH4 and N2O emissions
factors for kraft facilities in Table AA–
1 of this subpart and convert the CH4 or
N2O emissions to metric tons of CO2
equivalent according to the
methodology for stationary combustion
sources in § 98.2(b)(4).
(c) For each pulp mill lime kiln
located at a kraft or soda facility, you
must determine CO2, CH4, and N2O
emissions using the procedures in
paragraphs (c)(1) through (3) of this
section:
(1) Calculate CO2 emissions from
fossil fuel from direct measurement of
fossil fuels consumed and default HHV
and default emissions factors, according
to the Tier 1 Calculation Methodology
for stationary combustion sources in
§ 98.33(a)(1); use the default HHV listed
in Table C–1 of subpart C of this part
and the default CO2 emissions factors
listed in Table AA–2 of this subpart.
(2) Calculate CH4 and N2O emissions
from fossil fuel from direct
measurement of fossil fuels consumed,
default HHV, and default emissions
factors and convert to metric tons of CO2
equivalent according to the
methodology for stationary combustion
sources in § 98.33(c)(2) and (3); use the
default HHV listed in Table C–1 of
subpart C of this part and the default
CH4 and N2O emissions factors listed in
Table AA–2 of this subpart.
(3) Biogenic CO2 emissions from
conversion of CaCO3 to CaO are
calculated as part of the chemical
recovery furnace biogenic CO2 estimates
in paragraph (a)(3) of this section.
(d) For makeup chemical use, you
must calculate CO2 emissions by using
direct or indirect measurement of the
quantity of chemicals added and ratios
of the molecular weights of CO2 and the
makeup chemicals, according to
Equation AA–3 of this section:
44
44 ⎤
⎡
CO 2 = ⎢ M (CaCO 3 ) ∗
+ M ( Na2CO 3 )
∗1000 kg/metric ton
100
105.99 ⎥
⎣
⎦
Where:
CO2 = CO2 mass emissions from makeup
chemicals (kilograms/yr).
M (caCO3) = Make-up quantity of CaCO3 used
for the reporting year (metric tons).
M (NaCO3) = Make-up quantity of Na2CO3
used for the reporting year (metric tons).
44 = Molecular weight of CO2.
180 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.
§ 98.274 Monitoring and QA/QC
requirements.
(a) Each facility subject to this subpart
must quality assure the GHG emissions
data according to the applicable
requirements in § 98.34. All QA/QC data
must be available for inspection upon
request.
(b) High heat values of black liquor
must be determined once per month
using TAPPI Method T 684. The mass
of spent black liquor solids must be
determined once per month using
TAPPI Method T 650. Carbon analyses
for spent pulping liquor must be
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
determined once per month using
ASTM method D5373–08.
(c) Each facility must keep records
that include a detailed explanation of
how company records of measurements
are used to estimate GHG emissions.
The owner or operator must also
document the procedures used to ensure
the accuracy of the measurements of
fuel and makeup chemical usage,
including, but not limited, to calibration
of weighing equipment, fuel flow
meters, and other measurement devices.
The estimated accuracy of
measurements made with these devices
must be recorded and the technical
basis for these estimates must be
provided. The procedures used to
convert spent liquor flow rates to units
of mass (i.e., spent liquor solids firing
rates) also must be documented.
(d) Records must be made available
upon request for verification of the
calculations and measurements.
PO 00000
Frm 00245
Fmt 4701
Sfmt 4702
(Eq. AA-3)
§ 98.275 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions during unit
operation or if a required sample is not
taken), a substitute data value for the
missing parameter shall be used in the
calculations, according to the
requirements of paragraphs (a) through
(c) of this section:
(a) There are no missing data
procedures for measurements of heat
content and carbon content of spent
pulping liquor. A re-test must be
performed if the data from any monthly
measurements are determined to be
invalid.
(b) For missing spent pulping liquor
flow rates, use the lesser value of either
the maximum fuel flow rate for the
combustion unit, or the maximum flow
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.127</MATH>
Where:
Biogenic CO2 = Annual CO2 mass emissions
for spent liquor solids combustion
(metric tons).
(Solids)p = Mass of the spent liquor solids
combusted in month p (metric tons per
month).
(CC)p = Carbon content of the spent liquor
solids, from the fuel analysis results for
the month p (percent by weight,
expressed as a decimal fraction, e.g.,
95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Eq. AA-2)
EP10AP09.126</MATH>
44
∗ (Solids) p ∗ (CC) p
p =1 12
Biogenic CO 2 = ∑
16692
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
rate that the fuel flow meter can
measure.
(c) For the use of makeup chemicals
(carbonates), the substitute data value
shall be the best available estimate of
makeup chemical consumption, based
on available data (e.g., past accounting
records, production rates). The owner or
operator shall document and keep
records of the procedures used for all
such estimates.
§ 98.276
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information in
paragraphs (a) through (e) of this section
for each GHG emission unit listed in
§ 98.270(b).
(a) Annual emissions of CO2, biogenic
CO2, CH4, and N2O presented by
calendar quarter.
(b) Total consumption of all biomass
fuels by calendar quarter.
(c) Total annual quantity of spent
liquor solids fired at the facility by
calendar quarter.
(d) Total annual steam purchases.
(e) Total annual quantities of makeup
chemicals (carbonates) used.
§ 98.277
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the records in paragraphs (a) through (h)
of this section.
(a) GHG emission estimates (including
separate estimates of biogenic CO2) by
calendar quarter for each emissions
source listed under § 98.270(b) of this
subpart.
(b) Monthly total consumption of all
biomass fuels for each biomass
combustion unit.
(c) Monthly analyses of spent pulping
liquor HHV for each chemical recovery
furnace at kraft and soda facilities.
(d) Monthly analyses of spent pulping
liquor carbon content for each chemical
recovery combustion unit at a sulfite or
semichemical pulp facility.
(e) Monthly quantities of spent liquor
solids fired in each chemical recovery
furnace and chemical recovery
combustion unit.
(f) Monthly and annual steam
purchases.
(g) Monthly and annual steam
production for each biomass
combustion unit.
(h) Monthly quantities of makeup
chemicals used.
§ 98.278
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE AA–1 OF SUBPART AA—KRAFT PULPING LIQUOR EMISSIONS FACTORS FOR BIOMASS-BASED CO2, CH4, AND N2O
Biomass-based emissions factors
(kg/mmBtu HHV)
Wood furnish
CO2a
North American Softwood ....................................................................................................................................
North American Hardwood ..................................................................................................................................
Bagasse ...............................................................................................................................................................
Bamboo ................................................................................................................................................................
Straw ....................................................................................................................................................................
a Includes
CH4
94.4
93.7
95.5
93.7
95.1
0.030
N2O
0.005
emissions from both the recovery furnace and pulp mill lime kiln.
TABLE AA–2 OF SUBPART AA—KRAFT LIME KILN AND CALCINER EMISSIONS FACTORS FOR FOSSIL FUEL-BASED CO2,
CH4, AND N2O
Fossil fuel-based emissions factors (kg/mmBtu HHV)
Fuel
Kraft Lime Kilns
CO2
Residual Oil ..............................................................................................
Distillate Oil ..............................................................................................
Natural Gas ..............................................................................................
Biogas ......................................................................................................
Subpart BB—Silicon Carbide
Production
§ 98.280
Definition of the source category.
Silicon carbide production includes
any process that produces silicon
carbide for abrasive purposes.
§ 98.281
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a silicon carbide production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.282
GHGs to report.
(a) You must report CO2 and CH4
process emissions from all silicon
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
76.7
73.5
56.0
0
CH4
N2O
0.0027
................
................
................
0
................
................
................
carbide process units combined, as set
forth in this subpart.
(b) You must report CO2, N2O, and
CH4 emissions from each stationary
combustion unit by following all of the
requirements of subpart C of this part.
§ 98.283
Calculating GHG emissions.
You must determine CO2 emissions in
accordance with the procedures
specified in either paragraph (a) or (b)
of this section.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements of § 98.33(b)(5)(iii)(A), (B),
and (C), you must estimate total CO2
emissions according to the requirements
PO 00000
Frm 00246
Fmt 4701
Sfmt 4702
Kraft Calciners
CO2
76.7
73.5
56.0
0
CH4
0.0027
................
................
................
N2O
0.0003
0.0004
0.0001
0.0001
for the Tier 4 Calculation Methodology
in § 98.33(a)(4).
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must calculate the annual process
CO2 emissions from all silicon carbide
production processes at the facility
combined, using a facility-specific
emission factor according to the
procedures in paragraphs (b)(1) and (2)
of this section.
(1) Use Equation BB–1 of this section
to calculate the facility-specific
emissions factor for determining CO2
emissions. The carbon content must be
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
calculate a quarterly CO2 emisssions
factor:
(assuming 35 percent of carbon input is
in the carbide product).
CCF = Carbon content factor of petroleum
coke from the supplier or as measured by
the applicable method incorporated by
reference in § 98.7.
q
CO 2 = ∑ ⎡Tn ∗ EFCO 2, n ⎤ ∗
⎣
⎦
n =1
q
CH 4 = ∑ [Tn ∗ 10.2] ∗
n =1
Where:
CH4 = Annual CH4 mass emissions (metric
tons CH4, year).
Tn = Petroleum coke consumption in
calendar quarter n (tons coke).
10.2 = CH4 emissions factor (kg CH4/metric
ton coke).
2000/2205 = Conversion factor to convert
tons to metric tons.
0.001 = Conversion factor from kilograms to
metric tons.
q = Number of quarters.
§ 98.284 Monitoring and QA/QC
requirements.
(a) You must determine the quantity
of petroleum coke consumed each
quarter (tons coke/quarter).
(b) For CO2 process emissions, you
must determine the carbon content of
the petroleum coke for four calendar
quarters per year based on reports from
the supplier or by measurement of the
carbon content by an off-site laboratory
using the applicable test method
incorporated by reference in § 98.7.
§ 98.285 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. There are no
missing value provisions for the carbon
content factor or coke consumption. A
re-test must be performed if the data
from the quarterly carbon content
measurements are determined to be
15:41 Apr 09, 2009
Jkt 217001
2000
∗ 0.001
2205
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (e) of this
section.
(a) Annual CO2 and CH4 emissions
from all silicon carbide production
processes combined (in metric tons).
(b) Annual production of silicon
carbide (in metric tons).
(c) Annual capacity of silicon carbide
production (in metric tons).
(d) Annual operating hours.
(e) Quarterly facility-specific emission
factors.
§ 98.287
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (c) of
this section for all silicon carbide
production processes combined.
(a) Annual consumption of petroleum
coke (in metric tons).
(b) Quarterly analyses of carbon
content for consumed coke (averaged to
an annual basis).
(c) Quarterly facility-specific emission
factor calculations.
PO 00000
Frm 00247
Fmt 4701
Sfmt 4702
(c) You must determine annual
process CH4 emissions from all silicon
carbide production processes combined
using Equation BB–3 of this section:
(Eq. BB-3)
unacceptable or not representative of
typical operations.
§ 98.286
(2) Use Equation BB–2 of this section
to calculate CO2 process emissions
(quarterly) from all silicone carbide
production:
(Eq. BB-2)
EFCO2, n = CO2 emissions factor from calendar
quarter n (calculated in Equation BB–1 of
this section).
2000/2205 = Conversion factor to convert
tons to metric tons.
q = Number of quarters.
Where:
CO2 = Annual CO2 mass production
emissions (metric tons CO2/year).
Tn = Petroleum coke consumption in
calendar quarter n (tons coke).
VerDate Nov<24>2008
2000
2205
44/12 = Ratio of molecular weights, CO2 to
carbon.
§ 98.288
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart CC—Soda Ash Manufacturing
§ 98.290
Definition of the source category.
A soda ash manufacturing facility is
any facility with a manufacturing line
that calcines trona to produce soda ash.
§ 98.291
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a soda ash manufacturing
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.292
GHGs to report.
(a) You must report CO2 process
emissions from each soda ash
manufacturing line as required in this
subpart.
(b) You must report the CO2, N2O, and
CH4 emissions from fuel combustion at
each kiln and from each stationary
combustion unit by following the
requirements of subpart C of this part.
§ 98.293
Calculating GHG emissions.
You must determine CO2 emissions in
accordance with the procedures
specified in either paragraph (a) or (b)
of this section.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.130</MATH>
Where:
EFCO2 = CO2 emissions factor (metric tons
CO2/metric ton of petroleum coke
consumed).
0.65 = Adjustment factor for the amount of
carbon in silicon carbide product
(Eq. BB-1)
EP10AP09.129</MATH>
⎛ 44 ⎞
EFCO2 = 0.65 ∗ CCF ∗ ⎜ ⎟
⎝ 12 ⎠
EP10AP09.128</MATH>
determined quarterly and used to
16693
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
n
CO 2 = ∑ E k
Where:
CO2 = Annual process CO2 emissions from
soda ash manufacturing facility (metric
tons/year).
12
CO 2 = ∑
n =1
12
CO 2 = ∑
n =1
Where:
CO2 = Annual CO2 process emissions (metric
tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(ICT)n = Inorganic carbon content in trona
input, from the carbon analysis results
for month n (percent by weight,
expressed as a decimal fraction).
(ICsa)n = Inorganic carbon content in soda ash
output, from the carbon analysis results
for month n (percent by weight,
expressed as a decimal fraction).
(Tt)n = Mass of trona input in month n (tons).
(Tsa)n = Mass of soda ash output in month n
(tons).
2000/2205 = Conversion factor to convert
tons to metric tons.
0.097/1 = Ratio of ton of CO2 emitted for each
ton of trona.
0.138/1 = Ratio of ton of CO2 emitted for each
ton of natural soda ash produced.
(Eq. CC-1)
k =1
44
12
44
12
2000
2205
⎡( ICT )n
⎣
( Tt )n ⎤
⎦
⎡( ICsa )n
⎣
( Tsa )n ⎤
⎦
2000
2205
0.097
1
0.138
1
monthly basis using either belt scales or
by weighing the soda ash at the truck or
rail loadout points of your facility.
(e) You must keep a record of all trona
consumed and soda ash production.
You also must document the procedures
used to ensure the accuracy of the
monthly measurements of trona
consumed soda ash production.
§ 98.295 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. There are no
missing value provisions for the carbon
content of trona or soda ash. A re-test
must be performed if the data from the
daily carbon content measurements are
determined to be unacceptable.
§ 98.294 Monitoring and QA/QC
requirements.
§ 98.296
(a) You must determine the inorganic
carbon content of the trona or soda ash
on a daily basis and determine the
monthly average value for each soda ash
manufacturing line.
(b) If you calculate CO2 process
emissions based on trona input, you
must determine the inorganic carbon
content of the trona using a total organic
carbon analyzer according to the
ultraviolet light/chemical (sodium
persulfate) oxidation method (utilizing
ASTM D4839–03).
(c) If you calculate CO2 process
emissions based on soda ash
production, you must determine the
inorganic carbon content of the soda ash
using ASTM E359–00 (2005). The
inorganic carbon content of soda ash
can be directly expressed as the total
alkalinity of the soda ash.
(d) You must measure the mass of
trona input or soda ash produced by
each soda ash manufacturing line on a
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) through (f) of this
section for each soda ash manufacturing
line.
(a) Annual CO2 process emissions
(metric tons).
(b) Number of soda ash manufacturing
lines.
(c) Annual soda ash production
(metric tons) and annual soda ash
production capacity.
(d) Annual consumption of trona from
monthly measurements (metric tons).
(e) Fractional purity (i.e., inorganic
carbon content) of trona or soda ash (by
daily measurements and by monthly
average) depending on the components
used in Equation CC–2 or CC–3 of this
subpart).
(f) Number of operating hours in
calendar year.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Data reporting requirements.
Frm 00248
Fmt 4701
Sfmt 4702
Ek = Annual CO2 process emissions from
each calciner (kiln), k (in metric tons/
year), using either Equation CC–2 or CC–
3.
n = Number of calciners (kilns) located at the
facility.
(c) Calculate the annual CO2 process
emissions from each kiln using either
Equation CC–2 or CC–3 of this section.
(Eq. CC-2)
(Eq. CC-3)
§ 98.297
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (d)
of this section for each soda ash
manufacturing line.
(a) Monthly production of soda ash
(metric tons).
(b) Monthly consumption of trona
(metric tons).
(c) Daily analyses for inorganic carbon
content of trona or soda ash (as
fractional purity), depending on the
components used in Equation CC–2 or
CC–3 of this subpart.
(d) Number of operating hours in
calendar year.
§ 98.298
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart DD—Sulfur Hexafluoride (SF6)
From Electrical Equipment
§ 98.300
Definition of the source category.
The electric power system source
category includes electric power
transmission and distribution systems
that operate gas-insulated substations,
circuit breakers, other switchgear, gasinsulated lines, or power transformers
containing sulfur-hexafluoride (SF6) or
perfluorocarbons (PFCs).
§ 98.301
Reporting threshold.
You must report GHG emissions from
electric power systems if the total
nameplate capacity of SF6 and PFC
containing equipment in the system
exceeds 17,820 lbs (7,838 kg).
§ 98.302
GHGs to report.
You must report total SF6 and PFC
emissions (including emissions from
fugitive equipment leaks, installation,
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.133</MATH>
determine the total process emissions
from the facility using Equation CC–1 of
this section:
EP10AP09.132</MATH>
(a) Any soda ash manufacturing line
that meets the conditions specified in
§ 98.33(b)(5)(iii)(A),(B), and (C), or
§ 98.33(b)(5)(ii)(A) through (F) shall
calculate total CO2 emissions using a
continuous emissions monitoring
system according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4).
(b) If the facility does not measure
total emissions with a CEMS, you must
EP10AP09.131</MATH>
16694
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.303
(c) Switchgear.
(d) Gas-insulated lines.
(d) Electrical transformers.
User Emissions = ( Decrease in SF6 Inventory ) + ( Acquisitions of SF6 )
− ( Disbursements of SF6 ) − ( Net Increase in Total Nameplate
Capacity of Equipment Operated)
Where:
Decrease in SF6 Inventory = (SF6 stored in
containers, but not in equipment, at the
beginning of the year)—(SF6 stored in
containers, but not in equipment, at the
end of the year).
Acquisitions of SF6 = (SF6 purchased from
chemical producers or distributors in
bulk) + (SF6 purchased from equipment
manufacturers or distributors with or
inside equipment) + (SF6 returned to site
after off-site recycling).
Disbursements of SF6 = (SF6 in bulk and
contained in equipment that is sold to
other entities) + (SF6 returned to
suppliers) + (SF6 sent off site for
recycling) + (SF6 sent to destruction
facilities).
Net Increase in Total Nameplate Capacity of
Equipment Operated = (The Nameplate
Capacity of new equipment)—
(Nameplate Capacity of retiring
equipment). (Note that Nameplate
Capacity refers to the full and proper
charge of equipment rather than to the
actual charge, which may reflect
leakage.)
(b) The mass-balance method in
paragraph (a) of this section shall be
used to estimate emissions of PFCs from
power transformers, substituting the
relevant PFC(s) for SF6 in equation DD–
1.
§ 98.304 Monitoring and QA/QC
requirements.
(a) You must adhere to the following
QA/QC methods for reviewing the
completeness and accuracy of reporting:
(1) Review inputs to Equation DD–1 to
ensure inputs and outputs to the
company’s system are included.
(2) Do not enter negative inputs and
confirm that negative emissions are not
calculated. However, the Decrease in
SF6 Inventory and the Net Increase in
Total Nameplate Capacity may be
calculated as negative numbers.
(3) Ensure that beginning-of-year
inventory matches end-of-year
inventory from the previous year.
(4) Ensure that in addition to SF6
purchased from bulk gas distributors,
SF6 purchased from Original Equipment
Manufacturers (OEM) and SF6 returned
to the facility from off-site recycling are
also accounted for among the total
additions.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(b) Ensure the following QA/QC
methods are employed throughout the
year:
(1) Ensure that cylinders returned to
the gas supplier are consistently
weighed on a scale that is certified to be
accurate and precise to within 1 percent
of the true weight and is periodically
recalibrated per the manufacturer’s
specifications. Either measure residual
gas (the amount of gas remaining in
returned cylinders) or have the gas
supplier measure it. If the gas supplier
weighs the residual gas, obtain from the
gas supplier a detailed monthly
accounting, within 1 percent, of residual
gas amounts in the cylinders returned to
the gas supplier.
(2) Ensure that procedures are in
place and followed to track and weigh
all cylinders as they are leaving and
entering storage. Cylinders shall be
weighed on a scale that is certified to be
accurate to within 1 percent of the true
weight and the scale shall be
recalibrated at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent. All scales used to measure
quantities that are to be reported under
§ 98.306 shall be calibrated using
suitable NIST-traceable standards and
suitable methods published by a
consensus standards organization (e.g.,
ISWM, ISDA, NCWM, or others).
Alternatively, calibration procedures
specified by the scale manufacturer may
be used. Calibration shall be performed
prior to the first reporting year.
(3) Ensure all substations have
provided information to the manager
compiling the emissions report (if it is
not already handled through an
electronic inventory system).
§ 98.305 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Replace
missing data, if needed, based on data
from equipment with a similar
nameplate capacity for SF6 and PFC,
and from similar equipment repair,
PO 00000
Frm 00249
Fmt 4701
Sfmt 4702
Calculating GHG emissions.
(a) For each electric power system,
you must estimate the annual SF6 and
PFC emissions using the mass-balance
approach in Equation DD–1 of this
section:
(Eq. DD-1)
replacement, and maintenance
operations.
§ 98.306
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
for each electric power system, by
chemical:
(a) Nameplate capacity of equipment
containing SF6 and nameplate capacity
of equipment containing each PFC:
(1) Existing as of the beginning of the
year.
(2) New during the year.
(3) Retired during the year.
(b) Transmission miles (length of lines
carrying voltages at or above 34.5 kV).
(c) SF6 and PFC sales and purchases.
(d) SF6 and PFC sent off site for
destruction.
(e) SF6 and PFC sent off site to be
recycled.
(f) SF6 and PFC returned from off site
after recycling.
(g) SF6 and PFC stored in containers
at the beginning and end of the year.
(h) SF6 and PFC with or inside new
equipment purchased in the year.
(i) SF6 and PFC with or inside
equipment sold to other entities.
(j) SF6 and PFC returned to suppliers.
§ 98.307
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
records of the information reported and
listed in § 98.306.
§ 98.308
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart EE—Titanium Dioxide
Production
§ 98.310
Definition of the source category.
The titanium dioxide production
source category consists of facilities that
use the chloride process to produce
titanium dioxide.
§ 98.311
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.134</MATH>
servicing, equipment decommissioning
and disposal, and from storage
cylinders) from the following types of
equipment:
(a) Gas-insulated substations.
(b) Circuit breakers.
16695
16696
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.313
Calculating GHG emissions.
You must determine CO2 emissions
for each process line in accordance with
the procedures specified in either
paragraph (a) or (b) of this section.
(a) If the facility operates and
maintains a continuous emission
monitoring system (CEMS) that meets
the conditions specififed in
§ 98.33(b)(5)(ii) or (iii), then you must
calculate total CO2 emissions using the
Tier 4 Calculation Methodology
specified in § 98.33(a)(4).
(b) If the facility does not measure
total emissions with a CEMS, you must
calculate the process CO2 emissions for
each calcined petroleum coke process
line by determining the mass of calcined
petroleum coke consumed in line. Use
Equation EE–1 of this section to
calculate annual CO2 process emissions
for each process line:
12
Ep = ∑
n =1
44
2000
∗ Cn ∗
12
2205
(Eq. EE-1)
Where:
Ep = Annual CO2 mass emissions from each
chloride process line (metric tons).
Cn = Calcined petroleum coke consumption
in month n, tons.
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion of tons to metric
tons.
(c) You must determine the total CO2
process emissions from the facility
using Equation EE–2 of this section:
n
CO 2 = ∑ E p
(Eq. EE-2)
p −1
Where:
CO2 = Annual CO2 emissions from titanium
dioxide production facility (metric tons/
year).
Ep = Annual CO2 emissions from each
chloride process line, p (in metric tons/
year), determined using Equation EE–1.
n = Number of separate chloride process
lines located at the facility.
(a) You must measure your
consumption of calcined petroleum
coke either by weighing the petroleum
coke fed into your process (by belt
scales or a similar device) or through the
use of purchase records.
(b) You must document the
procedures used to ensure the accuracy
of monthly calcined petroleum coke
consumption.
§ 98.320
§ 98.315 Procedures for estimating
missing data.
There are no missing data procedures
for the measurement of petroleum coke
consumption. A complete record of all
measured parameters used in the GHG
emissions calculations is required.
§ 98.316
§ 98.317
15:41 Apr 09, 2009
Jkt 217001
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the following
records specified in paragraphs (a)
through (e) of this section for each
titanium dioxide production facility.
(a) Monthly production of titanium
dioxide (metric tons).
(b) Production capacity of titanium
dioxide (metric tons).
(c) Records of all calcined petroleum
coke purchases.
(d) Records of monthly calcined
petroleum coke consumption (metric
tons).
(e) Annual operating hours for each
titanium dioxide process line.
§ 98.318
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
C
⎛
CH 4V = n ⎜ V
100%
⎝
VerDate Nov<24>2008
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
specified in paragraphs (a) through (e)
for each titanium dioxide production
line.
(a) Annual CO2 emissions (metric
tons).
(b) Annual consumption of calcined
petroleum coke (metric tons).
(c) Annual production of titanium
dioxide (metric tons).
(d) Annual production capacity of
titanium dioxide (metric tons).
(e) Annual operating hours for each
titanium dioxide process line.
PO 00000
0.0423
Frm 00250
520oR
T
Fmt 4701
§ 98.321
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a underground coal mining
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
§ 98.322
GHGs to report.
You must report the following:
(a) CH4 emissions from each
ventilation well or shaft and each
degasification system (this includes
degasification systems deployed before,
during, or after mining operations are
conducted in a mine area).
(b) CO2 emissions from coal mine gas
CH4 destruction, where the gas is not a
fuel input for energy generation or use.
(c) CO2, CH4, and N2O emissions from
stationary fuel combustion devices. You
must follow the requirements of subpart
C of this part.
§ 98.323
Calculating GHG emissions.
(a) For each ventilation well or shaft,
you must estimate the quarterly CH4
liberated from the mine ventilation
system using the measured CH4 content
and flow rate, and Equation FF–1 of this
section. You must measure CH4 content,
flow rate, temperature, and pressure of
the gas using the procedures outlined in
§ 98.324.
P
0.454 ⎞
1, 440
⎟
1 atm
1, 000 ⎠
Sfmt 4725
Definition of the source category.
(a) This source category consists of
active underground coal mines and any
underground mines under development
that have operational pre-mining
degasification systems. An underground
coal mine is a mine at which coal is
produced by tunneling into the earth to
a subsurface coal seam, where the coal
is then mined with equipment such as
cutting machines, and transported to the
surface. Active underground coal mines
are mines categorized by MSHA as
active and where coal is currently being
produced or has been produced within
the previous 90 days.
(b) This source category comprises the
following emission points:
(1) Each ventilation well or shaft.
(2) Each degasification system well or
shaft, including degasification systems
deployed before, during, or after mining
operations are conducted in a mine area.
(c) This source category does not
include abandoned (closed) mines,
surface coal mines, or post-coal mining
activities.
E:\FR\FM\10APP2.SGM
(Eq. FF-1)
10APP2
EP10AP09.137</MATH>
GHGs to report.
(a) You must report CO2 process
emissions from each chloride process
line as required in this subpart.
(b) Report the CO2, N2O, and CH4
emissions from each stationary
combustion unit. You must follow the
requirements of subpart C of this part.
Subpart FF—Underground Coal Mines
EP10AP09.136</MATH>
§ 98.312
§ 98.314 Monitoring and QA/QC
requirements.
EP10AP09.135</MATH>
contains a titanium dioxide production
process and the facility meets the
requirements of either § 98.2(a)(1) or (2).
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
n = The number of days in the quarter where
active ventilation of mining operations is
taking place.
0.0423 = Density of CH4 at 520 °R (60 °F) and
1 atm (lb/scf).
T = Temperature at which flow is measured
(°R).
P = Pressure at which flow is measured (atm).
1,440 = Conversion factor (min/day).
P
0.454 ⎞
1, 440
⎟
1 atm
1, 000 ⎠
in operation and the continuous
monitoring equipment is properly
functioning (%, wet basis).
n = The number of days in the quarter.
0.0423 = Density of CH4 at 520 °R (60 °F) and
1 atm (lb/scf).
T = Measured average temperature at which
flow is measured (°R).
P = Measured average pressure at which flow
is measured (atm).
1,440 = Conversion factor (min/day).
CH 4 destroyed = CH 4 x DE/100
Where:
CH4 destroyed = Quantity of CH4 liberated
from mine that is destroyed (metric
tons).
CH 4 emitted (net) = CH 4V + CH 4D − CH 4 destroyed
(e) For each degasification or
ventilation system with on-site coal
mine gas CH4 destruction, where the gas
is not a fuel input for energy generation
or use, you must estimate the CO2
emissions using Equation FF–5 of this
section. You must measure the CH4
content and the flow rate according to
the provisions in § 98.324.
CO 2 = CH 4o
44/16
(Eq. FF-5)
Where:
CO2 = Quarterly CO2 emissions from CH4
destruction (metric tons).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
CH4o = CH4 destroyed, calculated using
Equation FF–3 of this section (metric
tons).
DE = Destruction efficiency, based on the
lesser of the manufacturer’s specified
destruction efficiency or 98 percent (%).
44/16 = Ratio of molecular weights of CO2 to
CH4.
§ 98.324 Monitoring and QA/QC
requirements.
(a) The flow and CH4 content of coal
mine gas destroyed must be determined
using ASTM D1945–03 (Reapproved
2006), Standard Test Method for
Analysis of Natural Gas by Gas
Chromatography; ASTM D1946–90
(Reapproved 2006), Standard Practice
for Analysis of Reformed Gas by Gas
Chromatography; ASTM D4891–89
(Reapproved 2006), Standard Test
Method for Heating Value of Gases in
Natural Gas Range by Stoichiometric
Combustion; or UOP539–97 Refinery
Gas Analysis by Gas Chromatography
(incorporated by reference, see § 98.7).
(b) For liberation of methane from
ventilation systems, you must do one of
the following:
PO 00000
Frm 00251
Fmt 4701
Sfmt 4702
0.454/1,000 = Conversion factor (metric ton/
lb).
(c) If gas from degasification system
wells or ventilation shafts is destroyed
you must calculate the quarterly CH4
destroyed using Equation FF–3 of this
section. You must measure CH4 content
and flowrate according to the provisions
in § 98.324.
(Eq. FF-3)
CH4 = Amount of CH4 collected for
destruction(metric tons).
DE = Destruction efficiency of the destruction
equipment, based on the lesser of the
Where:
CH4 emitted (net) = Quarterly CH4 emissions
from mine ventilation and degasification
systems (metric tons).
CH4V = Quarterly CH4 liberated from mine
ventilation systems, calculated using
Equation FF–1 of this section (metric
tons).
CH4D = Quarterly CH4 liberated from mine
degasification systems, calculated using
Equation FF–2 of this section (metric
tons).
CH4 destroyed = Quarterly CH4 destroyed,
calculated using Equation FF–3 of this
section (metric tons).
(Eq. FF-2)
manufacturer’s specified destruction
efficiency or 98 percent (%)’.
(d) You must calculate the quarterly
net CH4 emissions to the atmosphere
using Equation FF–3 of this section.
(Eq. FF-4)
(1) Monitor emissions from each well
or shaft where active ventilation is
taking place by collecting quarterly grab
samples and making quarterly
measurements of flow rate, temperature,
and pressure. The sampling and
measurements must be made at the
same location as MSHA inspection
samples are taken. You must follow
MSHA sampling procedures as set forth
in the MSHA Handbook entitled,
General Coal Mine Inspection
Procedures and Inspection Tracking
System Handbook Number: PH–08–V–1,
January 1, 2008. You must record the
airflow, temperature, and pressure
measured, the hand-held methane and
oxygen readings in percentile, the bottle
number of samples collected, and the
location of the measurement or
collection.
(2) Obtain results of the quarterly
testing performed by MSHA.
(c) For liberation of methane at
degasification systems, you must
monitor methane concentrations and
flow rate from each degasification well
or shaft using any of the oil and gas flow
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.141</MATH>
520oR
T
EP10AP09.140</MATH>
Where:
CH4D = Quarterly CH4 liberated from the
degasification system (metric tons CH4).
V = Measured average volumetric flow rate
for the days in the quarter when the
degasification system is in operation and
the continuous monitoring equipment is
properly functioning (cfm).
C = Estimated or measured average CH4
concentration of gas for the days in the
quarter when the degasification system is
0.0423
(b) For each degasification system,
you must estimate the quarterly CH4
liberated from the mine degasification
system using measured CH4 content,
flow rate, temperature, and pressure,
and Equation FF–2 of this section.
EP10AP09.139</MATH>
C
⎛
CH 4D = n ⎜ V
100%
⎝
0.454/1,000 = Conversion factor (metric ton/
lb).
EP10AP09.138</MATH>
Where:
CH4V = Quarterly CH4 liberated from
ventilation systems (metric tons CH4).
V = Measured volumetric flow rate of active
ventilation of mining operations (cfm).
C = Measured CH4 concentration of
ventilation gas during active ventilation
of mining operations (%, wet basis).
16697
16698
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
meter test methods incorporated by
reference in § 98.7.
(d) All fuel flow meters and gas
composition monitors monitors shall be
calibrated prior to the first reporting
year, using a suitable method published
by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, MSHA,
or others). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Fuel flow
meters, and gas composition monitors
shall be recalibrated either annually or
at the minimum frequency specified by
the manufacturer or other applicable
standards.
(e) All temperature and pressure
monitors must be calibrated using the
procedures and frequencies specified by
the manufacturer.
(f) If applicable, the owner or operator
shall document the procedures used to
ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure
measurements. These procedures
include, but are not limited to,
calibration of fuel flow meters, and
other measurement devices. The
estimated accuracy of measurements,
and the technical basis for the estimated
accuracy shall be recorded.
§ 98.325 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter 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, in accordance with
paragraph (b) of this section.
(b) For each missing value of CH4
concentration, flow rate, temperature,
and pressure for ventilation and
degasification systems, the substitute
data value shall be the arithmetic
average of the quality-assured values of
that parameter immediately preceding
and immediately following the missing
data incident. 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.
§ 98.326
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
for each mine:
(a) Quarterly volumetric flow rate
measurement results for all ventilation
systems, including date and location of
measurement.
(b) Quarterly CH4 concentration
measurement results for all ventilation
systems, including date and location of
measurement.
(c) Quarterly CEMS volumetric flow
data used to calculate CH4 liberated
from degasification systems (summed
from daily data).
(d) Quarterly CEMS CH4
concentration data used to calculate CH4
liberated from degasification systems
(average from daily data).
(e) Quarterly CH4 destruction at
ventilation and degasification systems.
(f) Dates in reporting period where
active ventilation of mining operations
is taking place.
(g) Dates in reporting period when
continuous monitoring equipment is not
properly functioning.
(h) Quarterly averages of temperatures
and pressures at the time and at the
conditions for which all measurements
are made.
(i) Quarterly CH4 liberated from each
ventilation well or shaft, and from each
degasification system (this includes
degasification systems deployed before,
during, or after mining operations are
conducted in a mine area).
(j) Quarterly CH4 emissions (net) from
each ventilation well or shaft, and from
each degasification system (this
includes degasification systems
deployed before, during, or after mining
operations are conducted in a mine
area).
(k) Quarterly CO2 emissions from onsite destruction of coal mine gas CH4,
where the gas is not a fuel input for
energy generation or use.
§ 98.327
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the following records:
(a) Calibration records for all
monitoring equipment.
(b) Records of gas sales.
(c) Logbooks of parameter
measurements.
(d) Laboratory analyses of samples.
§ 98.328
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart GG—Zinc Production
§ 98.330
Definition of the source category.
The zinc production source category
consists of zinc smelters and secondary
zinc recycling facilities.
§ 98.331
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a zinc production process and
the facility meets the requirements of
either § 98.2(a)(1) or (2).
§ 98.332
GHGs to report.
(a) You must report the CO2 process
emissions from each Waelz kiln and
electrothermic furnace used for zinc
production, as applicable to your
facility.
(a) You must report the CO2, CH4, and
N2O emissions from each stationary
combustion unit, following
requirements of subpart C of this part.
§ 98.333
Calculating GHG emissions.
(a) If you operate and maintain a
CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must estimate total CO2 emissions
according to the requirements in
§ 98.33(a).
(b) If you do not operate and maintain
a CEMS that measures total CO2
emissions consistent with the
requirements in subpart C of this part,
you must determine the total CO2
emissions from the Waelz kilns or
electrothermic furnaces at your facility
used for zinc production using the
procedures specified in paragraphs
(b)(1) and (2) of this section.
(1) For each Waelz kiln or
electrothermic furnace at your facility
used for zinc production, you must
determine the mass of carbon in each
carbon-containing material, other than
fuel, that is fed, charged, or otherwise
introduced into each Waelz kiln and
electrothermic furnace at your facility
for each calendar month and estimate
total annual CO2 process emissions from
each affected unit at your facility using
Equation GG–1. For electrothermic
furnaces, carbon containing input
materials include carbon eletrodes and
carbonaceous reducing agents. For
Waelz kilns, carbon containing input
materials include carbonaceous
reducing agents.
12
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00252
Fmt 4701
Sfmt 4725
E:\FR\FM\10APP2.SGM
10APP2
(Eq. GG-1)
EP10AP09.142</MATH>
44
∗ ⎡( Zinc )n ∗ ( CZinc )n + ( Flux) n ∗ (CFlux ) n + ( Electrode) n ∗ ( CElectrode )n + (Carbon) n ∗ ( Cc ) ⎤
⎦
12 ⎣
n =1
E CO2 = ∑
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(2) You must determine the total CO2
emissions from the Waelz kilns or
electrothermic furnaces at your facility
using Equation GG–2 of this section.
k
CO 2 = ∑ E CO 2k
(Eq. GG-2)
1
Where:
CO2 = Total annual CO2 emissions, metric
tons/year.
ECO2k = Annual CO2 emissions from Waelz
kiln or electrothermic furnace k
calculated using Equation GG–1 of this
section, metric tons/year.
k = Total number of Waelz kilns or
electrothermic furnaces at facility used
for the zinc production.
§ 98.334 Monitoring and QA/QC
requirements.
If you determine CO2 emissions using
the carbon input procedure in
§ 98.333(b)(1), you must meet the
requirements specified in paragraphs (a)
through (c) of this section.
(a) Determine the mass of each solid
carbon-containing input material by
direct measurement of the quantity of
the material placed in the unit or by
calculations using process operating
information, and record the total mass
for the material for each calendar
month.
(b) For each input material identified
in paragraph (a) of this section, you
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
must determine the average carbon
content of the material for each calendar
month using information provided by
your material supplier or by collecting
and analyzing a representative sample
of the material using an analysis method
appropriate for the material.
(c) For each input material identified
in paragraph (a) of this section for
which the carbon content is not
provided by your material supplier, the
carbon content of the material must be
analyzed by an independent certified
laboratory each calendar month using
the test methods (and their QA/QC
procedures) in § 98.7. Use ASTM
E1941–04 (‘‘Standard Test Method for
Determination of Carbon in Refractory
and Reactive Metals and Their Alloys’’)
for analysis of zinc bearing materials;
ASTM D5373–02 (‘‘Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke’’)
for analysis of carbonaceous reducing
agents and carbon electrodes, and
ASTM C25–06 (‘‘Standard Test Methods
for Chemical Analysis of Limestone,
Quicklime, and Hydrated Lime’’) for
analysis of flux materials such as
limestone or dolomite.
§ 98.335 Procedures for estimating
missing data.
For the carbon input procedure in
§ 98.333(b), a complete record of all
measured parameters used in the GHG
emissions calculations is required (e.g.,
raw materials carbon content values,
etc.). Therefore, whenever a qualityassured value of a required parameter is
unavailable, a substitute data value for
the missing parameter shall be used in
the calculations.
(a) For each missing value of the
carbon content the substitute data value
shall be the arithmetic average of the
quality-assured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
(b) For missing records of the mass of
carbon-containing input material
consumption, the substitute data value
shall be the best available estimate of
the mass of the input material. The
owner or operator shall document and
keep records of the procedures used for
all such estimates.
§ 98.336
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
PO 00000
Frm 00253
Fmt 4701
Sfmt 4702
in paragraphs (a) through (e) of this
section for each Waelz kiln or
electrothermic furnace.
(a) Annual CO2 emissions in metric
tons, and the method used to estimate
emissions.
(b) Annual zinc product production
capacity (in metric tons).
(c) Total number of Waelz kilns and
electrothermic furnaces at the facility.
(d) Number of facility operating hours
in calendar year.
(e) If you use the carbon input
procedure, report for each carboncontaining input material consumed or
used (other than fuel), the information
specified in paragraphs (e)(1) and (2) of
this section.
(1) Annual material quantity (in
metric tons).
(2) Annual average of the monthly
carbon content determinations for each
material and the method used for the
determination (e.g., supplier provided
information, analyses of representative
samples you collected).
§ 98.337
Records that must be retained.
In addition to the records required by
§ 98.3(g) of subpart A of this part, you
must retain the records specified in
paragraphs (a) through (d) of this
section.
(a) Monthly facility production
quantity for each zinc product (in metric
tons).
(b) Number of facility operating hours
each month.
(c) Annual production Quantity for
each zinc product (in metric tons).
(d) If you use the carbon input
procedure, record for each carboncontaining input material consumed or
used (other than fuel), the information
specified in paragraphs (d)(1) and (2) of
this section.
(1) Monthly material quantity (in
metric tons).
(2) Monthly average carbon content
determined for material and records of
the supplier provided information or
analyses used for the determination.
(e) You must keep records that
include a detailed explanation of how
company records of measurements are
used to estimate the carbon input to
each Waelz kiln or electrothermic
furnace, as applicable to your facility.
You also must document the procedures
used to ensure the accuracy of the
measurements of materials fed, charged,
or placed in an affected unit including,
but not limited to, calibration of
weighing equipment and other
measurement devices. The estimated
accuracy of measurements made with
these devices must also be recorded,
and the technical basis for these
estimates must be provided.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.143</MATH>
Where:
ECO2 = Total CO2 process emissions from an
individual Waelz kiln or electrothermic
furnace (metric tons per year).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Zinc)n = Mass of zinc bearing material
charged to the furnace in month ‘‘n’’
(metric tons).
(CZinc)n = Carbon content of the zinc bearing
material, from the carbon analysis results
for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace in month ‘‘n’’ (metric tons).
(CFlux)n = Average carbon content of the flux
materials, from the carbon analysis
results for month ‘‘n’’ (percent by weight,
expressed as a decimal fraction).
(Electrode)n = Mass of carbon electrode
consumed in month ‘‘n’’, for
electrothermic furnace (metric tons).
(CElectrode)n = Average carbon content of the
carbon electrode, from the carbon
analysis results for month ‘‘n’’, for
electrothermic furnace (percent by
weight, expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials
(e.g., coal, coke) charged to the furnace
in month ‘‘n’’ (metric tons).
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon
analysis results for month ‘‘n’’ (percent
by weight, expressed as a decimal
fraction).
16699
16700
Subpart HH—Landfills
§ 98.340
Definition of the source category.
(a) This source category consists of
the following sources at municipal solid
waste (MSW) landfill facilities: landfills,
landfill gas collection systems, and
landfill gas combustion systems
(including flares). This source category
also includes industrial landfills
(including, but not limited to landfills
located at food processing, pulp and
paper, and ethanol production
facilities).
§ 98.341
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a landfill process and the
facility meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.342
GHGs to report.
(a) You must report CH4 generation
and CH4 emissions from landfills.
(b) You must report CH4 destruction
resulting from landfill gas collection
and combustion systems.
(c) You must report CO2, CH4, and
N2O emissions from stationary fuel
combustion devices. This includes
⎡ T −1
⎤
GCH 4 = ⎢ ∑ Wx L0, x e − k (T − x −1) − e − k (T − x ) ⎥
⎣ x=S
⎦
{
Where:
GCH4 = Modeled methane generation rate in
reporting year T (metric tons CH4).
X = Year in which waste was disposed.
S = Start year of calculation. Use the year 50
years prior to the year of the emissions
estimate, or the opening year of the
landfill, whichever is more recent.
T = Reporting year for which emissions are
calculated.
Wx = Quantity of waste disposed in the
landfill in year X from tipping fee
receipts or other company records
(metric tons, as received (wet weight)).
L0 = CH4 generation potential (metric tons
CH4/metric ton waste) =
MCF*DOC*DOCF*F*16/12.
MCF = Methane correction factor (fraction).
DOC = Degradable organic carbon [fraction
(metric tons C/metric ton waste)].
DOCF = Fraction of DOC dissimilated
(fraction).
F = Fraction by volume of CH4 in landfill gas.
k = Rate constant (yr-1).
(2) For years when material-specific
waste quantity data are available, and
for industrial waste landfills, apply
Equation HH–1 of this section for each
waste quantity type and sum the CH4
generation rates for all waste types to
calculate the total modeled CH4
generation rate for the landfill. Use the
appropriate parameter values for k,
DOC, MCF, DOCF, and F shown in Table
HH–1. The annual quantity of each type
of waste disposed must be calculated as
the sum of the daily quantities of waste
(of that type) disposed. For both MSW
and industrial landfills, you may use the
bulk waste parameters for a portion of
your waste materials when using the
material-specific modeling approach for
mixed waste streams that cannot be
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
)}
(
(Eq. HH-2)
Where:
WDF = Average waste disposal factor
determined on the first year of reporting
(metric tons per production unit). The
average waste disposal factor should not
PO 00000
Frm 00254
Fmt 4701
Sfmt 4702
§ 98.343
Calculating GHG emissions.
(a) For all landfills subject to the
reporting requirements of this subpart,
calculate annual modeled CH4
generation according to the applicable
requirements in paragraphs (a)(1)
through (4) of this section.
(1) Calculate annual modeled CH4
generation using recorded or estimated
waste disposal quantities, default values
from Table HH–1, and Equation HH–1
of this section.
(Eq. HH-1)
designated to a specific material type.
For years when waste composition data
are not available, use the bulk waste
parameter values for k and L0 in Table
HH–1 of this subpart for the total
quantity of waste disposed in those
years.
(3) For years prior to reporting for
which waste disposal quantities are not
readily available for MSW landfills, Wx
shall be estimated using the estimated
population served by the landfill in
each year, the values for national
average per capita waste disposal and
fraction of generated waste disposed of
in solid waste disposal sites found in
Table HH–2 of this subpart.
(4) For industrial landfills, Wx in
reporting years must be determined by
direct mass measurement of waste
entering the landfill using industrial
scales with a manufacturer’s stated
accuracy of ±2 percent. For previous
years, where data are unavailable on
waste disposal quantities, estimate the
waste quantities according to the
requirements in paragraphs (a)(4)(i) and
(ii) of this section.
(i) Calculate the average waste
disposal rate per unit of production for
the first applicable reporting year using
Equation HH–2 of this section.
⎡ N ⎧ W ⎫⎤
WDF = ⎢ ∑ ⎨ n ⎬⎥
⎢
⎥
⎣ n =1 ⎩ N ∗ Pn ⎭⎦
emissions from the combustion of fuels
used in flares (e.g., for pilot gas or to
supplement the heating value of the
landfill gas). Follow the requirements of
subpart C of this part. Do not calculate
CO2 emissions resulting from the flaring
of landfill gas.
be re-calculated in subsequent reporting
years.
N = Number of years for which disposal and
production data are available.
Wn = Quantity of waste placed in the
industrial landfill in year n (metric tons).
Pn = Quantity of product produced in year n
(production units).
(ii) Calculate the waste disposal
quantities for historic years in which
direct waste disposal measurements are
not available using historical production
data and Equation HH–3 of this section.
Wx = WDF ∗ Px
(Eq. HH-3)
Where:
X = Historic year in which waste was
disposed.
Wx = Projected quantity of waste placed in
the landfill in year X (metric tons).
WDF = Average waste disposal factor from
Equation HH–1 of this section (metric
tons per production unit).
Px = Production quantity for the facility in
year X from company records
(production units).
(b) For landfills with gas collection
systems, calculate the quantity of CH4
destroyed according to the requirements
in paragraphs (b)(1) through (4) of this
section.
(1) Measure continuously the flow
rate, CH4 concentration, temperature,
and pressure, of the collected landfill
gas (before any treatment equipment)
using a monitoring meter specifically for
CH4 gas, as specified in § 98.344.
(2) Calculate the quantity of CH4
recovered for destruction using
Equation HH–4 of this section.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.146</MATH>
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
(b) This source category does not
include hazardous waste landfills and
construction and demolition landfills.
EP10AP09.145</MATH>
Definitions.
EP10AP09.144</MATH>
§ 98.338
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
365
⎛
Cn
P
520oR
0.454 ⎞
R = ∑ ⎜ Vn ∗
∗ 0.0423 ∗
∗ n ∗ 1, 440 ∗
⎟
100%
Tn
1 atm
1, 000 ⎠
n =1 ⎝
MG = G CH 4
(1 − OX)
Emissions = ⎡( G CH 4 − R ) ∗ (1 − OX ) + R
⎣
(1 − DE )⎤
⎦
§ 98.344 Monitoring and QA/QC
requirements.
(a) The quantity of waste landfilled
must be determined using mass
measurement equipment meeting the
requirements for commercial weighing
equipment as described in
‘‘Specifications, Tolerances, and Other
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. HH-6)
R = Quantity of recovered CH4 from Equation
HH–4 of this section (metric tons).
OX = Oxidation fraction default rate is 0.1
(10%).
DE = Destruction efficiency (lesser of
manufacturer’s specified destruction
efficiency and 0.99)
and estimated gas collection efficiency
and Equations HH–7 and HH–8, of this
section.
MG =
R
CE
(1 − OX)
(Eq. HH-7)
(ii) Calculate CH4 generation and CH4
emissions using measured CH4 recovery
⎥
⎦
Technical Requirements For Weighing
and Measuring Devices’’ NIST
Handbook 44, 2008.
(b) The quantity of landfill gas CH4
destroyed must be determined using
ASTM D1945–03 (Reapproved 2006),
Standard Test Method for Analysis of
Natural Gas by Gas Chromatography;
ASTM D1946–90 (Reapproved 2006),
Standard Practice for Analysis of
Reformed Gas by Gas Chromatography;
ASTM D4891–89 (Reapproved 2006),
Standard Test Method for Heating Value
of Gases in Natural Gas Range by
Stoichiometric Combustion; or
UOP539–97 Refinery Gas Analysis by
Gas Chromatography (incorporated by
reference, see § 98.7).
(c) All fuel flow meters and gas
composition monitors shall be
calibrated prior to the first reporting
year, using ASTM D1945–03
(Reapproved 2006), Standard Test
Method for Analysis of Natural Gas by
PO 00000
Frm 00255
Fmt 4701
Sfmt 4702
(Eq. HH-8)
Gas Chromatography; ASTM D1946–90
(Reapproved 2006), Standard Practice
for Analysis of Reformed Gas by Gas
Chromatography; ASTM D4891–89
(Reapproved 2006), Standard Test
Method for Heating Value of Gases in
Natural Gas Range by Stoichiometric
Combustion; or UOP539–97 Refinery
Gas Analysis by Gas Chromatography
(incorporated by reference, see § 98.7).
Alternatively, calibration procedures
specified by the flow meter
manufacturer may be used. Fuel flow
meters, and gas composition monitors
shall be recalibrated either annually or
at the minimum frequency specified by
the manufacturer.
(d) All temperature and pressure
monitors must be calibrated using the
procedures and frequencies specified by
the manufacturer.
(e) The owner or operator shall
document the procedures used to ensure
the accuracy of the estimates of disposal
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.151</MATH>
⎤
(1 − DE )⎥
EP10AP09.150</MATH>
⎡⎛ R
⎞
Emissions = ⎢⎜
− R ⎟ ∗ (1 − OX ) + R
⎢
⎠
⎣⎝ CE CH 4
Where:
MG = Methane generation from the landfill
in the reporting year (metric tons CH4).
Emissions = Methane emissions from the
landfill in the reporting year (metric tons
CH4).
R = Quantity of recovered CH4 from Equation
HH–4 of this section (metric tons CH4).
CE = Collection efficiency estimated at
landfill, taking into account system
coverage, operation, and cover system
materials. (Default is 0.75).
OX = Oxidation fraction (default rate is 0.1
(10%)).
DE = Destruction efficiency, (lesser of
manufacturer’s specified destruction
efficiency and 0.99).
(2) For landfills that do not have
landfill gas collection systems, the CH4
emissions are equal to the CH4
generation calculated in Equation HH–
5 of this section.
(3) For landfills with landfill gas
collection systems, calculate CH4
emissions using the methodologies
specified in paragraphs (c)(3)(i) and (ii)
of this section.
(i) Calculate CH4 emissions from the
modeled CH4 generation and measured
CH4 recovery using Equation HH–6 of
this section.
EP10AP09.149</MATH>
Where:
Emissions = Methane emissions from the
landfill in the reporting year (metric tons
CH4).
GCH4 = Modeled methane generation rate in
reporting year from Equation HH–1 of
this section or the quantity of recovered
CH4 from Equation HH–4 of this section,
whichever is greater (metric tons CH4).
(Eq. HH-5)
Where:
MG = Methane generation from the landfill
in the reporting year, adjusted for
oxidation (metric tons CH4).
GCH4 = Modeled methane generation rate in
reporting year from Equation HH–1 of
this section (metric tons CH4).
OX = Oxidation fraction default rate is 0.1
(10%).
EP10AP09.148</MATH>
(c) Calculate CH4 generation (adjusted
for oxidation in cover materials) and
actual CH4 emissions (taking into
account any CH4 recovery, and
oxidation in cover materials) according
to the applicable methods in paragraphs
(d)(1) through (4) of this section.
(1) Calculate CH4 generation, adjusted
for oxidation, from the modeled CH4
(GCH4 from Equation HH–1) using
Equation HH–5 of this section.
(Eq. HH-4)
EP10AP09.147</MATH>
Where:
R = Annual quantity of recovered CH4 (metric
tons CH4).
Vn = Daily average volumetric flow rate for
day n (acfm).
Cn = Daily average CH4 concentration of
landfill gas for day n (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520°R or
60°F and 1 atm).
Tn = Temperature at which flow is measured
for day n (°R).
Pn = Pressure at which flow is measured for
day n (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/
lb).
16701
16702
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
quantities and, if applicable, gas flow
rate, gas composition, temperature, and
pressure measurements. These
procedures include, but are not limited
to, calibration of weighing equipment,
fuel 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.
§ 98.345 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter 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, according to the
requirements in paragraphs (a) through
(c) of this section.
(a) For each missing value of the CH4
content, the substitute data value shall
be the arithmetic average of the qualityassured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
(b) For missing gas flow rates, the
substitute data value shall be the
arithmetic average of the quality-assured
values of that parameter immediately
preceding and immediately following
the missing data incident. 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.
(c) For missing daily waste disposal
data for disposal in reporting years, the
substitute value shall be the average
daily waste disposal quantity for that
day of the week as measured on the
week before and week after the missing
daily data.
§ 98.346
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
for each landfill.
(a) Waste disposal for each year of
landfilling.
(b) Method for estimating waste
disposal.
(c) Waste composition, if available, in
percentage categorized as—
(1) Municipal,
(2) Construction and demolition,
(3) Biosolids or biological sludges,
(4) Industrial, inorganic,
(5) Industrial, organic,
(6) Other, or more refined categories,
such as those for which k rates are
available in Table HH–1 of this subpart.
(d) Method for estimating waste
composition.
(e) Fraction of CH4 in landfill gas
based on measured values if the landfill
has a gas collection system or a default.
(f) Oxidation fraction used in the
calculations.
(g) Degradable organic carbon (DOC)
used in the calculations.
(h) Decay rate k used in the
calculations.
(i) Fraction of DOC dissimilated used
in the calculations.
(j) Methane correction factor used in
the calculations.
(k) Annual methane generation and
methane emissions (metric tons/year)
according to the methodologies in
§ 98.343(c)(1) through (3). Landfills with
gas collection system must separately
report methane generation and
emissions according to the
methodologies in § 98.343(c)(3)(i) and
(ii) and indicate which values are
calculated using the methodologies in
§ 98.343(c)(ii).
(l) Landfill design capacity.
(m) Estimated year of landfill closure.
(n) Total volumetric flow of landfill
gas for landfills with gas collection
systems.
(o) CH4 concentration of landfill gas
for landfills with gas collection systems.
(p) Monthly average temperature at
which flow is measured for landfills
with gas collection systems.
(q) Monthly average pressure at which
flow is measured for landfills with gas
collection systems.
(r) Destruction efficiency used for
landfills with gas collection systems.
(s) Methane destruction for landfills
with gas collection systems (total
annual, metric tons/year).
(t) Estimated gas collection system
efficiency for landfills with gas
collection systems.
(u) Methodology for estimating gas
collection system efficiency for landfills
with gas collection systems.
(v) Cover system description.
(w) Number of wells in gas collection
system.
(x) Acreage and quantity of waste
covered by intermediate cap.
(y) Acreage and quantity of waste
covered by final cap.
(z) Total CH4 generation from
landfills.
(aa) Total CH4 emissions from
landfills.
§ 98.347
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the calibration records for all
monitoring equipment.
§ 98.348
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE HH–1 OF SUBPART HH—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS
Factor
Default value
Units
Waste model—bulk waste option
k (precipitation <20 inches/year) ........................
k (precipitation 20–40 inches/year) ....................
k (precipitation >40 inches/year) ........................
L0 (Equivalent to DOC = 0.2028 when MCF=1,
DOCF=0.5, and F=0.5).
0.02 ..................................................................
0.038 ................................................................
0.057 ................................................................
0.067 ................................................................
yr¥1
yr¥1
yr¥1
metric tons CH4/ metric ton waste.
Waste model—All MSW and industrial waste landfills
MCF ....................................................................
DOCF ..................................................................
F .........................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
1 .......................................................................
0.5 ....................................................................
0.5 ....................................................................
PO 00000
Frm 00256
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16703
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE HH–1 OF SUBPART HH—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued
Factor
Default value
Units
Waste model—MSW using waste composition option
DOC (food waste) ..............................................
DOC (garden) .....................................................
DOC (paper) .......................................................
DOC (wood and straw) .......................................
DOC (textiles) .....................................................
DOC (diapers) ....................................................
DOC (sewage sludge) ........................................
DOC (bulk waste) ...............................................
k (food waste) .....................................................
k (garden) ...........................................................
k (paper) .............................................................
k (wood and straw) .............................................
k (textiles) ...........................................................
k (diapers) ..........................................................
k (sewage sludge) ..............................................
0.15 ..................................................................
0.2 ....................................................................
0.4 ....................................................................
0.43 ..................................................................
0.24 ..................................................................
0.24 ..................................................................
0.05 ..................................................................
0.20 ..................................................................
0.06 to 0.185 a ..................................................
0.05 to 0.10 a ....................................................
0.04 to 0.06 a ....................................................
0.02 to 0.03 a ....................................................
0.04 to 0.06 a ....................................................
0.05 to 0.10 a ....................................................
0.06 to 0.185 a ..................................................
Weight
Weight
Weight
Weight
Weight
Weight
Weight
Weight
yr¥1
yr¥1
yr¥1
yr¥1
yr¥1
yr¥1
yr¥1
fraction,
fraction,
fraction,
fraction,
fraction,
fraction,
fraction,
fraction,
wet
wet
wet
wet
wet
wet
wet
wet
basis.
basis.
basis.
basis.
basis.
basis.
basis.
basis.
Waste model—Industrial waste landfills
DOC (food processing) ......................................
DOC (pulp and paper) ........................................
k (food processing) .............................................
k (pulp and paper) ..............................................
0.15 ..................................................................
0.2 ....................................................................
0.185 ................................................................
0.06 ..................................................................
Weight fraction, wet basis.
Weight fraction, wet basis.
yr¥1
yr¥1
Calculating methane generation and emissions
OX ......................................................................
DE .......................................................................
0.1.
0.99.
a Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and the greater value when it
does not.
TABLE HH–2 OF SUBPART HH—U.S. PER CAPITA WASTE DISPOSAL RATES
Waste per
capita ton/cap/
yr
Year
1940
1941
1942
1943
1944
1945
1946
1947
1948
1949
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00257
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
0.64
0.64
0.64
0.64
0.63
0.64
0.64
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.63
0.64
0.64
0.65
0.65
0.66
0.66
0.67
0.68
0.68
0.69
0.69
0.70
0.71
% to SWDS
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
16704
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE HH–2 OF SUBPART HH—U.S. PER CAPITA WASTE DISPOSAL RATES—Continued
Waste per
capita ton/cap/
yr
Year
1974
1975
1976
1977
1978
1979
1980
1981
1982
1983
1984
1985
1986
1987
1988
1989
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
§ 98.351
Subpart II—Wastewater Treatment
§ 98.350
Definition of source category.
(a) A wastewater treatment system is
the collection of all processes that treat
or remove pollutants and contaminants,
such as soluble organic matter,
suspended solids, pathogenic
organisms, and chemicals from waters
released from industrial processes. This
source category applies to on-site
wastewater treatment systems at pulp
and paper mills, food processing plants,
ethanol production plants,
petrochemical facilities, and petroleum
refining facilities.
(b) This source category does not
include centralized domestic
wastewater treatment plants.
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a wastewater treatment process
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.352
GHGs to report.
(a) You must report annual CH4
emissions from anaerobic wastewater
treatment processes.
(b) You must report annual CO2
emissions from oil/water separators at
petroleum refineries.
(c) You must report CO2, CH4, and
N2O emissions from the combustion of
fuels in stationary combustion devices
and fuels used in flares by following the
requirements of subpart C of this part.
% to SWDS
0.71
0.72
0.73
0.73
0.74
0.75
0.75
0.76
0.77
0.77
0.78
0.79
0.79
0.80
0.80
0.85
0.84
0.78
0.76
0.78
0.77
0.72
0.71
0.72
0.78
0.78
0.84
0.95
1.06
1.06
1.06
1.06
1.06
100
100
100
100
100
100
100
100
100
100
100
100
100
100
100
84
77
76
72
71
67
63
62
61
61
60
61
63
66
65
64
64
64
For flares, calculate the CO2 emissions
only from pilot gas and other auxiliary
fuels combusted in the flare, as
specified in subpart C of this part. Do
not include CO2 emissions resulting
from the combustion of anaerobic
digester gas.
§ 98.353
Calculating GHG emissions.
(a) Estimate the annual CH4 mass
emissions from systems other than
digesters using Equation II–1 of this
section. The value of flow and COD
must be determined in accordance with
the monitoring requirements specified
in § 98.354. The flow and COD should
reflect the wastewater treated
anaerobically on site in anaerobic
systems such as lagoons.
12
CH 4 = ∑ [ Flow n ∗ COD ∗ Bo ∗ MCF ∗ 0.001]
(Eq. II-1)
Where:
CH4 = Annual CH4 mass emissions from the
wastewater treatment system (metric
tons).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Flown = Volumetric flow rate of wastewater
sent to an anaerobic treatment system in
month n (m3/month).
COD = Average monthly value for chemical
oxygen demand of wastewater entering
PO 00000
Frm 00258
Fmt 4701
Sfmt 4702
anaerobic treatment systems other than
digesters (kg/m3).
B0 = Maximum CH4 producing potential of
wastewater (kg CH4/kg COD), default is
0.25.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.152</MATH>
n =1
16705
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(b) For each petroleum refining
facility having an on-site oil/water
separator, estimate the annual CO2 mass
emissions using Equation II–2 using
measured values for the volume of
wastewater treated, and default values
for emission factors by separator type
from Table II–1 of this subpart. The flow
should reflect the wastewater treated in
the oil/water separator.
12
44
⎡
⎤
CO 2 = ∑ ⎢ EFsep ∗ VH2O ∗ C ∗ ∗ 0.001 metric tons CH 4 / kg ⎥
12
⎦
n =1 ⎣
Cn
100%
(c) For each anaerobic digester,
estimate the annual mass of CH4
destroyed using Equations II–3 and II–
4 of this section.
CH 4 d = CH 4 AD ∗ DE
0.0423
Where:
CH4AD = Annual quantity of CH4 generated
by anaerobic digestion (metric tons CH4/
yr).
Vn = Daily average volumetric flow rate for
day n, as determined from daily
monitoring specified in § 98.354 (acfm).
Cn = Daily average CH4 concentration of
digester gas for day n, as determined
from daily monitoring specified in
§ 98.354 (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 °R or
60 °F and 1 atm).
Tn = Temperature at which flow is measured
for day n (°R).
Pn = Pressure at which flow is measured for
day n (atm).
§ 98.354 Monitoring and QA/QC
requirements.
(a) The quantity of COD treated
anaerobically must be determined using
analytical methods for industrial
wastewater pollutants and must be
conducted in accordance with the
methods specified in 40 CFR part 136.
(b) All flow meters must be calibrated
using the procedures and frequencies
specified by the device manufacturer.
(c) For anaerobic treatment systems,
facilities must monitor the wastewater
flow and COD no less than once per
week. The sample location must
represent the influent to anaerobic
treatment for the time period that is
monitored. The flow sample must
correspond to the location used to
measure the COD. Facilities must collect
24-hour flow-weighted composite
samples, unless they can demonstrate
that the COD concentration and
wastewater flow into the anaerobic
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
520 R
Tn
(Eq. II-3)
Pn
1, 440 minutes/day
1 atm
treatment system does not vary. In this
case, facilities must collect 24-hour
time-weighted composites to
characterize changes in wastewater due
to production fluctuations, or a grab
sample if the influent flow is equalized
resulting in little variability.
(d) For oil/water separators, facilities
must monitor the flow no less than once
per week. The sample location must
represent the influent to oil/water
separator for the time period that is
monitored.
(e) The quantity of gas destroyed must
be determined using any of the oil and
gas flow meter test methods
incorporated by reference in § 98.7.
(f) All gas flow meters and gas
composition monitors shall be
calibrated prior to the first reporting
year, using a suitable method published
by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, or
others). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Gas flow
meters and gas composition monitors
shall be recalibrated either annually or
at the minimum frequency specified by
the manufacturer.
(g) All temperature and pressure
monitors must be calibrated using the
procedures and frequencies specified by
the device manufacturer.
(h) All equipment (temperature and
pressure monitors and gas flow meters
and gas composition monitors) shall be
maintained as specified by the
manufacturer.
PO 00000
Frm 00259
Fmt 4701
Sfmt 4702
Where:
CH4d = Annual quantity of CH4 destroyed
(kg/yr).
CH4AD = Annual quantity of CH4 generated
by anaerobic digester, as calculated in
Equation II–4 of this section (metric tons
CH4).
DE = CH4 destruction efficiency from flaring
or burning in engine (lesser of
manufacturer’s specified destruction
efficiency and 0.99).
0.454 metric ton ⎤
⎥
1, 000 pounds ⎦
(Eq. II-4)
(i) If applicable, the owner or operator
shall document the procedures used to
ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure
measurements. These procedures
include, but are not limited to,
calibration fuel 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.
§ 98.355 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter 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, according to the
following requirements in paragraphs
(a) and (b) of this section:
(a) For each missing monthly value of
COD or wastewater flow treated, the
substitute data value shall be the
arithmetic average of the quality-assured
values of those parameters for the weeks
immediately preceding and immediately
following the missing data incident. For
each missing value of the CH4 content
or gas flow rates, the substitute data
value shall be the arithmetic average of
the quality-assured values of that
parameter immediately preceding and
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.155</MATH>
365
⎡
CH 4 AD = ∑ ⎢ Vn
n =1 ⎣
44/12 = Conversion factor for carbon to
carbon dioxide.
0.001 = Conversion factor from kg to metric
tons.
EP10AP09.154</MATH>
Where:
CO2 = Annual emissions of CO2 from oil/
water separators (metric tons/yr).
EFsep = Emissions factor for the type of
separator (kg NMVOC/m3 wastewater
treated).
VH20 = Volumetric flow rate of wastewater
treated through oil/water separator in
month m (m3/month).
C = Carbon fraction in NMVOC (default =
0.6).
(Eq. II-2)
EP10AP09.153</MATH>
MCF = CH4 conversion factor, based on
relevant values in Table II–1.
0.001 = Conversion factor from kg to metric
tons.
16706
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
immediately following the missing data
incident.
(b) 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.
§ 98.356
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information
for the wastewater treatment system.
(a) Type of wastewater treatment
system.
(b) Percent of wastewater treated at
each system component.
(c) COD.
(d) Influent flow rate.
(e) B0.
(f) MCF.
(g) Methane emissions.
(h) Type of oil/water separator
(petroleum refineries).
(i) Emissions factor for the type of
separator (petroleum refineries).
(j) Carbon fraction in NMVOC
(petroleum refineries).
(k) CO2 emissions (petroleum
refineries).
(l) Total volumetric flow of digester
gas (facilities with anaerobic digesters).
(m) CH4 concentration of digester gas
(facilities with anaerobic digesters).
(n) Temperature at which flow is
measured (facilities with anaerobic
digesters).
(o) Pressure at which flow is
measured (facilities with anaerobic
digesters).
(p) Destruction efficiency used
(facilities with anaerobic digesters).
(q) Methane destruction (facilities
with anaerobic digesters).
(r) Fugitive methane (facilities with
anaerobic digesters).
§ 98.357
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the calibration records for all
monitoring equipment.
§ 98.358
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE II–1 OF SUBPART II—EMISSION FACTORS
Default
value
Factors
B0 ...................................................................................................
MCF—anaerobic deep lagoon, anaerobic reactor (e.g., upflow
anaerobic sludge blanket, fixed film).
MCF—anaerobic shallow lagoon (less than 2 m) ........................
MCF—centralized aerobic treatment system, well managed .......
MCF—Centralized aerobic treatment system, not well managed
(overloaded).
Anaerobic digester for sludge .......................................................
C fraction in NMOC .......................................................................
EF sep—Gravity Type (Uncovered) ..............................................
EF sep—Gravity Type (Covered) .................................................
EF sep—Gravity Type—(Covered and Connected to a Destruction Device).
DAF or IAF—uncovered ................................................................
DAF or IAF—covered ....................................................................
DAF or IAF—covered and connected to a destruction device .....
0.25
0.8
0.2
0
0.3
Units
Kg CH4/kg COD.
Fraction.
Fraction.
Fraction.
Fraction.
0.8
0.6
1.11E–01
3.30E–03
0
Fraction.
Fraction.
Kg NMVOC/m3 wastewater
Kg NMVOC/m3 wastewater.
Kg NMVOC/m3 wastewater.
4.00E–34
1.20E–44
0
Kg NMVOC/m3 wastewater.
Kg NMVOC/m3 wastewater.
Kg NMVOC/m3 wastewater.
DAF = dissolved air flotation type.
IAF = induced air flotation type.
Subpart JJ—Manure Management
§ 98.360
Definition of the source category.
(a) This source category consists of
manure management systems for
livestock manure.
(b) A manure management system is
as a system that stabilizes or stores
livestock manure in one or more of the
following system components:
uncovered anaerobic lagoons, liquid/
slurry systems, storage pits, digesters,
drylots, solid manure storage, feedlots
and other dry lots, high rise houses for
poultry production (poultry without
litter), poultry production with litter,
deep bedding systems for cattle and
swine, and manure composting. This
definition of manure management
system encompasses the treatment of
wastewaters from manure.
(c) This source category does not
include components at a livestock
operation unrelated to the stabilization
or storage of manure such as daily
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
spread or pasture/range/paddock
systems.
§ 98.361
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a manure management system
and the facility meets the requirements
of either § 98.2(a)(1) or (2).
§ 98.362
GHGs to report.
(a) You must report annual aggregate
CH4 and N2O emissions for each of the
following manure management system
(MMS) components at the facility:
(1) Liquid/slurry systems such as
tanks and ponds.
(2) Storage pits.
(3) Uncovered anaerobic lagoons used
for stabilization or storage or both.
(4) Digesters, including covered
anaerobic lagoons.
(5) Solid manure storage including
feedlots and other dry lots, high rise
houses for caged laying hens, broiler
PO 00000
Frm 00260
Fmt 4701
Sfmt 4702
and turkey production on litter, and
deep bedding systems for cattle and
swine.
(6) Manure composting.
(b) You must report CO2, CH4, and
N2O emissions from the combustion of
supplemental fuels used in flares by
following the requirements of subpart C
of this part. For flares, calculate the CO2
emissions only from pilot gas and other
auxiliary fuels combusted in the flare, as
specified in subpart C of this part. Do
not include CO2 emissions resulting
from the combustion of digester gas in
flares.
(c) A facility that is subject to this rule
only because of emissions from manure
management systems is not required to
report emissions from fuels used in
stationary combustion devices other
than flares.
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.363
16707
Calculating GHG emissions.
(a) For manure management systems
except digesters, estimate the annual
CH4 emissions using Equation JJ–1.
MCFMMS ] 0.662 kg CH 4 /m3 ⎤ (Eq. JJ-1)
⎦
(b) For each digester, estimate the
annual CH4 flow to the combustion
device using Equation JJ–3 of this
section, the amount of CH4 destroyed
using Eq JJ–4 of this section, and the
amount of CH4 leakage using Equation
JJ–5 of this section.
365
⎛
Cn
P
520oR
0.454 metric ton ⎞
CH 4 D = ∑ ⎜ Vn ∗
∗ 0.0423 ∗
∗ n ∗ 1, 440 minutes/day ∗
⎟
100%
Tn
1 atm
1,000 pounds ⎠
n=1 ⎝
Where:
CH4D = Methane flow to digester combustion
device (metric tons CH4/yr)
Vn = Daily average volumetric flow rate for
day n, as determined from daily
monitoring as specified in § 98.364
(acfm).
Cn = Daily average CH4 concentration of
digester gas for day n, as determined
from daily monitoring as specified in
§ 98.364 (%, wet basis)
0.0423 = Density of CH4 lb/scf (at 520 °R or
60 °F and 1 atm).
Tn = Temperature at which flow is measured
for day n(°R).
Pn = Pressure at which flow is measured for
day n (atm).
CH 4 Destruction at Digesters (kg/yr) = CH 4 D DE OH/Hours
Where:
CH4D = Annual quantity of CH4 flow to
digester combustion device, as
calculated in Equation JJ–4 of this
section (metric tons CH4).
DE = CH4 destruction efficiency from flaring
or burning in engine (lesser of
⎛ 1
⎞
CH 4 Leakage at Digesters (kg/yr) = CH 4 D × ⎜
− 1⎟
CE ⎠
⎝
CH4D = Annual quantity of CH4 combusted
by digester, as calculated in Equation JJ–
4 of this section (metric tons CH4).
CE = CH4 collection efficiency of anaerobic
digester, as specified in Table JJ–3 of this
section (decimal).
(Eq. JJ-3)
(Eq. JJ-4)
manufacturer’s specified destruction
efficiency and 0.99).
OH = Number of hours combustion device is
functioning in reporting year.
Hours = Hours in reporting year.
(Eq. JJ-5)
(c) For each manure management
system type, estimate the annual N2O
emissions using Equation JJ–6 of this
section.
Direct N 2 O Emissions (kg/yr) =
∑
VerDate Nov<24>2008
animal type
⎡ ∑ MMS N ex x N ex,MMS x EFMMS x 365.25 days/yr ⎤ x 44 N 2 O/28 N 2 O-N ]
⎣
⎦
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00261
Fmt 4701
Sfmt 4725
E:\FR\FM\10APP2.SGM
10APP2
(Eq. JJ-6)
EP10AP09.160</MATH>
Population = Average annual animal
population (head).
TAM = Typical animal mass, using either
default values in Table JJ–1 of this
section or farm-specific data (kg/head).
MER = Manure excretion rate, using either
default values in Table JJ–1 of this
section or farm-specific data (kg manure/
day/1,000 kg animal mass).
(Eq. JJ-2)
EP10AP09.159</MATH>
MER/1000)
EP10AP09.158</MATH>
TAM
B0 = Maximum CH4-producing capacity, as
specified in Table JJ–1 of this section (m3
CH4/kg VS).
MCFMMS = CH4 conversion factor for MMS,
as specified in Table JJ–2 of this section
(decimal).
EP10AP09.157</MATH>
VSMMS = Percent of manure that is managed
in each MMS (decimal) (assumed to be
equivalent to the amount of VS in each
system).
TVS = %TVS (Population
Where:
TVS = Total volatile solids excreted per
animal type (kg/day).
%TVS = Annual average percent total
volatile solids by animal type, as
determined from monthly manure
monitoring as specified in § 98.364
(decimal).
B0
EP10AP09.187</MATH>
Where:
TVS = Total volatile solids excreted by
animal type, calculated using Equation
JJ–2 of this section (kg/day).
365.25 days/yr
EP10AP09.156</MATH>
CH 4 Emissions (kg/yr) = ∑ animal type ⎡ ∑ MMS [TVS VSMMS
⎣
16708
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
N ex = N Manure × (Population × TAM × MER/1000)
Where:
Nex = Total nitrogen excreted per animal type
(kg/day).
NManure = Annual average percent of nitrogen
present in manure by animal type, as
determined from monthly manure
monitoring, as specified in § 98.364
(decimal).
Population = Average annual animal
population (head).
TAM = Typical animal mass, using either
default values in Table JJ–1 of this
section or farm-specific data (kg/head).
EFMMS = Emission factor for MMS, as
specified in Table JJ–4 of this section (kg
N2O–N/kg N).
(Eq. JJ-7)
MER = Manure excretion rate, using either
default values in Table JJ–1 of this
section or farm-specific data (kg manure/
day/1,000 kg animal mass).
(d) Estimate the annual total annual
emissions using Equation JJ–8 of this
section.
Total Emissions (metric tons CO 2 e /yr ) = [(CH 4 emissions + CH 4 flow to digester combustion
device − CH 4 destruction of digester + CH 4 leakage of digester)
x 1 metric ton/1000 kg x 21] +[direct N 2 O emissions x 1 metric ton/1000 kg x 310]
Where:
CH4 emissions = From Equation JJ–1 of this
section.
CH4 flow to digester combustion device =
From Equation JJ–3 of this section.
CH4 destruction of digester = From Equation
JJ–4 of this section.
CH4 leakage of digester = From Equation JJ–
5 of this section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = from Equation JJ–6 of
this section.
310 = Global Warming Potential of N2O.
§ 98.364 Monitoring and QA/QC
requirements.
(a) Perform a one-time analysis on
your operation to determine the percent
of total manure by weight that is
managed in each on-site manure
management system.
(b) Determine the annual average
percent total volatile solids by animal
type, (%TVS) by analysis of a
representative sample using Method
160.4 (Residue, Volatile) as described in
Methods for Chemical Analysis of Water
and Wastes, EPA–600/4–79/020,
Revised March 1983. The laboratory
performing the analyses should be
certified for analysis of waste for
National Pollutant Discharge
Elimination System compliance
reporting. The sample analyzed should
be a representative composite of freshly
excreted manure from each animal type
contributing to the manure management
system. Total volatile solids of manure
must be sampled and analyzed monthly.
(c) Determine the annual average
percent of nitrogen present in manure
by animal type (NManure) by analysis of
a representative sample using Method
351.3 as described in Methods for
Chemical Analysis of Water and Wastes,
EPA–600/4–79–020, Revised March
1983. The laboratory performing the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
analyses should be certified for analysis
of waste for National Pollutant
Discharge Elimination System
compliance reporting. The sample
analyzed should be a representative
composite of freshly excreted manure
from each animal type contributing to
the manure management system.
Sample collection and analysis must be
monthly.
(d) The flow and CH4 concentration of
gas from digesters must be determined
using ASTM D1945–03 (Reapproved
2006), Standard Test Method for
Analysis of Natural Gas by Gas
Chromatography; ASTM D1946–90
(Reapproved 2006), Standard Practice
for Analysis of Reformed Gas by Gas
Chromatography; ASTM D4891–89
(Reapproved 2006), Standard Test
Method for Heating Value of Gases in
Natural Gas Range by Stoichiometric
Combustion; or UOP539–97 Refinery
Gas Analysis by Gas Chromatography
(incorporated by reference in § 98.7).
(e) All temperature and pressure
monitors must be calibrated using the
procedures and frequencies specified by
the manufacturer.
(f) All gas flow meters and gas
composition monitors shall be
calibrated prior to the first reporting
year, using a suitable method published
by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, or
others). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Gas flow
meters and gas composition monitors
shall be recalibrated either annually or
at the minimum frequency specified by
the manufacturer.
(g) All equipment (temperature and
pressure monitors and gas flow meters
and gas composition monitors) shall be
PO 00000
Frm 00262
Fmt 4701
Sfmt 4702
(Eq. JJ-8)
maintained as specified by the
manufacturer.
(h) If applicable, the owner or
operator shall document the procedures
used to ensure the accuracy of gas flow
rate, gas composition, temperature, and
pressure measurements. These
procedures include, but are not limited
to, calibration of fuel 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.
§ 98.365 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter 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, according to the
requirements in paragraph (b) of this
section.
(b) For missing gas flow rates, volatile
solids, or nitrogen or methane content
data, the substitute data value shall be
the arithmetic average of the qualityassured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value obtained after the missing
data period.
§ 98.366
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.162</MATH>
Nex,MMS = Percent of manure that is managed
in each MMS (decimal) (assumed to be
equivalent to the amount of Nex in each
system).
EP10AP09.161</MATH>
Where:
Nex = Total nitrogen excreted per animal
type, calculated using Equation JJ–7 of
this section (kg/day).
16709
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
must contain the following information
for each manure management system
component:
(a) Type of manure management
system component.
(b) Animal population (by animal
type).
(c) Monthly total volatile solids
content of excreted manure.
(d) Percent of manure handled in each
manure management system
component.
(e) B0 value used.
(f) Methane conversion factor used.
(g) Average animal mass (for each
type of animal).
(h) Monthly nitrogen content of
excreted manure.
(i) N2O emission factor selected.
(j) CH4 emissions
(k) N2O emissions.
(l) Total annual volumetric biogas
flow (for systems with digesters).
(m) Average annual CH4
concentration (for systems with
digesters).
(n) Temperature at which gas flow is
measured (for systems with digesters).
(o) Pressure at which gas flow is
measured (for systems with digesters).
(p) Destruction efficiency used (for
systems with digesters).
(q) Methane destruction (for systems
with digesters).
(r) Methane generation from the
digesters.
§ 98.367
Records that must be retained.
In addition to the information
required by § 98.3(g), you must retain
the calibration records for all
monitoring equipment.
§ 98.368
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE JJ–1 OF SUBPART JJ—WASTE CHARACTERISTICS DATA
Animal
group typical animal
mass (kg)
Animal group
Dairy Cows ..............................................................................................................................................
Dairy Heifers ............................................................................................................................................
Feedlot Steers .........................................................................................................................................
Feedlot Heifers ........................................................................................................................................
Market Swine <60 lbs. .............................................................................................................................
Market Swine 60–119 lbs. .......................................................................................................................
Market Swine 120–179 lbs. .....................................................................................................................
Market Swine >180 lbs. ...........................................................................................................................
Breeding Swine ........................................................................................................................................
Feedlot Sheep .........................................................................................................................................
Goats .......................................................................................................................................................
Horses ......................................................................................................................................................
Hens >/= 1 yr ...........................................................................................................................................
Pullets ......................................................................................................................................................
Other Chickens ........................................................................................................................................
Broilers .....................................................................................................................................................
Turkeys ....................................................................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00263
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
604
476
420
420
16
41
68
91
198
25
64
450
1.8
1.8
1.8
0.9
6.8
10APP2
Manure excretion rate
(kg/day/
1000 kg animal mass)
Maximum
methane
generation
potential, Bo
(m3 CH4/kg
VS added)
80.34
85
51.2
51.2
106
63.4
63.4
63.4
31.8
40
41
51
60.5
45.6
60.5
80
43.6
0.24
0.17
0.33
0.33
0.48
0.48
0.48
0.48
0.48
0.36
0.17
0.33
0.39
0.39
0.39
0.36
0.36
16710
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE JJ–3 OF SUBPART JJ—COLLECTION EFFICIENCIES OF ANAEROBIC DIGESTERS
Methane
collection
efficiency
System type
Cover type
Covered anaerobic lagoon .........................................................
(biogas capture) ..........................................................................
Complete mix, fixed film, or plug flow digester ..........................
Bank to bank, impermeable .......................................................
Modular, impermeable ................................................................
Enclosed Vessel .........................................................................
Waste management system
Aerobic Treatment (forced aeration) .....................................
Aerobic Treatment (natural aeration) .....................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
N2O emission factor
0.005
0.01
Jkt 217001
TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS
(kg N2O-N/kg Kjdl N)—Continued
Waste management system
Digester ....................................
Uncovered Anaerobic Lagoon ..
Cattle Deep Bed (active mix) ...
Cattle Deep Bed (no mix) .........
PO 00000
Frm 00264
Fmt 4701
Sfmt 4702
N2O emission factor
0
0
0.07
0.01
TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS
(kg N2O-N/kg Kjdl N)—Continued
Waste management system
Manure
Manure
Manure
Manure
E:\FR\FM\10APP2.SGM
Composting
Composting
Composting
Composting
10APP2
(in vessel)
(intensive)
(passive)
(static) .....
N2O emission factor
0.006
0.1
0.01
0.006
EP10AP09.163</GPH>
TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS
(kg N2O-N/kg Kjdl N)
0.975
0.70
0.99
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
any U.S. coal mining company,
TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS wholesale coal dealer, retail coal dealer,
or other organization that imports coal
(kg N2O-N/kg Kjdl N)—Continued
into the U.S. ‘‘Importer’’ includes the
person primarily liable for the payment
N2O emisWaste management system
sion factor
of any duties on the merchandise or an
authorized agent acting on his or her
Deep Pit ....................................
0.002 behalf.
Dry Lot ......................................
0.02
(d) Coal exporter has the same
Liquid/Slurry ..............................
0.005
Poultry with bedding .................
0.001 meaning given in § 98.6 and includes
Poultry without bedding ............
0.001 any U.S. coal mining company,
Solid Storage ............................
0.005 wholesale coal dealer, retail coal dealer,
or other organization that exports coal
from the U.S.
Subpart KK—Supplies of Coal
(e) Waste coal reclaimer means any
§ 98.370 Definition of the source category.
U.S. facility that reclaims or recovers
(a) This source category comprises
waste coal from waste coal piles from
coal mines, coal importers, coal
previous mining operations and sells or
exporters, and waste coal reclaimers.
delivers to an end-user.
(b) Coal mine means any active U.S.
coal mine engaged in the production of
§ 98.371 Reporting threshold.
coal within the U.S. during the calendar
Any supplier of coal who meets the
year regardless of the rank of coal
requirements of § 98.2(a)(4) must report
produced, e.g., bituminous, subbituminous, lignite, anthracite. Any coal GHG emissions.
mine categorized as an active coal mine § 98.372 GHGs to report.
by MSHA is included.
(c) Coal importer has the same
You must report the CO2 emissions
meaning given in § 98.6 and includes
that would result from the complete
CO 2 = 44/12 Mass Carbon 0.907
Where:
CO2 = Annual CO2 mass emissions from the
combustion of coal (metric tons/yr).
44/12 = Ratio of molecular weights, CO2 to
carbon.
Mass = Quantity of coal produced from
company records (short tons/yr).
(d) For coal mines using Calculation
Methodology 1 of this subpart, the
annual weighted average of the mass
fraction of carbon in the coal shall be
n
yi ) /S
combustion or oxidation of coal
supplied during the calendar year.
§ 98.373
Calculating GHG emissions.
(a) For coal mines producing 100,000
short tons of coal or more annually, the
estimate of CO2 emissions shall be
calculated using either Calculation
Methodology 1 or Calculation
Methodology 2 of this subpart.
(b) For coal mines producing less than
100,000 short tons of coal annually, and
for coal exporters, coal importers, and
waste coal reclaimers; CO2 emissions
shall be calculated using either
Calculation Methodology 1, 2, or 3 of
this subpart.
(c) For Calculation Methodology 1, 2,
and 3 of this subpart, emissions of CO2
shall be calculated using Equation KK–
1 of this section. The difference between
Calculation Methodology 1, 2, and 3 of
this subpart, is the method for
determining the carbon content in coal,
as specified in paragraphs (d), (e), and
(f) of this section:
(Eq. KK-1)
Carbon = Annual weighted average fraction
of carbon in the coal (decimal value).
0.907 = Conversion factor from short tons to
metric tons.
Carbon = ∑ ( xi
16711
based on daily measurements and
calculated using Equation KK–2 of this
section. For importers, exporters, and
waste coal reclaimers using
Methodology 1 of this subpart,
measurements of each shipment can be
used in place of daily measurements:
(Eq. KK-2)
(e) For coal mines using Calculation
Methodology 2 of this subpart, the
annual weighted average of the mass
fraction of carbon in the coal shall be
calculated on the basis of daily
measurements of the gross calorific
value (GCV) of the coal and a statistical
relationship between carbon content
and GCV (higher heating value). For
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
importers, exporters, and waste coal
reclaimers using Calculation
Methodology 2 of this subpart,
measurements of each shipment can be
used in place of daily measurements.
(1) Equation KK–3 shall be used to
determine the weighted annual average
GCV of the coal, and the individual
daily or per shipment values shall be
determined according to the monitoring
methodology for gross calorific values in
§ 98.374(f).
(2) The statistical relationship
between GCV and carbon content shall
be established according to the
requirements in § 98.374(f).
(3) The estimated annual weighted
average of the mass fraction of carbon in
the coal shall be calculated by applying
the slope coefficient, determined
PO 00000
Frm 00265
Fmt 4701
Sfmt 4702
according to the requirements of
§ 98.374(f)(4), to the weighted annual
average GCV of the coal determined
according to Equation KK–3 of this
section.
(f) For coal mines using Calculation
Methodology 3 of this subpart, the
annual weighted average of the mass
fraction of carbon in the coal shall be
calculated on the basis of daily
measurements of GCV of the coal and a
default fraction of carbon in coal from
Table KK–1 of this subpart. For
importers, exporters, and waste coal
reclaimers using Methodology 3 of this
subpart, measurements of each
shipment can be used in place of daily
measurements.
(1) Equation KK–3 shall be used to
determine the weighted annual average
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.164</MATH>
Where:
Carbon = Annual mass fraction of coal carbon
(dimensionless).
Xi = Daily or per shipment mass fraction of
carbon in coal for day i measured by
ultimate analysis (decimal value).
Yi = Amount of coal supplied on day i(short
tons) as measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short
tons).
EP10AP09.165</MATH>
i =1
16712
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
n
GCV = ∑ ( zi ∗ yi ) /S
(Eq. KK-3)
i =1
Where:
GCV = the weighted annual average gross
calorific value or higher heating value of
the coal (Btu/lb).
zi = Daily or per shipment GCV or HHV of
coal for day i measured by proximate
analysis (decimal value).
yi = Amount of coal supplied on day i (short
tons) as measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short
tons).
§ 98.374 Monitoring and QA/QC
requirements.
(a) The most current version of the
NIST Handbook published by Weights
and Measures Division, National
Institute of Standards and Technology
shall be used as the standard practice
for all coal weighing.
(b) For all coal mines, the quantity of
coal shall be determined as the total
mass of coal in short tons sold and
removed from the facility during the
calendar year.
(c) For coal importers, the quantity of
coal shall be determined as the total
mass of coal in short tons imported into
the U.S. during the calendar year, as
reported to U.S. Customs.
(d) For coal exporters, the quantity of
coal shall be determined as the total
mass of coal in short tons sold and
exported from the U.S., as reported to
U.S. Customs.
(e) For waste coal reclaimers, the
quantity of coal shall be determined as
the total mass of coal in short tons sold
for use as reported to state agencies.
(f) For reporters using Calculation
Methodology 1 of this subpart, the
carbon content shall be determined as
follows:
(1) Representative coal samples shall
be collected daily or per shipment using
ASTM D4916–04, D6609–07, D6883–04,
D7256/D7256M–06a, or D7430–08 from
coal loaded on the conveyor belt.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(2) Daily or per shipment coal carbon
content shall be determined using
ASTM D5373 (Test Methods for
Instrumental Determination of Carbon
Hydrogen and Nitrogen in Laboratory
Samples of Coal and Coke).
(g) For reporters using Calculation
Methodology 2 of this subpart, the
carbon content shall be determined as
follows:
(1) Representative samples of coal
shall be collected daily or per shipment
using ASTM D4916–04, D6609–07,
D6883–04, D7256/D7256M–06a, or
D7430–08.
(2) Coal gross calorific value (GCV)
shall be determined on the set of
samples collected in paragraph (f)(1) of
this section using ASTM D5865–07a,
‘‘Standard Test Method for Gross
Calorific Value of Coal and Coke to
record the heat content of the coal
produced.
(3) Coal carbon content shall be
determined at a minimum once each
month on one set of daily or per
shipment samples collected in
paragraph (f)(1) of this section using
ASTM D5373 (Test Methods for
Instrumental Determination of Carbon
Hydrogen and Nitrogen in Laboratory
Samples of Coal and Coke).
(4) The individual samples for which
both carbon content and GCV were
determined according to paragraphs
(f)(2) and (f)(3) of this section
respectively, shall be used to establish
a statistical relationship between the
heat content and the carbon content of
the coal produced. The owner or
operator shall statistically plot the
correlation of Btu/lb of coal vs. percent
carbon (as a decimal value), where the
x-axis is Btu/lb coal and the y-axis is
percent carbon (as decimal value), then
fit a line to the data points, then
calculate the slope and the coefficient of
determination, and the R-square (R2) of
that line using the Btu/lb and percent
carbon.
(5) Calculation Methodology 2 of this
subpart can be used only if all of the
following four conditions are met:
(i) At least 12 samples per reporting
year from 12 different months of data
must be used to construct the
correlation graph.
(ii) The correlation graph must be
constructed using all paired data points
from the first reporting year and all
subsequent reporting years.
(iii) There must be a linear
relationship between percent carbon
and Btu/lb of coal.
(iv) For the second and subsequent
years, R-square (R2) must be greater than
or equal to 0.90. This R-square
requirement does not apply during the
first reporting year.
PO 00000
Frm 00266
Fmt 4701
Sfmt 4702
(6) If all of the conditions specified in
paragraph (f)(5) of this section are met,
the weighted annual average gross
calorific value or higher heating value
(Btu/lb) calculated according to
Equation KK–3 of this section shall be
used to determine the corresponding
annual average coal carbon content
using the correlation graph plotted
according to paragraph (f)(4) of this
section.
(h) Reporters complying with
Calculation Methodology 3 of this
subpart shall determine gross calorific
value of the coal by collecting
representative daily or per shipment
samples of coal using either ASTM
D4916–04, D6609–07, D6883–04,
D7256/D7256M–06a, or D7430–08; and
testing using ASTM D5865–07a,
‘‘Standard Test Method for Gross
Calorific Value of Coal and Coke to
record the heat content of the coal
produced.’’
(i) Coal exporters shall calculate
carbon content for each shipment of
coal using information on the carbon
content of the exported coal provided by
the source mine, according to
Calculation Methodology 1, 2, or 3 of
this subpart, as appropriate.
(j) Coal importers shall calculate
carbon content for each shipment of
coal using Calculation Methodology 1,
2, or 3 of this subpart.
(k) Waste coal reclaimers shall
calculate carbon content for each
shipment of coal using Calculation
Methodology 1, 2, or 3 of this subpart.
(l) Each owner or operator using
mechanical coal sampling systems shall
perform quality assurance and quality
control according to ASTM D4702–07
and ASTM D6518–07.
§ 98.375 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable, a
substitute data value for the missing
parameter shall be used in the
calculations.
(b) Whenever a quality-assured value
for coal production during any time
period is unavailable, you must use the
average of the parameter values
recorded immediately before and after
the missing data period in the
calculations.
(c) Facilities using Calculation
Methodology 1 of this subpart shall
develop the statistical relationship
between GCV and carbon content
according to § 98.274(e), and use this
statistical relationship to estimate daily
carbon content for any day for which
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.166</MATH>
GCV of the coal, and the individual
daily or per shipment values shall be
determined according to the monitoring
methodology for gross calorific values in
§ 98.374(g).
(2) The estimated annual weighted
average of the mass fraction of carbon in
the coal shall be identified from Table
KK–1 of this subpart using annual
weighted GCV of the coal determined
according to Equation KK–3 of this
section.
(g) For Calculation Methodologies 2
and 3 of this subpart, the weighted
annual average gross calorific value
(GCV) or higher heating value of the
coal shall be calculated using Equation
KK–3 of this section:
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
measured carbon content is not
available.
(d) Facilities, importers and exporters
using Calculation Methodology 2 or 3 of
this subpart shall estimate the missing
GCV values based on a weighted average
value for the previous seven days.
(e) Estimates of missing data shall be
documented and records maintained
showing the calculations.
§ 98.376
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information.
(a) Each coal mine owner or operator
shall report the following information
for each coal mine:
(1) The name and MSHA ID number
of the mine.
(2) The name of the operating
company.
(3) Annual CO2 emissions.
(4) By rank, the total annual quantity
in tons of coal produced.
(5) The annual weighted carbon
content of the coal as calculated
according to § 98.373.
(6) If Calculation Methodology 1 of
this subpart was used to determine CO2
mass emissions, you must report daily
mass fraction of carbon in coal
measured by ultimate analysis and daily
amount of coal supplied.
(7) If Calculation Methodology 2 of
this subpart was used to determine CO2
mass emissions, you must report:
(i) All of the data used to construct
the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R2) value of the
correlation.
(8) If Calculation Methodology 3 of
this subpart was used to determine CO2
mass emissions, you must report daily
GCV of coal measured by proximate
analysis and daily amount of coal
supplied.
(b) Coal importers shall report the
following information at the corporate
level:
(1) The total annual quantity in tons
of coal imported into the U.S. by the
importer, by rank, and country of origin.
(2) Annual CO2 emissions.
(3) The annual weighted carbon
content of the coal as calculated
according to § 98.373.
(4) If Calculation Methodology 1 of
this subpart was used to determine CO2
mass emissions, you must report mass
fraction of carbon in coal per shipment
measured by ultimate analysis and
amount of coal supplied per shipment.
(5) If Calculation Methodology 2 of
this subpart was used to determine CO2
mass emissions, you must report:
(i) All of the data used to construct
the carbon vs. Btu/lb correlation graph.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(ii) Slope of the correlation line.
(iii) The R-squared (R2) value of the
correlation.
(6) If Calculation Methodology 3 of
this subpart was used to determine CO2
mass emissions, you must report GCV in
coal per shipment measured by
proximate analysis and amount of coal
supplied per shipment.
(d) Coal exporters shall report the
following information at the corporate
level:
(1) The total annual quantity in tons
of coal exported from the U.S. by rank
and by coal producing company and
mine.
(2) Annual CO2 emissions.
(3) The annual weighted carbon
content of the coal as calculated
according to § 98.373.
(4) If Calculation Methodology 1 of
this subpart was used to determine CO2
mass emissions, you must report mass
fraction of carbon in coal per shipment
measured by ultimate analysis and
amount of coal supplied per shipment.
(5) If Calculation Methodology 2 of
this subpart was used to determine CO2
mass emissions, you must report:
(i) All of the data used to construct
the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R2) value of the
correlation.
(6) If Calculation Methodology 3 of
this subpart was used to determine CO2
mass emissions, you must report GCV in
coal per shipment measured by
proximate analysis and amount of coal
supplied per shipment.
(e) Waste coal reclaimers shall report
the following information for each
reclamation site:
(1) By rank, the total annual quantity
in tons of waste coal produced.
(2) Mine and state of origin if waste
coal is reclaimed from mines that are no
longer operating.
(3) Annual CO2 emissions.
(4) The annual weighted carbon
content of the coal as calculated
according to § 98.373.
(5) If Calculation Methodology 1 of
this subpart was used to determine CO2
mass emissions, you must report mass
fraction of carbon in coal per shipment
measured by ultimate analysis and
amount of coal supplied per shipment.
(6) If Calculation Methodology 2 of
this subpart was used to determine CO2
mass emissions, you must report:
(i) All of the data used to construct
the carbon vs. Btu/lb correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squre (R 2) value of the
correlation.
(7) If Calculation Methodology 3 of
this subpart was used to determine CO2
mass emissions, you must report GCV in
PO 00000
Frm 00267
Fmt 4701
Sfmt 4702
16713
coal per shipment measured by
proximate analysis and amount of coal
supplied per shipment.
§ 98.377
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the following
information:
(a) A complete record of all measured
parameters used in the reporting of fuel
quantities, including all sample results
and documentation to support
quantities that are reported under this
part.
(b) Records documenting all
calculations of missing data.
(c) Calculations and worksheets used
to estimate the CO2 emissions.
(d) Calibration records of any
instruments used on site and calibration
records of scales or other equipment
used to weigh coal.
§ 98.378
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE KK–1 OF SUBPART KK—DEFAULT CARBON CONTENT OF COAL
FOR METHOD 3 (CO2 lbs/MMBtu1)
Weighted annual average
GCV of coal Btu/lb1
2,000 .....................................
2,250 .....................................
2,500 .....................................
2,750 .....................................
3,000 .....................................
3,250 .....................................
3,500 .....................................
3,750 .....................................
4,000 .....................................
4,250 .....................................
4,500 .....................................
4,750 .....................................
5,000 .....................................
5,250 .....................................
5,500 .....................................
5,750 .....................................
6,000 .....................................
6,250 .....................................
6,500 .....................................
6,750 .....................................
7,000 .....................................
7,250 .....................................
7,500 .....................................
7,750 .....................................
8,000 .....................................
8,250 .....................................
8,500 .....................................
8,750 .....................................
9,000 .....................................
9,250 .....................................
9,500 .....................................
9,750 .....................................
10,000 ...................................
10,250 ...................................
10,500 ...................................
10,750 ...................................
E:\FR\FM\10APP2.SGM
10APP2
Mass fraction
of carbon in
coal
(decimal)
0.1140
0.1283
0.1425
0.1568
0.1710
0.1853
0.1995
0.2138
0.2280
0.2423
0.2565
0.2708
0.2850
0.2993
0.3135
0.3278
0.3420
0.3563
0.3705
0.3848
0.3990
0.4133
0.4275
0.4418
0.4560
0.4703
0.4845
0.4988
0.5130
0.5273
0.5415
0.5558
0.5700
0.5843
0.5985
0.6128
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Weighted annual average
GCV of coal Btu/lb1
Mass fraction
of carbon in
coal
(decimal)
TABLE KK–1 OF SUBPART KK—DEFAULT CARBON CONTENT OF COAL
FOR
METHOD
3
(CO2
lbs/
MMBtu1)—Continued
Weighted annual average
GCV of coal Btu/lb1
Mass fraction
of carbon in
coal
(decimal)
fuels such as gasoline and diesel using
the Fischer-Tropsch process or an
alternative process, involving
conversion of coal into gas and then into
liquids or conversion of coal directly
into liquids (direct liquefaction).
(b) An importer or exporter shall have
the same meaning given in § 98.6.
§ 98.381
11,000
11,250
11,500
11,750
12,000
12,250
12,500
12,750
13,000
13,250
13,500
13,750
14,000
14,250
14,500
14,750
15,000
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
...................................
0.6270
0.6413
0.6555
0.6698
0.6840
0.6983
0.7125
0.7268
0.7410
0.7553
0.7695
0.7838
0.7980
0.8123
0.8265
0.8408
0.8550
15,250 ...................................
15,500 ...................................
1 Based
on high heating values.
Subpart LL—Suppliers of Coal-based
Liquid Fuels
§ 98.380
Definition of the source category.
This source category consists of
producers, importers, and exporters of
coal-based liquids.
(a) A producer is the owner or
operator of a coal-to-liquids facility. A
coal-to-liquids facility is any facility
engaged in coverting coal into liquid
CO 2 = ∑ ( Pr oduct i ∗ EFi )
Where:
CO2 = Annual CO2 mass emissions from the
combustion of fuel (metric tons).
Producti = Total annual volume (in standard
barrels) of a coal-based liquid fuel ‘‘i’’
produced, imported, or exported.
EFi = CO2 emission factor (metric tons CO2
per barrel) specific to liquid fuel ‘‘i’’.
EF = Density
Where:
EF = Emission factor of coal-based liquid
(metric tons CO2 per barrel).
Density = Density of coal-based liquid
(metric tons per barrel).
Wt% = Percent of total mass that carbon
represents in coal-based liquid.
§ 98.384 Monitoring and QA/QC
requirements.
(a) Producers must measure the
quantity of coal-based liquid fuels using
procedures for flow meters as described
in subpart MM of this part.
(b) Importers and exporters must
determine the quantity of coal-based
liquid fuels using sales contract
information on the volume imported or
exported during the reporting period.
(1) The quantity of coal-based liquid
fuels must be measured using sales
contract information.
15:41 Apr 09, 2009
Jkt 217001
Wt%
(44/12)
Frm 00268
Fmt 4701
Sfmt 4702
§ 98.382
GHGs to report.
You must report the CO2 emissions
that would result from the complete
combustion or oxidation of coal-based
liquids during the calendar year.
§ 98.383
Calculating GHG emissions.
(a) Coal-to-liquid producers,
importers and exporters must calculate
CO2 emissions using Equation LL–1 of
this section.
(2) Calculation Methodology 2.
Develop a CO2 emission factor
according to Equation LL–2 of this
section using direct measurement of
density and carbon share according to
methods set forth in § 98.394(c) or a
combination of direct measurement and
the default factor listed in columns A or
B of Table MM–1 of subpart MM that
most closely represents the coal-based
liquid.
(Eq. LL-2)
(2) The minimum frequency of the
measurement of quantities of coal-based
liquid fuels shall be the number of sales
contracts executed in the reporting
period.
(c) All flow meters and product
monitors shall be calibrated prior to use
for reporting, using a suitable method
published by a consensus standards
organization (e.g., ASTM, ASME, API,
NAESB, or others). Alternatively,
calibration procedures specified by the
flow meter manufacturer may be used.
Fuel flow meters shall be recalibrated
either annually or at the minimum
frequency specified by the
manufacturer.
(d) Reporters shall take the following
steps to ensure the quality and accuracy
of the data reported under these rules:
(1) For all volumes of coal-based
liquid fuels, reporters shall maintain
PO 00000
Reporting threshold.
Any supplier of coal-based liquid
fuels who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
(Eq. LL-1)
calculation methodologies described in
paragraphs (a) and (b) of this section.
The same calculation methodology must
be used for the entire volume of the
product for the reporting year.
(1) Calculation Methodology 1. Use
the default CO2 emission factor listed in
column C of Table MM–1 of subpart
MM (Suppliers of Petroleum Products)
that most closely represents the coalbased liquid.
(b) The emission factor (EF) for each
type of coal-based liquid shall be
determined using either of the
VerDate Nov<24>2008
0.8693
0.8835
meter and such other records as are
normally maintained in the course of
business to document fuel flows.
(2) For all estimates of CO2 mass
emissions, reporters shall maintain
calculations and worksheets used to
calculate the emissions.
§ 98.385 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the reporting of fuel
volumes and the calculations of CO2
mass emissions is required. Therefore,
whenever a quality-assured
measurement of the quantity of coalbased liquid fuels is unavailable a
substitute data value for the missing
quantity measurement shall be
calculated and used in the calculations.
(b) For coal-to-liquids facilities, the
last quality assured reading shall be
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.168</MATH>
TABLE KK–1 OF SUBPART KK—DEFAULT CARBON CONTENT OF COAL
FOR
METHOD
3
(CO2
lbs/
MMBtu1)—Continued
EP10AP09.167</MATH>
16714
16715
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 98.388
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart MM—Suppliers of Petroleum
Products
§ 98.390
Definition of the source category.
This source category consists of
petroleum refineries and importers and
exporters of petroleum products.
(a) A petroleum refinery is any facility
engaged in producing gasoline,
kerosene, distillate fuel oils, residual
fuel oils, lubricants, asphalt (bitumen)
or other products through distillation of
petroleum or through redistillation,
cracking, or reforming of unfinished
petroleum derivatives.
(b) A refiner is the owner or operator
of a petroleum refinery.
(c) Importer has the same meaning
given in § 98.6 and includes any blender
or refiner of refined or semi-refined
petroleum products.
(d) Exporter has the same meaning
given in § 98.6 and includes any blender
or refiner of refined or semi-refined
petroleum products.
CO 2j = Feedstock j EFj
Where:
CO2j = Annual potential CO2 emissions from
the complete combustion or oxidation of
each non-crude feedstock ‘‘j’’ (metric
tons).
Where:
CO2m = Annual potential CO2 emissions from
the complete combustion or oxidation of
biomass ‘‘m’’ (metric tons).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
EFm
Frm 00269
Fmt 4701
§ 98.392
GHGs to report.
You must report the CO2 emissions
that would result from the complete
combustion or oxidation of each
petroleum product and natural gas
liquid produced, used as feedstock,
imported, or exported during the
calendar year. Additionally, if you are a
refiner, you must report CO2 emissions
that would result from the complete
combustion or oxidation of any biomass
co-processed with petroleum feedstocks.
§ 98.393
Calculating GHG emissions.
(a) Except as provided in paragraph
(g) of this section, any refiner, importer,
or exporter shall calculate CO2
emissions from each individual
petroleum product and natural gas
liquid using Equation MM–1 of this
section.
CO 2i = Product i
EFi
(Eq. MM-1)
Where:
CO2i = Annual potential CO2 emissions from
the complete combustion or oxidation of
each petroleum product or natural gas
liquid ‘‘i’’ (metric tons).
Producti = Total annual volume of product
‘‘i’’ produced, imported, or exported by
the reporting party (barrels). For refiners,
this volume only includes products ex
refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
(b) Except as provided in paragraph
(g) of this secton, any refiner shall
calculate CO2 emissions from each noncrude feedstock using Equation MM–2
of this section.
Sfmt 4702
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
(c) Refiners shall calculate CO2
emissions from all biomass co-processed
with petroleum feedstocks using
Equation MM–3 of this section.
(Eq. MM-3)
Biomassm = Total annual volume of a specific
type of biomass that enters the refinery
to be co-processed with petroleum
feedstocks to produce a petroleum
product reported under paragraph (a) of
this section (barrels).
PO 00000
Reporting threshold.
Any supplier of petroleum products
who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
(Eq. MM-2)
Feedstockj = Total annual volume of a
petroleum product or natural gas liquid
‘‘j’’ that enters the refinery as a feedstock
to be further refined or otherwise used
on site (barrels). Any waste feedstock
(see definitions) that enters the refinery
must also be included.
CO 2m = Biomass m
§ 98.391
EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per barrel).
(d) Refiners shall calculate total CO2
emissions from all products using
Equation MM–4 of this section.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.171</MATH>
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information:
(a) Producers shall report the
following information for each facility:
(1) The total annual volume of each
coal-based liquid supplied to the
economy (in standard barrels).
(2) The total annual CO2 emissions in
metric tons associated with each coalbased liquid supplied to the economy,
calculated according to § 98.383(a).
(b) Importers shall report the
following information at the corporate
level:
(1) The total annual volume of each
imported coal-based liquid (in standard
barrels).
(2) The total annual CO2 emissions in
metric tons associated with each
imported coal-based liquid, calculated
according to § 98.383(a).
(c) Exporters shall report the
following information at the corporate
level:
(1) The total annual volume of each
exported coal-based liquid (in standard
barrels).
(2) The total annual CO2 emissions in
metric tons associated with each
exported coal-based liquid, calculated
according to § 98.383(a).
Records that must be retained.
Reporters shall retain copies of all
reports submitted to EPA. Reporters
shall maintain records to support
volumes that are reported under this
part, including records documenting
any calculation of substitute measured
data. Reporters shall also retain
calculations and worksheets used to
estimate the CO2 equivalent of the
volumes reported under this part. These
records shall be retained for five (5)
years similar to 40 CFR part 80 fuels
compliance reporting program.
EP10AP09.170</MATH>
§ 98.386
§ 98.387
EP10AP09.169</MATH>
used. If substantial variation in the flow
rate is observed or if a quality assured
measurement of quantity is unavailable
for any other reason, the average of the
last and the next quality assured reading
shall be used to calculate a substitute
measurement of quantity.
(c) Calculation of substitute data shall
be documented and records maintained
showing the calculations.
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
CO 2r = ∑ ( CO 2i ) −∑ ( CO 2j ) −∑ ( CO 2m )
Where:
CO2i = Annual potential CO2 emissions from
the complete combustion or oxidation of
each petroleum product or natural gas
liquid ‘‘i’’ (metric tons).
CO2x = Total annual potential CO2 emissions
from the complete combustion or
oxidation of all petroleum products and
natural gas liquids.
(f) Except as provided in paragraph (g)
of this section, the emission factor (EF)
for each petroleum product and natural
gas liquid shall be determined using
Wt %
EFi
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
%Voli
EFj
%Vol j
Frm 00270
Fmt 4701
Sfmt 4702
(2) A refinery using Calculation
Methodology 1 of this subpart to
determine the emission factor of a noncrude petroleum feedstock shall
calculate the CO2 emissions associated
with that feedstock using Equation MM–
8 in place of Equation MM–2 of this
section.
(Eq. MM-8)
refined or otherwise used on site
(barrels).
EFj = Non-crude petroleum feedstock-specific
CO2 emission factor (metric tons CO2 per
barrel).
%Volj = Percent volume of feedstock ‘‘j’’ that
is petroleum-based.
PO 00000
paragraph (g)(1) or (2) of this section, as
appropriate.
(1) A reporting party using
Calculation Methodology 1 of this
subpart to determine the emission factor
of a petroleum product shall calculate
the CO2 emissions associated with that
product using Equation MM–7 of this
section in place of Equation MM–1 of
this section.
(Eq. MM-7)
For refiners, this volume only includes
products ex refinery gate.
EFi = Petroleum product-specific CO2
emission factor (metric tons CO2 per
barrel) from MM–1.
%Voli = Percent volume of product ‘‘i’’ that
is petroleum-based.
CO 2 j = Feedstock j
Where:
CO2j = Annual potential CO2 emissions from
the complete combustion or oxidation of
each non-crude feedstock ‘‘j’’ (metric
tons).
Feedstockj = Total annual volume of a
petroleum product ‘‘j’’ that enters the
refinery as a feedstock to be further
(Eq. MM-6)
(g) In the event that some portion of
a petroleum product or feedstock is
biomass-based and was not derived by
co-processing biomass and petroleum
feedstocks together (i.e., the petroleum
product or feedstock was produced by
blending a petroleum-based product
with a biomass-based product), the
reporting party shall calculate emissions
for the petroleum product or feedstock
according to one of the methods in
CO 2i = Product i
Where:
CO2i = Annual potential CO2 emissions from
the complete combustion or oxidation of
petroleum product ‘‘i’’ (metric tons).
Producti = Total annual volume of petroleum
product ‘‘i’’ produced, imported, or
exported by the reporting party (barrels).
(44/12)
(3) A reporter using Calculation
Methodology 2 of this subpart to
determine the emission factor of a
petroleum product must calculate the
CO2 emissions associated with that
product using Equation MM–9 of this
section in place of Equation MM–1 of
this section.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.176</MATH>
EF = Density
Where:
EF = Emission factor of petroleum or natural
gas product or non-crude feedstock
(metric tons CO2 per barrel).
Density = Density of petroleum product or
natural gas liquid or non-crude feedstock
(metric tons per barrel).
Wt% = Percent of total mass that carbon
represents in petroleum product or
natural gas liquid or non-crude
feedstock.
44/12 = Conversion factor for carbon to
carbon dioxide.
(Eq. MM-5)
EP10AP09.175</MATH>
CO 2 x = ∑ ( CO 2i )
either of the calculation methodologies
described in paragraphs (f)(1) or (f)(2) of
this section. The same calculation
methodology must be used for the entire
volume of the product for the reporting
year.
(1) Calculation Methodology 1. Use
the appropriate default CO2 emission
factors listed in column C of Tables
MM–1 and MM–2 of this subpart.
(2) Calculation Methodology 2.
Develop emission factors according to
Equation MM–6 of this section using
direct measurements of density and
carbon share according to methods set
forth in § 98.394(c) or a combination of
direct measurements and default factors
listed in columns A and B of Tables
MM–1 and MM–2 of this subpart.
EP10AP09.174</MATH>
(e) Importers and exporters shall
calculate total CO2 emissions from all
petroleum products and natural gas
liquids imported or exported,
respectively, using Equations MM–1
and MM–5 of this section.
EP10AP09.173</MATH>
Where:
CO2r = Total annual potential CO2 emissions
from the complete combustion or
oxidation of all petroleum products and
natural gas liquids (ex refinery gate)
minus non-crude feedstocks and any
biomass to be co-processed with
petroleum feedstocks.
CO2i = Annual potential CO2 emissions from
the complete combustion or oxidation of
each petroleum product or natural gas
liquid ‘‘i’’ (metric tons).
CO2j = Annual potential CO2 emissions from
the complete combustion or oxidation of
each non-crude feedstock ‘‘j’’ (metric
tons).
CO2m = Annual potential CO2 emissions from
the complete combustion or oxidation of
biomass ‘‘m’’ (metric tons).
(Eq. MM-4)
EP10AP09.172</MATH>
16716
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(h) Refiners shall use the most
appropriate default CO2 emission factor
(EFm) for biomass in Table MM–3 to
calculate CO2 emissions in paragraph (c)
of this section.
§ 98.394 Monitoring and QA/QC
requirements.
(a) The quantity of petroleum
products, natural gas liquids, biomass,
and all feedstocks shall be determined
using either a flow meter or tank gauge,
depending on the reporters existing
equipment and preferences.
(1) For flow meters any one of the
following test methods can be used to
determine quantity:
(i) Ultra-sonic flow meter: AGA
Report No. 9 (2007)
(ii) Turbine meters: American
National Standards Institute, ANSI/
ASME MFC–4M–1986
(iii) Orifice meters: American
National Standards Institute, AINSI/API
2530 (also called AGA–3) (1991)
(iv) Coriolis meters: ASME MFC–11
(2006)
(2) For tank gauges any one of the
following test methods can be used to
determine quantity:
(i) API–2550: Measurements and
Calibration of Petroleum Storage Tanks
(1965)
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
%Volm )
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM–3 that most closely represents the
component of product ‘‘i’’ that is
biomass-based.
%Volm = Percent volume of petroleum
product ‘‘i’’ that is biomass-based.
CO 2 j = ( Feedstock j
Where:
CO2j = Annual potential CO2 emissions from
the complete combustion or oxidation of
non-crude feedstock ‘‘j’’ (metric tons).
Feedstockj = Total annual volume of noncrude feedstock ‘‘j’’ that enters the
refinery as a feedstock to be further
refined or otherwise used on site
(barrels). Any waste feedstock (see
definitions) that enters the refinery must
also be included.
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM–3 of subpart MM that most closely
represents the component of product ‘‘i’’
that is biomass-based.
%Volm = Percent volume of non-crude
feedstock ‘‘j’’ that is biomass-based.
EFm
EFj ) − ( Feedstock i
EFm
% Volm )
(ii) API MPMS 2.2: A Manual of
Petroleum Measurement Standards
(1995)
(iii) API–653: Tank Inspection,
Repair, Alteration and Reconstruction,
3rd edition (2008)
(b) All flow meters and tank gauges
shall be calibrated prior to use for
reporting, using a suitable method
published by a consensus standards
organization (e.g., ASTM, ASME, API,
or NAESB). Alternatively, calibration
procedures specified by the flow meter
manufacturer may be used. Product flow
meters and tank gauges shall be
recalibrated either annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
(c) For Calculation Methodology 2 of
this subpart, samples of each petroleum
product and natural gas liquid shall be
taken each month for the reporting year.
The composite sample shall be tested at
the end of the reporting year using
ASTM D1298 (2003), ASTM D1657–02
(2007), ASTM D4052–96 (2002)el,
ASTM D5002–99 (2005), or ASTM
D5004–89 (2004)el for density, as
appropriate, and ASTM D5291 (2005) or
ASTM D6729–(2004)el for carbon share,
as appropriate (see Technical Support
Document). Reporters must sample
seasonal gasoline each month of the
season and then test the composite
sample at the end of the season.
§ 98.395 Procedures for estimating
missing data.
Whenever a metered or qualityassured value of the quantity of
petroleum products, natural gas liquids,
biomass, or feedstocks during any
period is unavailable, a substitute data
value for the missing quantity
measurement shall be used in the
calculations contained in § 98.393.
(a) For marine-imported and exported
refined and semi-refined products, the
reporting party shall attempt to
reconcile any differences between ship
and shore volume readings. If the
PO 00000
Frm 00271
Fmt 4701
Sfmt 4702
(Eq. MM-9)
(4) A refiner using Calculation
Methodology 2 of this subpart to
determine the emission factor of a noncrude petroleum feedstock must
calculate the CO2 emissions associated
with that feedstock using Equation MM–
10 in place of Equation MM–2 of this
section.
( Eq. MM-10)
reporting party is unable to reconcile
the readings, the higher of the two
volume values shall be used for
emission calculation purposes.
(b) For pipeline imported and
exported refined and semi-refined
products, the last valid volume reading
based on the company’s established
procedures for purposes of product
tracking and billing shall be used. If the
pipeline experiences substantial
variations in flow rate, the average of
the last valid volume reading and the
next valid volume reading shall be used
for emission calculation purposes.
(c) For petroleum refineries, the last
valid volume reading based on the
facility’s established procedures for
purposes of product tracking and billing
shall be used. If substantial variation in
the flow rate is observed, the average of
the last and the next valid volume
reading shall be used for emission
calculation purposes.
§ 98.396
Data reporting requirements.
In addition to the information
required by § 98.3(c), the following
requirements apply.
(a) Refiners shall report the following
information for each facility:
(1) CO2 emissions in metric tons for
each petroleum product and natural gas
liquid (ex refinery gate), calculated
according to § 98.393(a) or (g).
(2) CO2 emissions in metric tons for
each petroleum product or natural gas
liquid that enters the refinery annually
as a feedstock to be further refined or
otherwise used on site, calculated
according to § 98.393(b) or (g).
(3) CO2 emissions in metric tons from
each type of biomass feedstock coprocessed with petroleum feedstocks,
calculated according to § 98.393(c).
(4) The total sum of CO2 emissions
from all products, calculated according
to § 98.393(d).
(5) The total volume of each
petroleum product and natural gas
liquid associated with the CO2
emissions reported in paragraphs (a)(1)
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.178</MATH>
Where:
CO2i = Annual potential CO2 emissions from
the complete combustion or oxidation of
product ‘‘i’’ (metric tons).
Producti = Total annual volume of petroleum
product ‘‘i’’ produced, imported, or
exported by the reporting party (barrels).
For refiners, this volume only includes
products ex refinery gate.
EFi ) − ( Product i
EP10AP09.177</MATH>
CO 2i = ( Product i
16717
16718
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
and (2) of this section, seperately, and
the volume of the biomass-based
component of each petroleum product
reported in this paragraph that was
produced by blending a petroleumbased product with a biomass-based
product. If a determination cannot be
made whether the material is a
petroleum product or a natural gas
liquid, it shall be reported as a
petroleum product.
(6) The total volume of any biomass
co-processed with a petroleum product
associated with the CO2 emissions
reported in paragraph (a)(3) of this
section.
(7) The measured density and/or mass
carbon share for any petroleum product
or natural gas liquid for which CO2
emissions were calculated using
Calculation Methodology 2 of this
subpart, along with the selected method
from § 98.394(c) and the calculated EF.
(8) The total volume of each distillate
fuel oil product or feedstock reported in
paragraph (a)(5) of this section that
contains less than 15 ppm sulfur
content and is free from marker solvent
yellow 124 and dye solvent red 164.
(9) All of the following information
for all crude oil feedstocks used at the
refinery:
(i) Batch volume (in standard barrels).
(ii) API gravity of the batch.
(iii) Sulfur content of the batch.
(iv) Country of origin of the batch.
(b) In addition to the information
required by § 98.3(c), each importer
shall report all of the following
information at the corporate level:
(1) CO2 emissions in metric tons for
each imported petroleum product and
natural gas liquid, calculated according
to § 98.393(a).
(2) Total sum of CO2 emissions,
calculated according to § 98.393(e).
(3) The total volume of each imported
petroleum product and natural gas
liquid associated with the CO2
emissions reported in paragraph (b)(1)
of this section as well as the volume of
the biomass-based component of each
petroleum product reported in this
paragraph that was produced by
blending a petroleum-based product
with a biomass-based product. If you
cannot determine whether the material
is a petroleum product or a natural gas
liquid, you shall report it as a petroleum
product.
(4) The measured density and/or mass
carbon share for any imported
petroleum product or natural gas liquid
for which CO2 emissions were
calculated using Calculation
Methodology 2 of this subpart, along
with the selected method from
§ 98.394(c) and the calculated EF.
(5) The total volume of each distillate
fuel oil product reported in paragraph
(b)(1) of this section that contains less
than 15 ppm sulfur content and is free
from marker solvent yellow 124 and dye
solvent red 164.
(c) In addition to the information
required by § 98.3(c), each exporter shall
report all of the following information at
the corporate level:
(1) CO2 emissions in metric tons for
each exported petroleum product and
natural gas liquid, calculated according
to § 98.393(a).
(2) Total sum of CO2 emissions,
calculated according to § 98.393(e).
(3) The total volume of each exported
petroleum product and natural gas
liquid associated with the CO2
emissions reported in paragraph (c)(1) of
this section as well as the volume of the
biomass-based component of each
petroleum product reported in this
paragraph that was produced by
blending a petroleum-based product
with a biomass-based product. If you
cannot determine whether the material
is a petroleum product or a natural gas
liquid, you shall report it as a petroleum
product.
(4) The measured density and/or mass
carbon share for any petroleum product
or natural gas liquid for which CO2
emissions were calculated using
Calculation Methodology 2 of this
subpart, along with the selected method
from § 98.394(c) and the calculated EF.
(5) The total volume of each distillate
fuel oil product reported in paragraph
(c)(1) of this section that contains less
than 15 ppm sulfur content and is free
from marker solvent yellow 124 and dye
solvent red 164.
§ 98.397
Records that must be retained.
(a) Any reporter described in § 98.391
shall retain copies of all reports
submitted to EPA under § 98.396. In
addition, any reporter under this
subpart shall maintain sufficient records
to support information contained in
those reports, including but not limited
to information on the characteristics of
their feedstocks and products.
(b) Reporters shall maintain records to
support volumes that are reported under
this part, including records
documenting any estimations of missing
metered data. For all volumes of
petroleum products, natural gas liquids,
biomass, and feedstocks, reporters shall
maintain meter and other records
normally maintained in the course of
business to document product and
feedstock flows.
(c) Reporters shall also retain
laboratory reports, calculations and
worksheets used to estimate the CO2
emissions of the volumes reported
under this part.
(d) Estimates of missing data shall be
documented and records maintained
showing the calculations.
(e) Reporters described in this subpart
shall also retain all records described in
§ 98.3(g).
§ 98.398
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE MM–1 OF SUBPART MM—DEFAULT CO2 FACTORS FOR PETROLEUM PRODUCTS 1, 2
Column A:
density
(metric tons/
bbl)
Refined and semi-refined petroleum products
Column B:
carbon share
(% of mass)
Column C:
emission
factor
(metric tons
CO2/bbl)
[Column A *
Column B/100
* 44/12]
Motor Gasoline 3
Conventional—Summer ........................................................................................................
Conventional—Winter ...........................................................................................................
Reformulated—Summer .......................................................................................................
Reformulated—Winter ..........................................................................................................
Finished Aviation Gasoline ...................................................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00272
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
0.12
0.12
0.12
0.12
0.11
10APP2
86.96
86.96
86.60
86.60
85.00
0.38
0.37
0.37
0.37
0.35
16719
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE MM–1 OF SUBPART MM—DEFAULT CO2 FACTORS FOR PETROLEUM PRODUCTS 1, 2—Continued
Column A:
density
(metric tons/
bbl)
Refined and semi-refined petroleum products
Column B:
carbon share
(% of mass)
Column C:
emission
factor
(metric tons
CO2/bbl)
[Column A *
Column B/100
* 44/12]
Blendstocks
RBOB ....................................................................................................................................
CBOB ....................................................................................................................................
Others ...................................................................................................................................
0.12
0.12
0.11
86.60
85.60
84.00
0.38
0.37
0.34
0.13
0.12
0.12
0.12
0.12
0.12
0.12
0.13
0.12
0.13
37.50
64.90
64.90
68.20
70.50
70.50
70.60
86.30
85.80
86.01
0.17
0.29
0.29
0.29
0.30
0.31
0.30
0.41
0.39
0.41
0.13
0.13
0.15
0.13
0.13
0.15
0.14
0.16
86.40
86.34
86.47
86.40
86.34
86.47
85.81
85.68
0.43
0.43
0.46
0.43
0.43
0.46
0.43
0.49
0.12
0.13
0.12
0.14
0.13
0.07
0.16
0.07
0.06
0.09
0.08
0.08
0.09
0.11
0.09
0.09
0.11
0.14
0.14
0.12
0.13
0.15
0.16
0.14
84.11
86.34
84.76
85.80
85.29
92.28
83.47
24.40
80.00
85.71
81.80
85.71
82.80
85.71
82.80
85.71
83.70
85.49
85.49
85.70
85.80
85.80
85.70
85.70
0.36
0.43
0.38
0.45
0.40
0.23
0.50
0.06
0.17
0.28
0.24
0.26
0.28
0.35
0.27
0.29
0.32
0.43
0.43
0.37
0.41
0.46
0.51
0.45
Oxygenates
Methanol ...............................................................................................................................
GTBA ....................................................................................................................................
t-butanol ................................................................................................................................
MTBE ....................................................................................................................................
ETBE ....................................................................................................................................
TAME ....................................................................................................................................
DIPE .....................................................................................................................................
Kerosene-Type Jet Fuel .......................................................................................................
Naptha-Type Jet Fuel ...........................................................................................................
Kerosene ..............................................................................................................................
Distillate Fuel Oil
Diesel No. 1 ..........................................................................................................................
Diesel No. 2 ..........................................................................................................................
Diesel No. 4 ..........................................................................................................................
Fuel Oil No. 1 .......................................................................................................................
Fuel Oil No. 2 .......................................................................................................................
Fuel Oil No. 4 .......................................................................................................................
Residual Fuel Oil No. 5 (Navy Special) ...............................................................................
Residual Fuel Oil No. 6 (a.k.a. Bunker C) ...........................................................................
Petrochemical Feedstocks
Naphthas (< 401 °F) .............................................................................................................
Other Oils (> 401 °F) ............................................................................................................
Special Naphthas .................................................................................................................
Lubricants .............................................................................................................................
Waxes ...................................................................................................................................
Petroleum Coke ....................................................................................................................
Asphalt and Road Oil ...........................................................................................................
Still Gas ................................................................................................................................
Ethane ..................................................................................................................................
Ethylene ................................................................................................................................
Propane ................................................................................................................................
Propylene ..............................................................................................................................
Butane ..................................................................................................................................
Butylene ................................................................................................................................
Isobutane ..............................................................................................................................
Isobutylene ...........................................................................................................................
Pentanes Plus ......................................................................................................................
Miscellaneous Products ........................................................................................................
Unfinished Oils .....................................................................................................................
Naphthas ..............................................................................................................................
Kerosenes .............................................................................................................................
Heavy Gas Oils ....................................................................................................................
Residuum ..............................................................................................................................
Waste Feedstocks ................................................................................................................
1 In the case of transportation fuels blended with some portion of biomass-based fuel, the carbon share in Table MM–1 represents only the petroleum-based components.
2 Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum
product (i.e., co-processed) should be reported as the petroleum product that it most closely represents.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00273
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16720
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE MM–2 OF SUBPART MM—DEFAULT CO2 FACTORS FOR NATURAL GAS LIQUIDS
Column A:
density
tonnes/barrel
Natural gas liquids
C2+
C4+
C5+
C6+
..............................................................................................................................................
..............................................................................................................................................
..............................................................................................................................................
..............................................................................................................................................
0.08
0.10
0.11
0.11
Column B:
carbon share
(% of mass)
Column C:
computed
emission
factor
(tonnes CO2/
bbl)
[Column A *
Column B/100
* 44/12]
81.79
83.15
83.70
84.04
0.24
0.30
0.32
0.34
TABLE MM–3 OF SUBPART MM—DEFAULT CO2 FACTORS FOR BIOMASS-BASED FUEL AND BIOMASS FEEDSTOCK
Column A:
emission
factor
(tonnes CO2/
bbl)
Biomass products and feedstock
Ethanol (100%) ....................................................................................................................................................................................
Biodiesel (100%, methyl ester) ............................................................................................................................................................
Rendered Animal Fat ...........................................................................................................................................................................
Vegetable Oil .......................................................................................................................................................................................
Definition of the source category.
This supplier category consists of
natural gas processing plants and local
natural gas distribution companies.
(a) Natural Gas Processing Plants are
installations designed to separate and
recover natural gas liquids (NGLs) or
other gases and liquids from a stream of
produced natural gas through the
processes of condensation, absorption,
adsorption, refrigeration, or other
methods and to control the quality of
natural gas marketed. This does not
include field gathering and boosting
stations.
(b) Local Distribution Companies are
companies that own or operate
distribution pipelines, not interstate
pipelines or intrastate pipelines, that
physically deliver natural gas to end
users and that are regulated as separate
§ 98.401
Reporting threshold.
Any supplier of natural gas and
natural gas liquids that meets the
requirements of § 98.2(a)(4) must report
GHG emissions.
§ 98.402
GHGs to report.
(a) Natural gas processing plants must
report the CO2 emissions that would
result from the complete combustion or
oxidation of the annual quantity of
propane, butane, ethane, isobutane and
bulk NGLs sold or delivered for use off
site.
(b) Local distribution companies must
report the CO2 emissions that would
result from the complete combustion or
oxidation of the annual volumes of
natural gas provided to end-users.
CO 2 = 1 x 10−3
Where:
CO2 = Annual potential CO2 mass emissions
from the combustion of fuel (metric
tons).
Fuel = Total annual volume of fuel or
product (volume per year, typically in
Mcf for gaseous fuels and bbl for liquid
fuels).
HHV = Higher heat value of the fuel supplied
(MMBtu/Mcf or MMBtu/bbl).
EF = Fuel-specific CO2 emission factor (kg
CO2/MMBtu).
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Fuel HHV
EF
(2) Calculation Methodology 2.
Estimate CO2 emissions using Equation
NN–2.
EF
(Eq. NN- 2)
Where:
PO 00000
Frm 00274
Calculating GHG emissions.
(a) For each type of fuel or product
reported under this part, calculate the
estimated CO2 equivalent emissions
using either of Calculation Methodology
1 or 2 of this subpart:
(1) Calculation Methodology 1.
Estimate CO2 emissions using Equation
NN–1. For Equation NN–1, use the
default values for higher heating values
and CO2 emission factors in Table NN–
1 to this subpart. Alternatively, reporterspecific higher heating values and CO2
emission factors may be used, provided
they are developed using methods
outlined in § 98.404. For Equation NN–
2 of this section, use the default values
for the CO2 emission factors found in
Table NN–2 of this subpart.
Alternatively, reporter-specific CO2
emission factors may be used, provided
they are developed using methods
outlined in § 98.404.
(Eq. NN-1)
1 × 10¥3 = Conversion factor from kilograms
to metric tons (MT/kg).
CO 2 = Fuel
§ 98.403
CO2 = Annual CO2 mass emissions from the
combustion of fuel supplied (metric
tons)
Fuel = Total annual volume of fuel or
product supplied (bbl or Mcf per year)
EF = Fuel-specific CO2 emission factor (MT
CO2/bbl, or MT CO2/Mcf)
§ 98.404 Monitoring and QA/QC
requirements.
(a) The quantity of natural gas liquids
and natural gas must be determined
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.180</MATH>
§ 98.400
operating companies by State public
utility commissions or that operate as
independent municipally-owned
distribution systems.
EP10AP09.179</MATH>
Subpart NN—Suppliers of Natural Gas
and Natural Gas Liquids
0.23
0.40
0.37
0.41
16721
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
using any of the oil and gas flow meter
test methods that are in common use in
the industry and consistent with the Gas
Processors Association Technical
Manual and the American Gas
Association Gas Measurement
Committee reports.
(b) The minimum frequency of the
measurements of quantities of natural
gas liquids and natural gas shall be
based on the industry standard practices
for commercial operations. For natural
gas liquids these are measurements
taken at custody transfers summed to
the annual reportable volume. For
natural gas these are daily totals of
continuous measurements, and summed
to the annual reportable volume.
(c) All flow meters and product or
fuel composition monitors shall be
calibrated prior to the first reporting
year, using a suitable method published
by the American Gas Association Gas
Measurement Committee reports on
flow metering and heating value
calculations and the Gas Processors
Association standards on measurement
and heating value. Alternatively,
calibration procedures specified by the
flow meter manufacturer may be used.
Fuel flow meters shall be recalibrated
either annually or at the minimum
frequency specified by the
manufacturer.
(d) Reporter-specific emission factors
or higher heating values shall be
determined using industry standard
practices such as the American Gas
Association (AGA) Gas Measurement
Committee Report on heating value and
the Gas Processors Association (GPA)
Technical Standards Manual for NGL
heating value; and ASTM D–2597–94
and ASTM D–1945–03 for
compositional analysis necessary for
estimating CO2 emission factors.
§ 98.405 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the reporting of fuel
volumes and in the calculations of CO2
mass emissions is required. Therefore,
whenever a quality-assured value of the
quantity of natural gas liquids or natural
gas during any period is unavailable
(e.g., if a flow meter malfunctions), a
substitute data value for the missing
quantity measurement must be used in
the calculations according to paragraphs
(b) and (c) of this section.
(b) For NGLs, natural gas processing
plants shall substitute meter records
provided by pipeline(s) for all pipeline
receipts of NGLs; by manifests for
deliveries made to trucks or rail cars; or
metered quantities accepted by the
entities purchasing the output from the
processing plant whether by pipeline or
by truck or rail car. In cases where the
metered data from the receiving
pipeline(s) or purchasing entities are not
available, natural gas processors may
substitute estimates based on contract
quantities required to be delivered
under purchase or delivery contracts
with other parties.
(c) Natural gas local distribution
companies may substitute the metered
quantities from the delivering pipelines
for all deliveries into the distribution
system. In cases where the pipeline
metered delivery data are not available,
local distribution companies may
substitute their pipeline nominations
and scheduled quantities for the period
when metered values of actual
deliveries are not available.
(d) Estimates of missing data shall be
documented and records maintained
showing the calculations of the values
used for the missing data.
end users on the local distribution
company’s distribution system.
(2) The total annual CO2 mass
emissions associated with the volumes
in paragraph (b)(1) of this section and
calculated in accordance with § 98.403.
(3) The total natural gas volumes
received for redelivery to downstream
gas transmission pipelines and other
local distribution companies.
(4) The name and EPA and EIA
identification code of each individual
covered facility, and the name and EIA
identification code of any other enduser for which the local gas distribution
company delivered greater than or equal
to 460,000 Mcf during the calendar year,
and the total natural gas volumes
actually delivered to each of these endusers.
(5) The annual volume in Mcf of
natural gas delivered by the local
distribution company to each of the
following end-use categories. For
definitions of these categories, refer to
EIA Form 176 and Instructions.
(i) Residential consumers.
(ii) Commercial consumers.
(iii) Industrial consumers.
(iv) Electricity generating facilities.
(6) The total annual CO2 mass
emissions associated with the volumes
in paragraph (b)(5) of this section and
calculated in accordance with § 98.403.
§ 98.406
§ 98.407
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), the annual report
for each natural gas processing plant
must contain the following information.
(1) The total annual quantity in
barrels of NGLs produced for sale or
delivery on behalf of others in the
following categories: Propane, natural
butane, ethane, and isobutane, and all
other bulk NGLs as a single category.
(2) The total annual CO2 mass
emissions associated with the volumes
in paragraph (a)(1) of this section and
calculated in accordance with § 98.403.
(b) In addition to the information
required by § 98.3(c), the annual report
for each local distribution company
must contain the following information.
(1) The total annual volume in Mcf of
natural gas received by the local
distribution company for redelivery to
Records that must be retained.
In addition to the information
required by § 98.3(g), each annual report
must contain the following information:
(a) Records of all daily meter readings
and documentation to support volumes
of natural gas and NGLs that are
reported under this part.
(b) Records documenting any
estimates of missing metered data.
(c) Calculations and worksheets used
to estimate CO2 emissions for the
volumes reported under this part.
(d) Records related to the large endusers identified in § 98.406(b)(4).
(e) Records relating to measured Btu
content or carbon content.
§ 98.408
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE NN–1 OF SUBPART NN—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART
Fuel
Default high heating value factor
Natural Gas ..................................................................................
Propane ........................................................................................
Butane ..........................................................................................
1.027 MMBtu/Mcf .........................................................................
3.836 MMBtu/bbl ..........................................................................
4.326 MMBtu/bbl ..........................................................................
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00275
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
Default CO2
emission
factor (kg
CO2/
MMBtu)
53.02
63.02
64.93
16722
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
TABLE NN–1 OF SUBPART NN—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART—Continued
Default CO2
emission
factor (kg
CO2/
MMBtu)
Fuel
Default high heating value factor
Ethane ..........................................................................................
Isobutane ......................................................................................
Natural Gas Liquids ......................................................................
3.082 MMBtu/bbl ..........................................................................
3.974 MMBtu/bbl ..........................................................................
4.140 MMBtu/bbl ..........................................................................
59.58
65.08
63.20
TABLE NN–2 OF SUBPART NN—LOOKUP DEFAULT VALUES FOR CALCULATION METHODOLOGY 2 OF THIS SUBPART
Default CO2
emission
value (MT
CO2/Unit)
Fuel
Unit
Natural Gas ..................................................................................
Propane ........................................................................................
Butane ..........................................................................................
Ethane ..........................................................................................
Isobutane ......................................................................................
Natural Gas Liquids ......................................................................
Mcf ................................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Reporting threshold.
Any supplier of industrial greenhouse
gases who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
§ 98.412
GHGs to report.
You must report the GHG emissions
that would result from the release of the
nitrous oxide and each fluorinated GHG
that you produce, import, export,
transform, or destroy during the
calendar year.
§ 98.413
Calculating GHG emissions.
(a) The total mass of each fluorinated
GHG or nitrous oxide produced
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(Eq. OO-1)
p =1
Where:
P = Mass of fluorinated GHG or nitrous oxide
produced annually.
Pp = Mass of fluorinated GHG or nitrous
oxide produced over the period ‘‘p’’.
(b) The total mass of each fluorinated
GHG or nitrous oxide produced over the
period ‘‘p’’ shall be estimated by using
Equation OO–2 of this section:
Pp = O p − U p
(Eq. OO-2)
Where:
Pp = Mass of fluorinated GHG or nitrous
oxide produced over the period ‘‘p’’
(metric tons).
Op = Mass of fluorinated GHG or nitrous
oxide that is measured coming out of the
production process over the period p
(metric tons).
Up = Mass of used fluorinated GHG or nitrous
oxide that is added to the production
process upstream of the output
measurement over the period ‘‘p’’ (metric
tons).
(c) The total mass of each fluorinated
GHG or nitrous oxide transformed shall
be estimated by using Equation OO–3 of
this section:
T = FT − R
(Eq. OO-3)
Where:
T = Mass of fluorinated GHG or nitrous oxide
transformed annually (metric tons).
FT = Mass of fluorinated GHG fed into the
transformation process annually (metric
tons).
PO 00000
Frm 00276
Fmt 4701
Sfmt 4702
(d) The total mass of each fluorinated
GHG destroyed shall be estimated by
using Equation OO–4 of this section:
D = FD ∗ DE
(Eq. OO- 4)
Where:
D = Mass of fluorinated GHG destroyed
annually (metric tons).
FD = Mass of fluorinated GHG fed into the
destruction device annually (metric
tons).
DE = Destruction efficiency of the destruction
device (fraction).
§ 98.414 Monitoring and QA/QC
requirements.
(a) The mass of fluorinated GHGs or
nitrous oxide coming out of the
production process shall be measured at
least daily using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of 0.2 percent of
full scale or better.
(b) The mass of any used fluorinated
GHGs or used nitrous oxide added back
into the production process upstream of
the output measurement in paragraph
(a) of this section shall be measured at
least daily (when being added) using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better.
(c) The mass of fluorinated GHGs or
nitrous oxide fed into transformation
processes shall be measured at least
daily using flowmeters, weigh scales, or
a combination of volumetric and density
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.184</MATH>
§ 98.411
n
P = ∑ Pp
EP10AP09.183</MATH>
Definition of the source category.
(a) The industrial gas supplier source
category consists of any facility that
produces a fluorinated GHG or nitrous
oxide, any bulk importer of fluorinated
GHGs or nitrous oxide, and any bulk
exporter of fluorinated GHGs or nitrous
oxide.
(b) To produce a fluorinated GHG
means to manufacture a fluorinated
GHG from any raw material or feedstock
chemical. Producing a fluorinated GHGs
does not include the reuse or recycling
of a fluorinated GHG or the generation
of HFC–23 during the production of
HCFC–22.
(c) To produce nitrous oxide means to
produce nitrous oxide by thermally
decomposing ammonium nitrate
(NH4NO3). Producing nitrous oxide does
not include the reuse or recycling of
nitrous oxide or the creation of byproducts that are released or destroyed
at the production facility.
EP10AP09.182</MATH>
§ 98.410
R = Mass of residual, unreacted fluorinated
GHG or nitrous oxide that is
permanently removed from the
transformation process (metric tons).
EP10AP09.181</MATH>
annually shall be estimated by using
Equation OO–1 of this section:
Subpart OO—Suppliers of Industrial
Greenhouse Gases
0.054452
0.241745
0.280887
0.183626
0.258628
0.261648
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
measurements with an accuracy and
precision of 0.2 percent of full scale or
better.
(d) If unreacted fluorinated GHGs or
nitrous oxide are permanently removed
(recovered, destroyed, or emitted) from
the transformation process, the mass
removed shall be measured using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the unreacted
fluorinated GHG or nitrous oxide, the
concentration of the unreacted
fluorinated GHG or nitrous oxide shall
be measured at least daily using
equipment and methods (e.g., gas
chromatography) with an accuracy and
precision of 5 percent or better at the
concentrations of the process samples.
This concentration (mass fraction) shall
be multiplied by the mass measurement
to obtain the mass of the fluorinated
GHG or nitrous oxide permanently
removed from the transformation
process.
(e) The mass of fluorinated GHG or
nitrous oxide sent to another facility for
transformation shall be measured at
least daily using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of 0.2 percent of
full scale or better.
(f) The mass of fluorinated GHG sent
to another facility for destruction shall
be measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the fluorinated
GHG, the concentration of the
fluorinated GHG shall be measured at
least daily using equipment and
methods (e.g., gas chromatography) with
an accuracy and precision of 5 percent
or better at the concentrations of the
process samples. This concentration
(mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the fluorinated GHG sent to
another facility for destruction.
(g) The mass of fluorinated GHGs fed
into the destruction device shall be
measured at least daily using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of 0.2 percent of full scale or
better. If the measured mass includes
more than trace concentrations of
materials other than the fluorinated
GHG being destroyed, the
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
concentrations of fluorinated GHG being
destroyed shall be measured at least
daily using equipment and methods
(e.g., gas chromatography) with an
accuracy and precision of 5 percent or
better at the concentrations of the
process samples. This concentration
(mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the fluorinated GHG destroyed.
(h) For purposes of Equation OO–4,
the destruction efficiency can initially
be equated to the destruction efficiency
determined during a previous
performance test of the destruction
device or, if no performance test has
been done, the destruction efficiency
provided by the manufacturer of the
destruction device. Fluorinated GHG
production facilities that destroy
fluorinated GHGs shall conduct annual
measurements of mass flow and
fluorinated GHG concentrations at the
outlet of the thermal oxidizer in
accordance with EPA Method 18 at 40
CFR part 60, appendix A–6. Tests shall
be conducted under conditions that are
typical for the production process and
destruction device at the facility. The
sensitivity of the emissions tests shall be
sufficient to detect emissions equal to
0.01 percent of the mass of fluorinated
GHGs being fed into the destruction
device. If the test indicates that the
actual DE of the destruction device is
lower than the previously determined
DE, facilities shall either:
(1) Substitute the DE implied by the
most recent emissions test for the
previously determined DE in the
calculations in § 98.413, or
(2) Perform more extensive
performance testing of the DE of the
oxidizer and use the DE determined by
the more extensive testing in the
calculations in § 98.413.
(i) In their estimates of the mass of
fluorinated GHGs destroyed, designated
representatives of fluorinated GHG
production facilities that destroy
fluorinated GHGs shall account for any
temporary reductions in the destruction
efficiency that result from any startups,
shutdowns, or malfunctions of the
destruction device, including departures
from the operating conditions defined in
state or local permitting requirements
and/or oxidizer manufacturer
specifications.
(j) All flowmeters, weigh scales, and
combinations of volumetric and density
measurements that are used to measure
or calculate quantities that are to be
reported under this subpart shall be
calibrated using suitable NIST-traceable
standards and suitable methods
published by a consensus standards
organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively,
PO 00000
Frm 00277
Fmt 4701
Sfmt 4702
16723
calibration procedures specified by the
flowmeter, scale, or load cell
manufacturer may be used. Calibration
shall be performed prior to the first
reporting year. After the initial
calibration, recalibration shall be
performed at least annually or at the
minimum frequency specified by the
manufacturer, whichever is more
frequent.
(k) All gas chromatographs that are
used to measure or calculate quantities
that are to be reported under this
subpart shall be calibrated at least
monthly through analysis of certified
standards with known concentrations of
the same chemical(s) in the same
range(s) (fractions by mass) as the
process samples. Calibration gases
prepared from a high-concentration
certified standard using a gas dilution
system that meets the requirements
specified in Test Method 205, 40 CFR
Part 51, Appendix M may also be used.
§ 98.415 Procedures for estimating
missing data.
(a) A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever a quality-assured value of a
required parameter is unavailable (e.g.,
if a meter malfunctions), a substitute
data value for the missing parameter
shall be used in the calculations,
according to the following requirements:
(1) For each missing value of the mass
produced, fed into the production
process (for used material being
reclaimed), fed into transformation
processes, fed into destruction devices,
sent to another facility for
transformation, or sent to another
facility for destruction, the substitute
value of that parameter shall be a
secondary mass measurement. For
example, if the mass produced is
usually measured with a flowmeter at
the inlet to the day tank and that
flowmeter fails to meet an accuracy or
precision test, malfunctions, or is
rendered inoperable, then the mass
produced may be estimated by
calculating the change in volume in the
day tank and multiplying it by the
density of the product.
(2) For each missing value of
fluorinated GHG concentration, except
the annual destruction device outlet
concentration measurement specified in
§ 98.414(h), the substitute data value
shall be the arithmetic average of the
quality-assured values of that parameter
immediately preceding and immediately
following the missing data incident. If,
for a particular parameter, no qualityassured data are available prior to the
missing data incident, the substitute
data value shall be the first quality-
E:\FR\FM\10APP2.SGM
10APP2
16724
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
assured value obtained after the missing
data period. There are no missing value
allowances for the annual destruction
device outlet concentration
measurement. A re-test must be
performed if the data from the annual
destruction device outlet concentration
measurement are determined to be
unacceptable or not representative of
typical operations.
(3) Notwithstanding paragraphs (a)(1)
and (2) of this section, if the owner or
operator has reason to believe that the
methods specified in paragraphs (a)(1)
and (2) of this section are likely to
significantly under- or overestimate the
value of the parameter during the period
when data were missing, the designated
representative of the fluorinated GHG
production facility shall develop his or
her best estimate of the parameter,
documenting the methods used, the
rationale behind them, and the reasons
why the methods specified in
paragraphs (a)(1) and (2) of this section
would probably lead to a significant
under- or overestimate of the parameter.
EPA may reject the alternative estimate
and replace it with an estimate based on
the applicable method in paragraph
(a)(1) or (2) if EPA does not agree with
the rationale or method for the
alternative estimate.
§ 98.416
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information:
(a) Each fluorinated GHG or nitrous
oxide production facility shall report
the following information at the facility
level:
(1) Total mass in metric tons of each
fluorinated GHG or nitrous oxide
produced at that facility.
(2) Total mass in metric tons of each
fluorinated GHG or nitrous oxide
transformed at that facility.
(3) Total mass in metric tons of each
fluorinated GHG destroyed at that
facility.
(4) Total mass in metric tons of any
fluorinated GHG or nitrous oxide sent to
another facility for transformation.
(5) Total mass in metric tons of any
fluorinated GHG sent to another facility
for destruction.
(6) Total mass in metric tons of each
reactant fed into the production process.
(7) Total mass in metric tons of each
non-GHG reactant and by-product
permanently removed from the process.
(8) Mass of used product added back
into the production process (e.g., for
reclamation).
(9) Names and addresses of facilities
to which any nitrous oxide or
fluorinated GHGs were sent for
transformation, and the quantities
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(metric tons) of nitrous oxide and of
each fluorinated GHG that were sent to
each for transformation.
(10) Names and addresses of facilities
to which any fluorinated GHGs were
sent for destruction, and the quantities
(metric tons) of nitrous oxide and of
each fluorinated GHG that were sent to
each for destruction.
(11) Where missing data have been
estimated pursuant to § 98.415, the
reason the data were missing, the length
of time the data were missing, the
method used to estimate the missing
data, and the estimates of those data.
Where the missing data have been
estimated pursuant to § 98.415(a)(3), the
report shall explain the rationale for the
methods used to estimate the missing
data and why the methods specified in
§ 98.415(a)(1) and (2) would lead to a
significant under- or overestimate of the
parameters.
(b) A fluorinated GHG production
facility that destroys fluorinated GHGs
shall report the results of the annual
fluorinated GHG concentration
measurements at the outlet of the
destruction device, including:
(1) Flow rate of fluorinated GHG being
fed into the destruction device in kg/hr.
(2) Concentration (mass fraction) of
fluorinated GHG at the outlet of the
destruction device.
(3) Flow rate at the outlet of the
destruction device in kg/hr.
(4) Emission rate calculated from
(b)(2) and (b)(3) in kg/hr.
(c) A fluorinated GHG production
facility that destroys fluorinated GHGs
shall submit a one-time report
containing the following information:
(1) Destruction efficiency (DE) of each
destruction unit.
(2) Test methods used to determine
the destruction efficiency.
(3) Methods used to record the mass
of fluorinated GHG destroyed.
(4) Chemical identity of the
fluorinated GHG(s) used in the
performance test conducted to
determine DE.
(5) Name of all applicable federal or
state regulations that may apply to the
destruction process.
(6) If any process changes affect unit
destruction efficiency or the methods
used to record mass of fluorinated GHG
destroyed, then a revised report must be
submitted to reflect the changes. The
revised report must be submitted to EPA
within 60 days of the change.
(d) A bulk importer of fluorinated
GHGs or nitrous oxide shall submit an
annual report that summarizes their
imports at the corporate level, except for
transshipments and heels. The report
shall contain the following information
for each import:
PO 00000
Frm 00278
Fmt 4701
Sfmt 4702
(1) Total mass in metric tons of
nitrous oxide and each fluorinated GHG
imported in bulk.
(2) Total mass in metric tons of
nitrous oxide and each fluorinated GHG
imported in bulk and sold or transferred
to persons other than the importer for
use in processes resulting in the
transformation or destruction of the
chemical.
(3) Date on which the fluorinated
GHGs or nitrous oxide were imported.
(4) Port of entry through which the
fluorinated GHGs or nitrous oxide
passed.
(5) Country from which the imported
fluorinated GHGs or nitrous oxide were
imported.
(6) Commodity code of the fluorinated
GHGs or nitrous oxide shipped.
(7) Importer number for the shipment.
(8) If applicable, the names and
addresses of the persons and facilities to
which the nitrous oxide or fluorinated
GHGs were sold or transferred for
transformation, and the quantities
(metric tons) of nitrous oxide and of
each fluorinated GHG that were sold or
transferred to each facility for
transformation.
(9) If applicable, the names and
addresses of the persons and facilities to
which the nitrous oxide or fluorinated
GHGs were sold or transferred for
destruction, and the quantities (metric
tons) of nitrous oxide and of each
fluorinated GHG that were sold or
transferred to each facility for
destruction.
(e) A bulk exporter of fluorinated
GHGs or nitrous oxide shall submit an
annual report that summarizes their
exports at the corporate level, except for
transshipments and heels. The report
shall contain the following information
for each export:
(1) Total mass in metric tons of
nitrous oxide and each fluorinated GHG
exported in bulk.
(2) Names and addresses of the
exporter and the recipient of the
exports.
(3) Exporter’s Employee Identification
Number.
(4) Quantity exported by chemical in
metric tons of chemical.
(5) Commodity code of the fluorinated
GHGs and nitrous oxide shipped.
(6) Date on which, and the port from
which, fluorinated GHGs and nitrous
oxide were exported from the United
States or its territories.
(7) Country to which the fluorinated
GHGs or nitrous oxide were exported.
§ 98.417
Records that must be retained.
(a) In addition to the data required by
§ 98.3(g), the designated representative
of a fluorinated GHG production facility
shall retain the following records:
E:\FR\FM\10APP2.SGM
10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
source; or a waste, wastewater, or water
treatment process.
(2) Facilities with CO2 production
wells.
(3) Importers or exporters of bulk CO2.
(b) This source category does not
include the following:
(1) Geologic sequestration (long term
storage) of CO2.
(2) Injection and subsequent
production and/or processing of CO2 for
enhanced oil and gas recovery.
(3) Above ground storage of CO2.
(4) Transportation or distribution of
CO2 via pipelines, vessels, motor
carriers, or other means.
(5) Purification, compression, or
processing of CO2.
(6) CO2 imported or exported in
equipment.
§ 98.418
Where:
CO2 = CO2 mass emission (metric tons per
year).
CCO2 = Quarterly average CO2 concentration
in flow (wt. % CO2).
Q = Quarterly mass flow rate (metric tons per
quarter).
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart PP—Suppliers of Carbon
Dioxide
§ 98.420
Definition of the source category.
(a) The carbon dioxide (CO2) supplier
source category consists of the
following:
(1) Production process units that
capture a CO2 stream for purposes of
supplying CO2 for commercial
applications. Capture refers to the
separation and removal of CO2 from a
manufacturing process; fuel combustion
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
§ 98.421
Reporting threshold.
Any supplier of CO2 who meets the
requirements of § 98.2(a)(4) must report
GHG emissions.
§ 98.422
GHGs to report.
You must report the mass of carbon
dioxide captured from production
process units, the mass of carbon
dioxide extracted from carbon dioxide
production wells, and the mass of
carbon dioxide imported and exported
regardless of the degree of impurities in
the carbon dioxide stream.
§ 98.423
Calculating GHG emissions.
(a) Facilities with production process
units must calculate quarterly the total
mass of carbon dioxide in a carbon
dioxide stream in metric tons captured,
prior to any subsequent purification,
processing, or compressing, based on
multiplying the mass flow by the
composition data, according to Equation
PP–1 of this section. Mass flow and
composition data measurements are
made in accordance with § 98.424.
4
CO 2 = ∑ Q ∗ CCO 2
(Eq. PP-1)
p =1
(b) CO2 production well facilities
must calculate quarterly the total mass
of carbon dioxide in a carbon dioxide
stream from wells in metric tons, prior
to any subsequent purification,
processing, or compressing, based on
multiplying the mass flow by the
composition data, according to Equation
PP–1. Mass flow and composition data
measurements are made in accordance
with § 98.424.
PO 00000
Frm 00279
Fmt 4701
Sfmt 4702
(c) Importers or exporters of a carbon
dioxide stream must calculate quarterly
the total mass of carbon dioxide
imported or exported in metric tons,
based on multiplying the mass flow by
the composition data, according to
Equation PP–1. Mass flow and
composition data measurements are
made in accordance with § 98.424. The
quantities of CO2 imported or exported
in equipment, such as fire extinguishers,
need not be calculated or reported.
§ 98.424 Monitoring and QA/QC
requirements.
(a) Facilities with production process
units that capture a carbon dioxide
stream must measure on a quarterly
basis using a mass flow meter the mass
flow of the CO2 stream captured. If
production process units do not have
mass flow meters installed to measure
the mass flow of the CO2 stream
captured, measurements shall be based
on the mass flow of gas transferred off
site using a mass flow meter. In either
case, sampling also must be conducted
on at least a quarterly basis to determine
the composition of the captured or
transferred CO2 stream.
(b) Carbon dioxide production well
facilities must measure on a quarterly
basis the mass flow of the CO2 stream
extracted using a mass flow meter. If the
CO2 production wells do not have mass
flow meters installed to measure the
mass flow of the CO2 stream extracted,
measurements shall be based on mass
flow of gas transferred off site using a
mass flow meter. In either case,
sampling must be conducted on at least
a quarterly basis to determine the
composition of the extracted or
transferred carbon dioxide.
(c) Importers or exporters of bulk CO2
must measure on a quarterly basis the
mass flow of the CO2 stream imported
or exported using a mass flow meter and
must conduct sampling on at least a
quarterly basis to determine the
composition of the imported or exported
CO2 stream. If the importer of a CO2
stream does not have mass flow meters
installed to measure the mass flow of
gas imported, the measurements shall be
based on the mass flow of the imported
CO2 stream transferred off site or used
in on-site processes, as measured by
mass flow meters. If an exporter of a
CO2 stream does not have mass flow
meters installed to measure the mass
flow exported, the measurements shall
be based on the mass flow of the CO2
stream received for export, as measured
by mass flow meters. In all cases,
sampling on at least a quarterly basis
also must be conducted to determine the
composition of the CO2 stream.
E:\FR\FM\10APP2.SGM
10APP2
EP10AP09.185</MATH>
(1) Dated records of the data used to
estimate the data reported under
§ 98.416, and
(2) Records documenting the initial
and periodic calibration of the gas
chromatographs, weigh scales,
flowmeters, and volumetric and density
measures used to measure the quantities
reported under this subpart, including
the industry standards or manufacturer
directions used for calibration pursuant
to § 98.414(j) and (k).
(b) In addition to the data required by
paragraph (a) of this section, the
designated representative of a
fluorinated GHG production facility that
destroys fluorinated GHGs shall keep
records of test reports and other
information documenting the facility’s
one-time destruction efficiency report
and annual destruction device outlet
reports in § 98.416(b) and (c).
(c) In addition to the data required by
§ 98.3(g), the designated representative
of a bulk importer shall retain the
following records substantiating each of
the imports that they report:
(1) A copy of the bill of lading for the
import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by
§ 98.3(g), the designated representative
of a bulk exporter shall retain the
following records substantiating each of
the exports that they report:
(1) A copy of the bill of lading for the
export and
(2) The invoice for the import.
(e) Every person who imports a
container with a heel shall keep records
of the amount brought into the United
States that document that the residual
amount in each shipment is less than 10
percent of the volume of the container
and will:
(1) Remain in the container and be
included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
16725
16726
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
(d) Mass flow meter calibrations must
be NIST traceable.
(e) Methods to measure the
composition of the carbon dioxide
captured, extracted, transferred,
imported, or exported must conform to
applicable chemical analytical
standards. Acceptable methods include
U.S. Food and Drug Administration
food-grade specifications for carbon
dioxide (see 21 CFR 184.1250) and
ASTM standard E–1745–95 (2005).
§ 98.425 Procedures for estimating
missing data.
(a) Missing quarterly monitoring data
on mass flow of CO2 streams captured,
extracted, imported, or exported shall be
substituted with the greater of the
following values:
(1) Quarterly CO2 mass flow of gas
transferred off site measured during the
current reporting year.
(2) Quarterly or annual average values
of the monitored CO2 mass flow from
the past calendar year.
(b) Missing monitoring data on the
mass flow of the CO2 stream transferred
off site shall be substituted with the
quarterly or annual average values from
off site transfers from the past calendar
year.
(c) Missing data on composition of the
CO2 stream captured, extracted,
transferred, imported, or exported may
be substituted for with quarterly or
annual average values from the past
calendar year.
§ 98.426
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the following information.
(a) Each facility with production
process units or CO2 production wells
must report the following information:
(1) Total annual mass in metric tons
and the weighted average composition
of the CO2 stream captured, extracted, or
transferred in either gas, liquid, or solid
forms.
(2) Annual quantities in metric tons
transferred to the following end use
applications by end-use, if known:
(i) Food and beverage.
(ii) Industrial and municipal water/
wastewater treatment.
(iii) Metal fabrication, including
welding and cutting.
(iv) Greenhouse uses for plant growth.
(v) Fumigants (e.g., grain storage) and
herbicides.
(vi) Pulp and paper.
(vii) Cleaning and solvent use.
(viii) Fire fighting.
(ix) Transportation and storage of
explosives.
(x) Enhanced oil and natural gas
recovery.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
(xi) Long-term storage (sequestration).
(xii) Research and development.
(b) CO2 importers and exporters must
report the information in paragraphs
(a)(1) and (a)(2) at the corporate level.
Subpart C—[Amended]
§ 98.427
§ 1033.205 Applying for a certificate of
conformity.
Records that must be retained.
In addition to the records required by
§ 98.3(g), you must retain the records
specified in paragraphs (a) through (c) of
this section.
(a) The owner or operator of a facility
containing production process units
must retain quarterly records of
captured and transferred CO2 streams
and composition.
(b) The owner or operator of a carbon
dioxide production well facility must
maintain quarterly records of the mass
flow of the extracted and transferred
CO2 stream and composition.
(c) Importers or exporters of CO2 must
retain quarterly records of the mass flow
and composition of CO2 streams
imported or exported.
§ 98.428
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
PART 600—[AMENDED]
27. The authority citation for part 600
continues to read as follows:
Authority: 49 U.S.C. 32901–23919q, Pub.
L. 109–58.
Subpart A—[Amended]
28. Section 600.006–08 is amended by
revising paragraph (c) introductory text
and adding paragraph (c)(5) to read as
follows:
§ 600.006–08 Data and information
requirements for fuel economy vehicles.
*
*
*
*
*
(c) The manufacturer shall submit the
following data:
*
*
*
*
*
(5) Starting with the 2011 model year,
the data submitted according to
paragraphs (c)(1) through (c)(4) of this
section shall include CO2, N2O, and CH4
in addition to fuel economy. Use the
procedures specified in 40 CFR part
1065 as needed to measure N2O and
CH4. Round the test results as follows:
(i) Round CO2 to the nearest 1 g/mi.
(ii) Round N2O to the nearest 0.001 g/
mi.
(iii) Round CH4 to the nearest 0.001g/
mi.
*
*
*
*
*
30. Section 1033.205 is amended by
revising paragraph (d)(8) to read as
follows:
*
*
*
*
*
(d) * * *
(8)(i) All test data you obtained for
each test engine or locomotive. As
described in § 1033.235, we may allow
you to demonstrate compliance based
on results from previous emission tests,
development tests, or other testing
information. Include data for NOX, PM,
HC, CO, and CO2.
(ii) Starting in the 2011 model year,
report measured N2O and CH4 as
described in § 1033.235. Small
manufacturers/remanufacturers may
omit this requirement.
*
*
*
*
*
31. Section 1033.235 is amended by
adding paragraph (i) to read as follows:
§ 1033.235 Emission testing required for
certification.
*
*
*
*
*
(i) Starting in the 2011 model year,
measure N2O, and CH4 with each lowhour certification test using the
procedures specified in 40 CFR part
1065. Small manufacturers/
remanufacturers may omit this
requirement. Use the same units and
modal calculations as for your other
results to report a single weighted value
for CO2, N2O, and CH4. Round the final
values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
(3) Round CH4 to the nearest 0.001g/
kW-hr.
Subpart J—[Amended]
32. Section 1033.905 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
§ 1033.905 Symbols, acronyms, and
abbreviations.
*
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
*
*
*
*
*
*
PART 1033—[AMENDED]
PART 1039—[AMENDED]
29. The authority citation for part
1033 continues to read as follows:
33. The authority citation for part
1039 continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
PO 00000
Frm 00280
Fmt 4701
Sfmt 4702
Authority: 42 U.S.C. 7401–7671q.
E:\FR\FM\10APP2.SGM
10APP2
16727
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Subpart C—[Amended]
PART 1042—[AMENDED]
34. Section 1039.205 is amended by
revising paragraph (r) to read as follows:
Authority: 42 U.S.C. 7401–7671q.
§ 1039.205 What must I include in my
application?
*
*
*
*
*
(r) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR part 1065.
(2) Starting in the 2011 model year,
report measured CO2 , N2O, and CH4 as
described in § 1039.235. Small-volume
engine manufacturers may omit this
requirement.
*
*
*
*
*
35. Section 1039.235 is amended by
adding paragraph (g) to read as follows:
§ 1039.235 What emission testing must I
perform for my application for a certificate
of conformity?
*
*
*
*
*
(g) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit this
requirement. These measurements are
not required for NTE testing. Use the
same units and modal calculations as
for your other results to report a single
weighted value for each constituent.
Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
(3) Round CH4 to the nearest 0.001g/
kW-hr.
Subpart I—[Amended]
36. Section 1039.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
§ 1039.805 What symbols, acronyms, and
abbreviations does this part use?
*
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
VerDate Nov<24>2008
15:41 Apr 09, 2009
*
*
*
*
*
*
Jkt 217001
37. The authority citation for part
1042 continues to read as follows:
38. Section 1042.205 is amended by
revising paragraph (r) to read as follows:
Application requirements.
*
*
*
*
*
(r) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR part 1065.
(2) Starting in the 2011 model year,
report measured CO2, N2O, and CH4 as
described in § 1042.235. Small-volume
engine manufacturers may omit this
requirement.
*
*
*
*
*
39. Section 1042.235 is amended by
adding paragraph (g) to read as follows:
§ 1042.235 Emission testing required for a
certificate of conformity.
*
*
*
*
*
(g) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit this
requirement. These measurements are
not required for NTE testing. Use the
same units and modal calculations as
for your other results to report a single
weighted value for each constituent.
Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
(3) Round CH4 to the nearest 0.001g/
kW-hr.
Subpart J—[Amended]
40. Section 1042.905 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
§ 1042.905 Symbols, acronyms, and
abbreviations.
*
*
*
N2O nitrous oxide.
*
*
*
*
*
*
PART 1045—[AMENDED]
41. The authority citation for part
1045 continues to read as follows:
Subpart C—[Amended]
§ 1042.205
*
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
42. Section 1045.205 is amended by
revising paragraph (q) to read as follows:
§ 1045.205 What must I include in my
application?
*
*
*
*
*
(q) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year,
report measured CO2, N2O, and CH4 as
described in § 1045.235. Small-volume
engine manufacturers may omit this
requirement.
*
*
*
*
*
43. Section 1045.235 is amended by
adding paragraph (g) to read as follows:
§ 1045.235 What emission testing must I
perform for my application for a certificate
of conformity?
*
*
*
*
*
(g) Measure CO2, N2O, and CH4 with
each low-hour certification test using
the procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit this
requirement. These measurements are
not required for NTE testing. Use the
same units and modal calculations as
for your other results to report a single
weighted value for each constituent.
Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
(3) Round CH4 to the nearest 0.001g/
kW-hr.
PART 1048—[AMENDED]
44. The authority citation for part
1048 continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
*
*
*
*
*
CH4 methane.
*
*
*
*
*
*
*
Subpart C—[Amended]
*
*
*
45. Section 1048.205 is amended by
revising paragraph (s) to read as follows:
*
PO 00000
Frm 00281
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
16728
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
§ 1048.205 What must I include in my
application?
Subpart C—[Amended]
PART 1054—[AMENDED]
*
49. Section 1051.205 is amended by
revising paragraph (p) to read as
follows:
52. The authority citation for part
1054 continues to read as follows:
§ 1051.205 What must I include in my
application?
Subpart C—[Amended]
*
53. Section 1054.205 is amended by
revising paragraph (p) to read as
follows:
*
*
*
*
(s) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR part 1065.
(2) Starting in the 2011 model year,
report measured CO2, N2O, and CH4 as
described in § 1048.235. Small-volume
engine manufacturers may omit this
requirement.
*
*
*
*
*
46. Section 1048.235 is amended by
adding paragraph (g) to read as follows:
§ 1048.235 What emission testing must I
perform for my application for a certificate
of conformity?
*
*
*
*
*
(g) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit this
requirement. These measurements are
not required for measurements using
field-testing procedures. Use the same
units and modal calculations as for your
other results to report a single weighted
value for each constituent. Round the
final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001 g/
kW-hr.
(3) Round CH4 to the nearest 0.001g/
kW-hr.
§ 1048.805 What symbols, acronyms, and
abbreviations does this part use?
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
*
*
*
*
*
*
PART 1051—[AMENDED]
48. The authority citation for part
1051 continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
VerDate Nov<24>2008
15:41 Apr 09, 2009
*
*
*
*
*
(i) Starting in the 2011 model year,
measure CO2, N2O, and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065. Small-volume manufacturers may
omit this requirement. Use the same
units and modal calculations as for your
other results to report a single weighted
value for each constituent. Round the
final values as follows:
(1) Round CO2 to the nearest 1 g/kWhr or 1 g/km, as appropriate.
(2) Round N2O to the nearest 0.001
g/kW-hr or 0.001 g/km, as appropriate.
(3) Round CH4 to the nearest 0.001g/
kW-hr or 0.001 g/km, as appropriate.
*
*
*
*
*
(p) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year,
report measured CO2, N2O, and CH4 as
described in § 1054.235. Small-volume
engine manufacturers may omit this
requirement.
*
*
*
*
*
54. Section 1054.235 is amended by
adding paragraph (g) to read as follows:
§ 1054.235 What exhaust emission testing
must I perform for my application for a
certificate of conformity?
Jkt 217001
51. Section 1051.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
*
*
*
*
(g) Measure CO2, N2O, and CH4 with
each low-hour certification test using
the procedures specified in 40 CFR part
1065. Small-volume engine
manufacturers may omit this
requirement. Use the same units and
modal calculations as for your other
results to report a single weighted value
for each constituent. Round the final
values as follows:
(1) Round CO2 to the nearest 1 g/kWhr.
(2) Round N2O to the nearest 0.001
g/kW-hr.
(3) Round CH4 to the nearest 0.001
g/kW-hr.
55. A new part 1064 is added to
subchapter U of chapter I to read as
follows:
PART 1064—VEHICLE TESTING
PROCEDURES
*
47. Section 1048.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
*
§ 1051.235 What emission testing must I
perform for my application for a certificate
of conformity?
§ 1054.205 What must I include in my
application?
§ 1051.805 What symbols, acronyms, and
abbreviations does this part use?
Subpart I—[Amended]
*
*
*
*
*
(p) Report test results as follows:
(1) Report all test results involving
measurement of pollutants for which
emission standards apply. Include test
results from invalid tests or from any
other tests, whether or not they were
conducted according to the test
procedures of subpart F of this part. We
may ask you to send other information
to confirm that your tests were valid
under the requirements of this part and
40 CFR parts 86 and 1065.
(2) Starting in the 2011 model year,
report measured CO2, N2O, and CH4 as
described in § 1051.235. Small-volume
manufacturers may omit this
requirement.
*
*
*
*
*
50. Section 1051.235 is amended by
adding paragraph (i) to read as follows:
Authority: 42 U.S.C. 7401–7671q.
Subpart A—Applicability and general
provisions
Sec.
1064.1 Applicability.
Subpart I—[Amended]
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
PO 00000
Frm 00282
Fmt 4701
*
*
*
*
*
*
Sfmt 4702
*
Subpart B—Air Conditioning Systems
1064.201 Method for calculating emissions
due to air conditioning leakage.
E:\FR\FM\10APP2.SGM
10APP2
16729
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Authority: 42 U.S.C. 7401–7671q.
Subpart A—Applicability and General
Provisions
§ 1064.1
Applicability.
(a) This part describes procedures that
apply to testing we require for 2011 and
later model year light-duty vehicles,
light-duty trucks, and medium-duty
personal vehicles (see 40 CFR part 86).
(b) See 40 CFR part 86 for
measurement procedures related to
exhaust and evaporative emissions.
Subpart B—Air Conditioning Systems
§ 1064.201 Method for calculating
emissions due to air conditioning leakage.
Determine a refrigerant leakage rate
from vehicle-based air conditioning
units as described in this section.
(a) Emission totals. Calculate an
annual rate of refrigerant leakage from
an air conditioning system using the
following equation:
Grams/YRTOT = Grams/YRRP + Grams/
YRSP + Grams/YRFH + Grams/YRMC
+ Grams/YRC
Where:
Grams/YRRP = Emission rate for rigid pipe
connections as described in paragraph
(b) of this section.
Grams/YRSP = Emission rate for service ports
and refrigerant control devices as
described in paragraph (c) of this section.
Grams/YRFH = Emission rate for flexible
hoses as described in paragraph (d) of
this section.
Grams/YRMC = Emission rate for heat
exchangers, mufflers, receiver/driers,
and accumulators as described in
paragraph (e) of this section.
Grams/YRC = Emission rate for compressors
as described in paragraph (f) of this
section.
(b) Fittings. Determine the emission
rate for rigid pipe connections using the
following Equation:
Grams/YRRP = 0.00522 · [(125 · SO) +
(75 · SCO) + (50 · MO) + (10 · SW)
+ (5 · SWO) + (MG)]
Where:
SO = The number of single O-ring
connections.
SCO = The number of single captured O-ring
connections.
MO = The number of multiple O-ring
connections.
SW = The number of seal washer
connections.
SWO = The number of seal washer with Oring connections.
MG = The number of metal gasket
connections.
(c) Service ports and refrigerant
control devices. Determine the emission
rate for service ports and refrigerant
control devices using the following
Equation:
Grams/YRSP = (0.3 · HSSP) + (0.2 ·
LSSP) + (0.2 · STV) + (0.2 · TXV)
Where:
HSSP = The number of high side service
ports.
LSSP = The number of low side service ports.
STV = The total number of switches,
transducers, and expansion valves.
TXV = The number of TXV refrigerant
control devices.
(d) Flexible hoses. Determine the
permeation emission rate for each
segment of flexible hose using the
following Equation, then add those
values to calculate a total emission rate
for the system:
Grams/YRFH = 0.00522 · (3.14159 · ID ·
L · ER)
Where:
ID = Inner diameter of hose, in millimeters.
L = Length of hose, in millimeters.
ER = Emission rate per unit internal surface
area of the hose, in g/mm2. Select the
appropriate value from the following
table:
ER
Material/configuration
High-pressure
side
Rubber .........................................................................................................................................................
Standard barrier or veneer hose .................................................................................................................
Ultra-low permeation barrier or veneer hose ..............................................................................................
(e) Heat exchangers, mufflers,
receiver/driers, and accumulators. Use
an emission rate of 0.5 grams per year
as a combined value for all heat
exchangers, mufflers, receiver/driers,
and accumulators (Grams/YRMC).
(f) Compressors. Determine the
emission rate for compressors using the
following equation:
Grams/YRC = 0.00522 · [(300 · OHS) +
(200 · MHS) + (150 · FAP) + (100 · GHS)
+ (1500/SSL)]
Where:
OHS = The number of O-ring housing seals.
MHS = The number of molded housing seals.
FAP = The number of fitting adapter plates.
GHS = The number of gasket housing seals.
SSL = The number of lips on shaft seal (for
belt-driven compressors only).
PART 1065—[AMENDED]
56. The authority citation for part
1065 continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Subpart C—[Amended]
57. A new § 1065.257 is added to
subpart C to read as follows:
§ 1065.257
analyzer.
Nondispersive N2O infrared
(a) Application. Use a nondispersive
infrared (NDIR) analyzer to measure
N2O concentrations in diluted exhaust
for batch sampling. Batch sampling may
be performed in a single bag covering all
phases of the test procedure.
(b) Component requirements. We
recommend that you use an NDIR
analyzer that meets the specifications in
Table 1 of § 1065.205. Note that your
NDIR-based system must meet the
calibration and verification in
§ 1065.357 and it must also meet the
linearity verification in § 1065.307. You
may use an NDIR analyzer that has
compensation algorithms that are
functions of other gaseous
measurements and the engine’s known
or assumed fuel properties. The target
value for any compensation algorithm is
PO 00000
Frm 00283
Fmt 4701
Sfmt 4702
0.0216
0.0054
0.00225
Low-pressure side
0.0144
0.0036
0.00167
0.0 % (that is, no bias high and no bias
low), regardless of the uncompensated
signal’s bias.
(c) Artifact formation, SO2, and H2O
removal. SO2, NOX, and H2O have been
shown to react in the sample bag to form
N2O. SO2 and H2O must therefore be
sequentially removed from the sample
gas before the sample enters the bag.
SO2 can be neutralized from the sample
gas by passing the sample through a
sorbent cartridge packed with 120 cc of
a 10:1 ratio of 18–20 mesh sand and
Ca(OH)2. This sorbent works only in the
presence of H2O so the H2O sorbent
cartridge must be located downstream of
the SO2 sorbent cartridge. H2O can be
removed by passing the sample through
a sorbent cartridge packed with 120 cc
of P2O5.
58. A new § 1065.357 is added to
subpart D to read as follows:
§ 1065.357 CO and Co2 interference
verification for N2O NDIR analyzers.
(a) Scope and frequency. If you
measure CO using an NDIR analyzer,
E:\FR\FM\10APP2.SGM
10APP2
16730
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
verify the amount of CO and Co2
interference after initial analyzer
installation and after major
maintenance.
(b) Measurement principles. CO and
Co2 can positively interfere with an
NDIR analyzer by causing a response
similar to N2O. If the NDIR analyzer
uses compensation algorithms that
utilize measurements of other gases to
meet this interference verification,
simultaneously conduct these other
measurements to test the compensation
algorithms during the analyzer
interference verification.
(c) System requirements. A N2O NDIR
analyzer must have combined CO and
Co2 interference that is within ±2
percent of the flow-weighted mean
concentration of N2O expected at the
standard, though we strongly
recommend a lower interference that is
within ±1 percent.
(d) Procedure. Perform the
interference verification as follows:
(1) Start, operate, zero, and span the
N2O NDIR analyzer as you would before
an emission test.
(2) Introduce a CO span to the
analyzer.
(3) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the transfer
line and to account for analyzer
response.
(4) While the analyzer measures the
sample’s concentration, record its
output for 30 seconds. Calculate the
arithmetic mean of this data.
(5) Scale the CO interference by
multiplying this mean value (from
paragraph (d)(7) of this section) by the
ratio of expected CO to span gas CO
concentration. In other words, estimate
the flow-weighted mean dry
concentration of CO expected during
testing, and then divide this value by
the concentration of CO in the span gas
used for this verification. Then multiply
this ratio by the mean value recorded
during this verification (from paragraph
(d)(7) of this section).
(6) Repeat the steps in paragraphs
(d)(2) through (5) of this section, but
with a CO2 analytical gas mixture
instead of CO and without humidifying
the sample through the distilled water
in a sealed vessel.
(7) Add together the CO and CO2scaled result of paragraphs (d)(5) and (6)
of this section.
(8) The analyzer meets the
interference verification if the result of
paragraph (d)(7) of this section is within
±2 percent of the flow-weighted mean
concentration of N2O expected at the
standard.
(e) Exceptions. The following
exceptions apply:
(1) You may omit this verification if
you can show by engineering analysis
that for your N2O sampling system and
your emission calculations procedures,
the combined CO, CO2, and H2O
interference for your N2O NDIR analyzer
always affects your brake-specific N2O
emission results within ±0.5 percent of
the applicable N2O standard.
(2) You may use a N2O NDIR analyzer
that you determine does not meet this
verification, as long as you try to correct
the problem and the measurement
deficiency does not adversely affect
your ability to show that engines
comply with all applicable emission
standards.
Subpart H—[Amended]
59. Section 1065.750 is amended by
revising paragraph (a)(1)(ii) and adding
paragraph (a)(3)(xi) to read as follows:
§ 1065.750
Analytical gases.
*
*
*
*
*
(a) * * *
(1) * * *
(ii) Contamination as specified in the
following table:
TABLE 1 OF § 1065.750—GENERAL SPECIFICATIONS FOR PURIFIED GASES
Constituent
Purified synthetic air 1
THC (C1 equivalent) ...........................................
CO ......................................................................
CO2 ....................................................................
O2 .......................................................................
NOX ....................................................................
N2O ....................................................................
<0.05 μmol/mol ................................................
<1 μmol/mol .....................................................
<10 μmol/mol ...................................................
0.205 to 0.215 mol/mol ....................................
<0.02 μmol/mol ................................................
<0.05 μmol/mol ................................................
1 We
Purified N21
<0.05 μmol/mol
<1 μmol/mol.
<10 μmol/mol.
<2 μmol/mol.
<0.02 μmol/mol.
<0.05 μmol/mol.
do not require these levels of purity to be NIST-traceable.
§ 1065.1001
*
*
*
*
*
(3) * * *
(xi) N2O, balance purified N2.
*
*
*
*
*
Subpart K—[Amended]
60. Section 1065.1001 is amended by
revising the definition for ‘‘Oxides of
nitrogen’’ to read as follows:
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
Definitions.
*
*
*
*
*
Oxides of nitrogen means NO and
NO2 as measured by the procedures
specified in § 1065.270. Oxides of
nitrogen are expressed quantitatively as
if the NO is in the form of NO2, such
that you use an effective molar mass for
all oxides of nitrogen equivalent to that
of NO2.
*
*
*
*
*
PO 00000
Frm 00284
Fmt 4701
Sfmt 4702
61. Section 1065.1005 is amended by
adding items to the table in paragraph
(b) in alphanumeric order to read as
follows:
§ 1065.1005 Symbols, abbreviations,
acronyms, and units of measure.
*
*
*
(b) * * *
E:\FR\FM\10APP2.SGM
10APP2
*
*
16731
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules
Symbol
Species
*
*
*
*
*
Ca(OH)2 .................................................................................................... calcium hydroxide
*
*
*
*
*
*
*
P2O5 .......................................................................................................... phosphorous pentoxide
*
*
*
*
*
*
SO2 ........................................................................................................... sulfur dioxide
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
[FR Doc. E9–5711 Filed 4–9–09; 8:45 am]
BILLING CODE 6560–50–P
VerDate Nov<24>2008
15:41 Apr 09, 2009
Jkt 217001
PO 00000
Frm 00285
Fmt 4701
Sfmt 4702
E:\FR\FM\10APP2.SGM
10APP2
]]>Agencies
[Federal Register Volume 74, Number 68 (Friday, April 10, 2009)]
[Proposed Rules]
[Pages 16448-16731]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-5711]
[[Page 16447]]
-----------------------------------------------------------------------
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 86, 87, 89, et al.
Mandatory Reporting of Greenhouse Gases; Proposed Rule
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 /
Proposed Rules
[[Page 16448]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 86, 87, 89, 90, 94, 98, 600, 1033, 1039, 1042, 1045,
1048, 1051, 1054, and 1065
[EPA-HQ-OAR-2008-0508; FRL-8782-1]
RIN 2060-A079
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: EPA is proposing a regulation to require reporting of
greenhouse gas emissions from all sectors of the economy. The rule
would apply to fossil fuel suppliers and industrial gas suppliers, as
well as to direct greenhouse gas emitters. The proposed rule does not
require control of greenhouse gases, rather it requires only that
sources above certain threshold levels monitor and report emissions.
DATES: Comments must be received on or before June 9, 2009. There will
be two public hearings. One hearing was held on April 6 and 7, 2009, in
the Washington, DC, area (One Potomac Yard, 2777 S. Crystal Drive,
Arlington, VA 22202). One hearing will be on April 16, 2009 in
Sacramento, CA (Sacramento Convention Center, 1400 J Street,
Sacramento, CA 95814). The April 16, 2009 hearing will begin at 9 a.m.
local time.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2008-0508, by one of the following methods:
Federal eRulemaking Portal: https://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: a-and-r-Docket@epa.gov.
Fax: (202) 566-1741.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mailcode 6102T, Attention Docket ID No. EPA-HQ-OAR-2008-0508,
1200 Pennsylvania Avenue, NW., Washington, DC 20460.
Hand Delivery: EPA Docket Center, Public Reading Room, EPA
West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC
20004. Such deliveries are only accepted during the Docket's normal
hours of operation, and special arrangements should be made for
deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2008-0508. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
https://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be CBI or
other information whose disclosure is restricted by statute. Do not
submit information that you consider to be CBI or otherwise protected
through https://www.regulations.gov or e-mail. The https://www.regulations.gov Web site is an ``anonymous access'' system, which
means EPA will not know your identity or contact information unless you
provide it in the body of your comment. If you send an e-mail comment
directly to EPA without going through https://www.regulations.gov your
e-mail address will be automatically captured and included as part of
the comment that is placed in the public docket and made available on
the Internet. If you submit an electronic comment, EPA recommends that
you include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses.
Docket: All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in https://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC.
This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address:
GHGReportingRule@epa.gov. For technical information, contact the
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: ghgmrr@epa.gov. To obtain information about the public
hearings or to register to speak at the hearings, please go to https://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively,
contact Carole Cook at 202-343-9263.
SUPPLEMENTARY INFORMATION:
Additional Information on Submitting Comments: To expedite review
of your comments by Agency staff, you are encouraged to send a separate
copy of your comments, in addition to the copy you submit to the
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC,
20460, telephone (202) 343-9263, e-mail GHGReportingRule@epa.gov.
Regulated Entities. The Administrator determines that this action
is subject to the provisions of CAA section 307(d). See CAA section
307(d)(1)(V) (the provisions of section 307(d) apply to ``such other
actions as the Administrator may determine.''). This is a proposed
regulation. If finalized, these regulations would affect owners and
operators of fuel and chemicals suppliers, direct emitters of GHGs and
manufacturers of mobile sources and engines. Regulated categories and
entities would include those listed in Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
Examples of affected
Category NAICS facilities
------------------------------------------------------------------------
General Stationary Fuel .............. Facilities operating
Combustion Sources. boilers, process
heaters, incinerators,
turbines, and internal
combustion engines:
211 Extractors of crude
petroleum and natural
gas.
321 Manufacturers of lumber
and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries,
and manufacturers of
coal products.
[[Page 16449]]
316, 326, 339 Manufacturers of rubber
and miscellaneous
plastic products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of motor
vehicle parts and
accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational services.
Electricity Generation......... 221112 Fossil-fuel fired
electric generating
units, including units
owned by Federal and
municipal governments
and units located in
Indian Country.
Adipic Acid Production......... 325199 Adipic acid
manufacturing
facilities.
Aluminum Production............ 331312 Primary Aluminum
production facilities.
Ammonia Manufacturing.......... 325311 Anhydrous and aqueous
ammonia manufacturing
facilities.
Cement Production.............. 327310 Owners and operators of
Portland Cement
manufacturing plants.
Electronics Manufacturing...... 334111 Microcomputers
manufacturing
facilities.
334413 Semiconductor,
photovoltaic (solid-
state) device
manufacturing
facilities.
334419 LCD unit screens
manufacturing
facilities.
.............. MEMS manufacturing
facilities.
Ethanol Production............. 325193 Ethyl alcohol
manufacturing
facilities.
Ferroalloy Production.......... 331112 Ferroalloys
manufacturing
facilities.
Fluorinated GHG Production..... 325120 Industrial gases
manufacturing
facilities.
Food Processing................ 311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
Glass Production............... 327211 Flat glass
manufacturing
facilities.
327213 Glass container
manufacturing
facilities.
327212 Other pressed and blown
glass and glassware
manufacturing
facilities.
HCFC-22 Production and HFC-23 325120 Chlorodifluoromethane
Destruction. manufacturing
facilities.
Hydrogen Production............ 325120 Hydrogen manufacturing
facilities.
Iron and Steel Production...... 331111 Integrated iron and
steel mills, steel
companies, sinter
plants, blast
furnaces, basic oxygen
process furnace shops.
Lead Production................ 331419 Primary lead smelting
and refining
facilities.
331492 Secondary lead smelting
and refining
facilities.
Lime Production................ 327410 Calcium oxide, calcium
hydroxide, dolomitic
hydrates manufacturing
facilities.
Magnesium Production........... 331419 Primary refiners of
nonferrous metals by
electrolytic methods.
331492 Secondary magnesium
processing plants.
Nitric Acid Production......... 325311 Nitric acid
manufacturing
facilities.
Oil and Natural Gas Systems.... 486210 Pipeline transportation
of natural gas.
221210 Natural gas
distribution
facilities.
325212 Synthetic rubber
manufacturing
facilities.
Petrochemical Production....... 32511 Ethylene dichloride
manufacturing
facilities.
325199 Acrylonitrile, ethylene
oxide, methanol
manufacturing
facilities.
325110 Ethylene manufacturing
facilities.
325182 Carbon black
manufacturing
facilities.
Petroleum Refineries........... 324110 Petroleum refineries.
Phosphoric Acid Production..... 325312 Phosphoric acid
manufacturing
facilities.
Pulp and Paper Manufacturing... 322110 Pulp mills.
322121 Paper mills.
322130 Paperboard mills.
Silicon Carbide Production..... 327910 Silicon carbide
abrasives
manufacturing
facilities.
Soda Ash Manufacturing......... 325181 Alkalies and chlorine
manufacturing
facilities.
Sulfur Hexafluoride (SF6) from 221121 Electric bulk power
Electrical Equipment. transmission and
control facilities.
Titanium Dioxide Production.... 325188 Titanium dioxide
manufacturing
facilities.
Underground Coal Mines......... 212113 Underground anthracite
coal mining
operations.
212112 Underground bituminous
coal mining
operations.
Zinc Production................ 331419 Primary zinc refining
facilities.
331492 Zinc dust reclaiming
facilities, recovering
from scrap and/or
alloying purchased
metals.
Landfills...................... 562212 Solid waste landfills.
221320 Sewage treatment
facilities.
322110 Pulp mills.
322121 Paper mills.
322122 Newsprint mills.
322130 Paperboard mills.
311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
Wastewater Treatment........... 322110 Pulp mills.
322121 Paper mills.
322122 Newsprint mills.
322130 Paperboard mills.
[[Page 16450]]
311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
325193 Ethanol manufacturing
facilities.
324110 Petroleum refineries.
Manure Management.............. 112111 Beef cattle feedlots.
112120 Dairy cattle and milk
production facilities.
112210 Hog and pig farms.
112310 Chicken egg production
facilities.
112330 Turkey Production.
112320 Broilers and Other Meat
type Chicken
Production.
Suppliers of Coal and Coal- 212111 Bituminous, and lignite
based Products. coal surface mining
facilities.
212113 Anthracite coal mining
facilities.
212112 Underground bituminous
coal mining
facilities.
Suppliers of Coal Based Liquids 211111 Coal liquefaction at
Fuels. mine sites.
Suppliers of Petroleum Products 324110 Petroleum refineries.
Suppliers of Natural Gas and 221210 Natural gas
NGLs. distribution
facilities.
211112 Natural gas liquid
extraction facilities.
Suppliers of Industrial GHGs... 325120 Industrial gas
manufacturing
facilities.
Suppliers of Carbon Dioxide 325120 Industrial gas
(CO2). manufacturing
facilities.
Mobile Sources................. 336112 Light-duty vehicles and
trucks manufacturing
facilities.
333618 Heavy-duty, non-road,
aircraft, locomotive,
and marine diesel
engine manufacturing.
336120 Heavy-duty vehicle
manufacturing
facilities.
336312 Small non-road, and
marine spark-ignition
engine manufacturing
facilities.
336999 Personal watercraft
manufacturing
facilities.
336991 Motorcycle
manufacturing
facilities.
------------------------------------------------------------------------
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
regulated by this action. Table 1 of this preamble lists the types of
facilities that EPA is now aware could be potentially affected by this
action. Other types of facilities not listed in the table could also be
subject to reporting requirements. To determine whether your facility
is affected by this action, you should carefully examine the
applicability criteria found in proposed 40 CFR part 98, subpart A. If
you have questions regarding the applicability of this action to a
particular facility, consult the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.
Many facilities that would be affected by the proposed rule have
GHG emissions from multiple source categories listed in Table 1 of this
preamble. Table 2 of this preamble has been developed as a guide to
help potential reporters subject to the mandatory reporting rule
identify the source categories (by subpart) that they may need to (1)
consider in their facility applicability determination, and (2) include
in their reporting. For each source category, activity, or facility
type (e.g., electricity generation, aluminum production), Table 2 of
this preamble identifies the subparts that are likely to be relevant.
The table should only be seen as a guide. Additional subparts may be
relevant for a given reporter. Similarly, not all listed subparts would
be relevant for all reporters.
Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
Source category (and main applicable Subparts recommended for review
subpart) to determine applicability
------------------------------------------------------------------------
General Stationary Fuel Combustion General Stationary Fuel
Sources. Combustion.
Electricity Generation................. General Stationary Fuel
Combustion, Electricity
Generation, Suppliers of CO2,
Electric Power Systems.
Adipic Acid Production................. Adipic Acid Production, General
Stationary Fuel Combustion.
Aluminum Production.................... General Stationary Fuel
Combustion.
Ammonia Manufacturing.................. General Stationary Fuel
Combustion, Hydrogen, Nitric
Acid, Petroleum Refineries,
Suppliers of CO2.
Cement Production...................... General Stationary Fuel
Combustion, Suppliers of CO2.
Electronics Manufacturing.............. General Stationary Fuel
Combustion.
Ethanol Production..................... General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Ferroalloy Production.................. General Stationary Fuel
Combustion.
Fluorinated GHG Production............. General Stationary Fuel
Combustion.
Food Processing........................ General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Glass Production....................... General Stationary Fuel
Combustion.
HCFC-22 Production and HFC-23 General Stationary Fuel
Destruction. Combustion.
Hydrogen Production.................... General Stationary Fuel
Combustion, Petrochemicals,
Petroleum Refineries,
Suppliers of Industrial GHGs,
Suppliers of CO2.
Iron and Steel Production.............. General Stationary Fuel
Combustion, Suppliers of CO2.
Lead Production........................ General Stationary Fuel
Combustion.
Lime Manufacturing..................... General Stationary Fuel
Combustion.
[[Page 16451]]
Magnesium Production................... General Stationary Fuel
Combustion.
Nitric Acid Production................. General Stationary Fuel
Combustion, Adipic Acid.
Oil and Natural Gas Systems............ General Stationary Fuel
Combustion, Petroleum
Refineries, Suppliers of
Petroleum Products, Suppliers
of Natural Gas and NGL,
Suppliers of CO2.
Petrochemical Production............... General Stationary Fuel
Combustion, Ammonia, Petroleum
Refineries.
Petroleum Refineries................... General Stationary Fuel
Combustion, Hydrogen,
Landfills, Wastewater
Treatment, Suppliers of
Petroleum Products.
Phosphoric Acid Production............. General Stationary Fuel
Combustion.
Pulp and Paper Manufacturing........... General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Silicon Carbide Production............. General Stationary Fuel
Combustion.
Soda Ash Manufacturing................. General Stationary Fuel
Combustion.
Sulfur Hexafluoride (SF6) from General Stationary Fuel
Electrical Equipment. Combustion.
Titanium Dioxide Production............ General Stationary Fuel
Combustion.
Underground Coal Mines................. General Stationary Fuel
Combustion, Suppliers of Coal.
Zinc Production........................ General Stationary Fuel
Combustion.
Landfills.............................. General Stationary Fuel
Combustion, Ethanol, Food
Processing, Petroleum
Refineries, Pulp and Paper.
Wastewater Treatment................... General Stationary Fuel
Combustion, Ethanol, Food
Processing, Petroleum
Refineries, Pulp and Paper.
Manure Management...................... General Stationary Fuel
Combustion.
Suppliers of Coal...................... General Stationary Fuel
Combustion, Underground Coal
Mines.
Suppliers of Coal-based Liquid Fuels... Suppliers of Coal, Suppliers of
Petroleum Products.
Suppliers of Petroleum Products........ General Stationary Fuel
Combustion, Oil and Natural
Gas Systems.
Suppliers of Natural Gas and NGLs...... General Stationary Fuel
Combustion, Oil and Natural
Gas Systems, Suppliers of CO2.
Suppliers of Industrial GHGs........... General Stationary Fuel
Combustion, Hydrogen
Production, Suppliers of CO2.
Suppliers of Carbon Dioxide (CO2)...... General Stationary Fuel
Combustion, Electricity
Generation, Ammonia, Cement,
Hydrogen, Iron and Steel,
Suppliers of Industrial GHGs.
Mobile Sources......................... General Stationary Fuel
Combustion.
------------------------------------------------------------------------
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
A/C air conditioning
AERR Air Emissions Reporting Rule
ANPR advance notice of proposed rulemaking
ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BLS Bureau of Labor Statistics
CAA Clean Air Act
CAFE Corporate Average Fuel Economy
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CDX central data exchange
CEMS continuous emission monitoring system(s)
CERR Consolidated Emissions Reporting Rule
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CHP combined heat and power
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DE destruction efficiency
DOD U.S. Department of Defense
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
DE destruction efficiency
DRE destruction or removal efficiency
ECOS Environmental Council of the States
EGUs electrical generating units
EIA Energy Information Administration
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EU European Union
FTP Federal Test Procedure
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC-22 chlorodifluoromethane (or CHClF2)
HCFCs hydrochlorofluorocarbons
HCl hydrogen chloride
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
ISO International Organization for Standardization
kg kilograms
LandGEM Landfill Gas Emissions Model
LCD liquid crystal display
LDCs local natural gas distribution companies
LEDs light emitting diodes
LNG liquified natural gas
LPG liquified petroleum gas
MEMS microelectricomechanical system
mmBtu/hr millions British thermal units per hour
MMTCO2e million metric tons carbon dioxide equivalent
MSHA Mine Safety and Health Administration
MSW municipal solid waste
MW megawatts
N2O nitrous oxide
NAAQS national ambient air quality standard
NACAA National Association of Clean Air Agencies
NAICS North American Industry Classification System
NEI National Emissions Inventory
NESHAP national emission standards for hazardous air pollutants
NF3 nitrogen trifluoride
NGLs natural gas liquids
NIOSH National Institute for Occupational Safety and Health
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act of 1995
O3 ozone
ODS ozone-depleting substance(s)
OMB Office of Management and Budget
ORIS Office of Regulatory Information Systems
PFCs perfluorocarbons
PIN personal identification number
POTWs publicly owned treatment works
PSD Prevention of Significant Deterioration
PV photovoltaic
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
RFA Regulatory Flexibility Act
RFS Renewable Fuel Standard
RGGI Regional Greenhouse Gas Initiative
[[Page 16452]]
RIA regulatory impact analysis
SAE Society of Automotive Engineers
SAR IPCC Second Assessment Report
SBREFA Small Business Regulatory Enforcement Fairness Act
SF6 sulfur hexafluoride
SFTP Supplemental Federal Test Procedure
SI international system of units
SIP State Implementation Plan
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TOC total organic carbon
TRI Toxic Release Inventory
TSCA Toxics Substances Control Act
TSD technical support document
U.S. United States
UIC underground injection control
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
USDA U.S. Department of Agriculture
USGS U.S. Geological Survey
VMT vehicle miles traveled
VOC volatile organic compound(s)
WBCSD World Business Council for Sustainable Development
WCI Western Climate Initiative
WRI World Resources Institute
XML eXtensible Markup Language
Table of Contents
I. Background
A. What Are GHGs?
B. What Is Climate Change?
C. Statutory Authority
D. Inventory of U.S. GHG Emissions and Sinks
E. How does this proposal relate to U.S. government and other
climate change efforts?
F. How does this proposal relate to EPA's Climate Change ANPR?
G. How was this proposed rule developed?
II. Summary of Existing Federal, State, and Regional Emission
Reporting Programs
A. Federal Voluntary GHG Programs
B. Federal Mandatory Reporting Programs
C. EPA Emissions Inventories
D. Regional and State Voluntary Programs for GHG Emissions
Reporting
E. State and Regional Mandatory Programs for GHG Emissions
Reporting and Reduction
F. How the Proposed Mandatory GHG Reporting Program is Different
From the Federal and State Programs EPA Reviewed
III. Summary of the General Requirements of the Proposed Rule
A. Who must report?
B. Schedule for Reporting
C. What do I have to report?
D. How do I submit the report?
E. What records must I retain?
IV. Rationale for the General Reporting, Recordkeeping and
Verification Requirements That Apply to All Source Categories
A. Rationale for Selection of GHGs To Report
B. Rationale for Selection of Source Categories To Report
C. Rationale for Selection of Thresholds
D. Rationale for Selection of Level of Reporting
E. Rationale for Selecting the Reporting Year
F. Rationale for Selecting the Frequency of Reporting
G. Rationale for the Emissions Information to Report
H. Rationale for Monitoring Requirements
I. Rationale for Selecting the Recordkeeping Requirements
J. Rationale for Verification Requirements
K. Rationale for Selection of Duration of the Program
V. Rationale for the Reporting, Recordkeeping and Verification
Requirements for Specific Source Categories
A. Overview of Reporting for Specific Source Categories
B. Electricity Purchases
C. General Stationary Fuel Combustion Sources
D. Electricity Generation
E. Adipic Acid Production
F. Aluminum Production
G. Ammonia Manufacturing
H. Cement Production
I. Electronics Manufacturing
J. Ethanol Production
K. Ferroalloy Production
L. Fluorinated GHG Production
M. Food Processing
N. Glass Production
O. HCFC-22 Production and HFC-23 Destruction
P. Hydrogen Production
Q. Iron and Steel Production
R. Lead Production
S. Lime Manufacturing
T. Magnesium Production
U. Miscellaneous Uses of Carbonates
V. Nitric Acid Production
W. Oil and Natural Gas Systems
X. Petrochemical Production
Y. Petroleum Refineries
Z. Phosphoric Acid Production
AA. Pulp and Paper Manufacturing
BB. Silicon Carbide Production
CC. Soda Ash Manufacturing
DD. Sulfur Hexafluoride (SF6) from Electrical
Equipment
EE. Titanium Dioxide Production
FF. Underground Coal Mines
GG. Zinc Production
HH. Landfills
II. Wastewater Treatment
JJ. Manure Management
KK. Suppliers of Coal
LL. Suppliers of Coal-Based Liquid Fuels
MM. Suppliers of Petroleum Products
NN. Suppliers of Natural Gas and Natural Gas Liquids
OO. Suppliers of Industrial GHGs
PP. Suppliers of Carbon Dioxide (CO2)
QQ. Mobile Sources
VI. Collection, Management, and Dissemination of GHG Emissions Data
A. Purpose
B. Data Collection
C. Data Management
D. Data Dissemination
VII. Compliance and Enforcement
A. Compliance Assistance
B. Role of the States
C. Enforcement
VIII. Economic Impacts of the Proposed Rule
A. How are compliance costs estimated?
B. What are the costs of this proposed rule?
C. What are the economic impacts of the proposed rule?
D. What are the impacts of the proposed rule on small entities?
E. What are the benefits of the proposed rule for society?
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Background
The proposed rule would require reporting of annual emissions of
carbon dioxide (CO2), methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), perfluorochemicals (PFCs), and other
fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated
ethers (HFEs)). The proposed rule would apply to certain downstream
facilities that emit GHGs (primarily large facilities emitting 25,000
tpy of CO2 equivalent GHG emissions or more) and to upstream
suppliers of fossil fuels and industrial GHGs, as well as to
manufacturers of vehicles and engines. Reporting would be at the
facility level, except certain suppliers and vehicle and engine
manufacturers would report at the corporate level.
This preamble is broken into several large sections, as detailed
above in the Table of Contents. Throughout the preamble we explicitly
request comment on a variety of issues. The paragraph below describes
the layout of the preamble and provides a brief summary of each
section. We also highlight particular issues on which, as indicated
later in the preamble, we would specifically be interested in receiving
comments.
The first section of this preamble contains the basic background
information about greenhouse gases and climate change. It also
describes the origin of this proposal, our legal authority and how this
proposal relates to other efforts to address emissions of greenhouse
gases. In this section we
[[Page 16453]]
would be particularly interested in receiving comment on the
relationship between this proposal and other government efforts.
The second section of this preamble describes existing Federal,
State, Regional mandatory and voluntary GHG reporting programs and how
they are similar and different to this proposal. Again, similar to the
previous section, we would like comments on the interrelationship of
this proposal and existing GHG reporting programs.
The third section of this preamble provides an overview of the
proposal itself, while the fourth section provides the rationale for
each decision the Agency made in developing the proposal, including key
design elements such as: (i) Source categories included, (ii) the level
of reporting, (iii) applicability thresholds, (iv) reporting and
monitoring methods, (v) verification, (vi) frequency and (vii) duration
of reporting. Furthermore, in this section, EPA explains the
distinction between upstream and downstream reporters, describes why it
is necessary to collect data at multiple points, and provides
information on how different data would be useful to inform different
policies. As stated in the fourth section, we solicit comment on each
design element of the proposal generally.
The fifth section of this preamble looks at the same key design
elements for each of the source categories covered by the proposal.
Thus, for example, there is a specific discussion regarding appropriate
applicability thresholds, reporting and monitoring methodologies and
reporting and recordkeeping requirements for each source category. Each
source category describes the proposed options for each design element,
as well as the other options considered. In addition to the general
solicitation for comment on each design element generally and for each
source category, throughout the fifth section there are specific issues
highlighted on which we solicit comment. Please refer to the specific
source category of interest for more details.
The sixth section of this preamble explains how EPA would collect,
manage and disseminate the data, while the seventh section describes
the approach to compliance and enforcement. In both sections the role
of the States is discussed, as are requests for comment on that role.
Finally, the eighth section provides the summary of the impacts and
costs from the Regulatory Impact Analysis and the last section walks
through the various statutory and executive order requirements
applicable to rulemakings.
A. What Are GHGs?
The proposed rule would cover the major GHGs that are directly
emitted by human activities. These include CO2,
CH4, N2O, HFCs, PFCs, SF6, and other
specified fluorinated compounds (e.g., HFEs) used in boutique
applications such as electronics and anesthetics. These gases influence
the climate system by trapping in the atmosphere heat that would
otherwise escape to space. The GHGs vary in their capacity to trap
heat. The GHGs also vary in terms of how long they remain in the
atmosphere after being emitted, with the shortest-lived GHG remaining
in the atmosphere for roughly a decade and the longest-lived GHG
remaining for up to 50,000 years. Because of these long atmospheric
lifetimes, all of the major GHGs become well mixed throughout the
global atmosphere regardless of emission origin.
Global atmospheric CO2 concentration increased about 35
percent from the pre-industrial era to 2005. The global atmospheric
concentration of CH4 has increased by 148 percent from pre-
industrial levels, and the N2O concentration has increased
18 percent. The observed increase in concentration of these gases can
be attributed primarily to human activities. The atmospheric
concentration of industrial fluorinated gases--HFCs, PFCs,
SF6--and other fluorinated compounds are relatively low but
are increasing rapidly; these gases are entirely anthropogenic in
origin.
Due to sheer quantity of emissions, CO2 is the largest
contributor to GHG concentrations followed by CH4.
Combustion of fossil fuels (e.g., coal, oil, gas) is the largest source
of CO2 emissions in the U.S. The other GHGs are emitted from
a variety of activities. These emissions are compiled by EPA in the
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory) and
reported to the UNFCCC \1\ on an annual basis.\2\ A more detailed
discussion of the Inventory is provided in Section I.D below.
---------------------------------------------------------------------------
\1\ For more information about the UNFCCC, please refer to:
https://www.unfccc.int. See Articles 4 and 12 of the UNFCCC treaty.
Parties to the Convention, by ratifying, ``shall develop,
periodically update, publish and make available * * * national
inventories of anthropogenic emissions by sources and removals by
sinks of all greenhouse gases not controlled by the Montreal
Protocol, using comparable methodologies * * *''.
\2\ The U.S. submits the Inventory of U.S. Greenhouse Gas
Emissions and Sinks to the Secretariat of the UNFCCC as an annual
reporting requirement. The UNFCCC treaty, ratified by the U.S. in
1992, sets an overall framework for intergovernmental efforts to
tackle the challenge posed by climate change. The U.S. has submitted
the GHG inventory to the United Nations every year since 1993. The
annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is
consistent with national inventory data submitted by other UNFCCC
Parties, and uses internationally accepted methods for its emission
estimates.
---------------------------------------------------------------------------
Because GHGs have different heat trapping capacities, they are not
directly comparable without translating them into common units. The
GWP, a metric that incorporates both the heat-trapping ability and
atmospheric lifetime of each GHG, can be used to develop comparable
numbers by adjusting all GHGs relative to the GWP of CO2.
When quantities of the different GHGs are multiplied by their GWPs, the
different GHGs can be compared on a CO2e basis. The GWP of
CO2 is 1.0, and the GWP of other GHGs are expressed relative
to CO2. For example, CH4 has a GWP of 21, meaning
each metric ton of CH4 emissions would have 21 times as much
impact on global warming (over a 100-year time horizon) as a metric ton
of CO2 emissions. The GWPs of the other gases are listed in
the proposed rule, and range from the hundreds up to 23,900 for
SF6.\3\ Aggregating all GHGs on a CO2e basis at
the source level allows a comparison of the total emissions of all the
gases from one source with emissions from other sources.
---------------------------------------------------------------------------
\3\ EPA has chosen to use GWPs published in the IPCC SAR
(furthermore referenced as ``SAR GWP values''). The use of the SAR
GWP values allows comparability of data collected in this proposed
rule to the national GHG inventory that EPA compiles annually to
meet U.S. commitments to the UNFCCC. To comply with international
reporting standards under the UNFCCC, official emission estimates
are to be reported by the U.S. and other countries using SAR GWP
values. The UNFCCC reporting guidelines for national inventories
were updated in 2002 but continue to require the use of GWPs from
the SAR. The parties to the UNFCCC have also agreed to use GWPs
based upon a 100-year time horizon although other time horizon
values are available. For those fluorinated compounds included in
this proposal that not listed in the SAR, EPA is using the most
recent available GWPs, either the IPCC Third Assessment Report or
Fourth Assessment Report. For more specific information about the
GWP of specific GHGs, please see Table A-1 in the proposed 40 CFR
part 98, subpart A.
---------------------------------------------------------------------------
For additional information about GHGs, climate change, climate
science, etc. please see EPA's climate change Web site found at https://www.epa.gov/climatechange/.
B. What Is Climate Change?
Climate change refers to any significant changes in measures of
climate (such as temperature, precipitation, or wind) lasting for an
extended period. Historically, natural factors such as volcanic
eruptions and changes in the amount of energy released from the sun
have affected the earth's climate. Beginning in the late 18th century,
human activities associated with the industrial revolution
[[Page 16454]]
have also changed the composition of the earth's atmosphere and very
likely are influencing the earth's climate.\4\ The heating effect
caused by the buildup of GHGs in our atmosphere enhances the Earth's
natural greenhouse effect and adds to global warming. As global
temperatures increase other elements of the climate system, such as
precipitation, snow and ice cover, sea levels, and weather events,
change. The term ``climate change,'' which encompasses these broader
effects, is often used instead of ``global warming.''
---------------------------------------------------------------------------
\4\ IPCCC: Climate Change 2007: The Physical Science Basis,
February 2, 2007 (https://www.ipcc.ch/).
---------------------------------------------------------------------------
According to the IPCC, warming of the climate system is
``unequivocal,'' as is now evident from observations of increases in
global average air and ocean temperatures, widespread melting of snow
and ice, and rising global average sea level. Global mean surface
temperatures have risen by 0.74 [deg]C (1.3 [deg]F) over the last 100
years. Global mean surface temperature was higher during the last few
decades of the 20th century than during any comparable period during
the preceding four centuries. U.S. temperatures also warmed during the
20th and into the 21st century; temperatures are now approximately 0.56
[deg]C (1.0 [deg]F) warmer than at the start of the 20th century, with
an increased rate of warming over the past 30 years. Most of the
observed increase in global average temperatures since the mid-20th
century is very likely due to the observed increase in anthropogenic
GHG concentrations.
According to different scenarios assessed by the IPCC, average
global temperature by end of this century is projected to increase by
1.8 to 4.0 [deg]C (3.2 to 7.2 [deg]F) compared to the average
temperature in 1990. The uncertainty range of this estimate is 1.1 to
6.4 [deg]C (2.0 to 11.5 [deg]F). Future projections show that, for most
scenarios assuming no additional GHG emission reduction policies,
atmospheric concentrations of GHGs are expected to continue climbing
for most if not all of the remainder of this century, with associated
increases in average temperature. Overall risk to human health, society
and the environment increases with increases in both the rate and
magnitude of climate change.
For additional information about GHGs, climate change, climate
science, etc. please see EPA's climate change Web site found at https://www.epa.gov/climatechange/.
C. Statutory Authority
On December 26, 2007, President Bush signed the FY2008 Consolidated
Appropriations Act which authorized funding for EPA to ``develop and
publish a draft rule not later than 9 months after the date of
enactment of this Act, and a final rule not later than 18 months after
the date of enactment of this Act, to require mandatory reporting of
GHG emissions above appropriate thresholds in all sectors of the
economy of the United States.'' Consolidated Appropriations Act, 2008,
Public Law 110-161, 121 Stat 1844, 2128 (2008).
The accompanying joint explanatory statement directed EPA to ``use
its existing authority under the Clean Air Act'' to develop a mandatory
GHG reporting rule. ``The Agency is further directed to include in its
rule reporting of emissions resulting from upstream production and
downstream sources, to the extent that the Administrator deems it
appropriate.'' EPA has interpreted that language to confirm that it may
be appropriate for the Agency to exercise its CAA authority to require
reporting of the quantity of fuel or chemical that is produced or
imported from upstream sources such as fuel suppliers, as well as
reporting of emissions from facilities (downstream sources) that
directly emit GHGs from their processes or from fuel combustion, as
appropriate. The joint explanatory statement further states that
``[t]he Administrator shall determine appropriate thresholds of
emissions above which reporting is required, and how frequently reports
shall be submitted to EPA. The Administrator shall have discretion to
use existing reporting requirements for electric generating units''
under section 821 of the 1990 CAA Amendments.
EPA is proposing this rule under its existing CAA authority. EPA
also proposes that the rule require the reporting of the GHG emissions
resulting from the quantity of fossil fuel or industrial gas that is
produced or imported from upstream sources such as fuel suppliers, as
well as reporting of GHG emissions from facilities (downstream sources)
that directly emit GHGs from their processes or from fuel combustion,
as appropriate. This proposed rule would also establish appropriate
thresholds and frequency for reporting.
Section 114(a)(1) of the CAA authorizes the Administrator to, inter
alia, require certain persons (see below) on a one-time, periodic or
continuous basis to keep records, make reports, undertake monitoring,
sample emissions, or provide such other information as the
Administrator may reasonably require. This information may be required
of any person who (i) owns or operates an emission source, (ii)
manufactures control or process equipment, (iii) the Administrator
believes may have information necessary for the purposes set forth in
this section, or (iv) is subject to any requirement of the Act (except
for manufacturers subject to certain title II requirements). The
information may be required for the purposes of developing an
implementation plan, an emission standard under sections 111, 112 or
129, determining if any person is in violation of any standard or
requirement of an implementation plan or emissions standard, or
``carrying out any provision'' of the Act (except for a provision of
title II with respect to manufacturers of new motor vehicles or new
motor vehicle engines).\5\ Section 208 of the CAA provides EPA with
similar broad authority regarding the manufacturers of new motor
vehicles or new motor vehicle engines, and other persons subject to the
requirements of parts A and C of title II.
---------------------------------------------------------------------------
\5\ Although there are exclusions in section 114(a)(1) regarding
certain title II requirements applicable to manufacturers of new
motor vehicle and motor vehicle engines, section 208 authorizes the
gathering of information related to those areas.
---------------------------------------------------------------------------
The scope of the persons potentially subject to a section 114(a)(1)
information request (e.g., a person ``who the Administrator believes
may have information necessary for the purposes set forth in'' section
114(a)) and the reach of the phrase ``carrying out any provision'' of
the Act are quite broad. EPA's authority to request information reaches
to a source not subject to the CAA, and may be used for purposes
relevant to any provision of the Act. Thus, for example, utilizing
sections 114 and 208, EPA could gather information relevant to carrying
out provisions involving research (e.g., section 103(g)); evaluating
and setting standards (e.g., section 111); and endangerment
determinations contained in specific provisions of the Act (e.g., 202);
as well as other programs.
Given the broad scope of sections 114 and 208 of the CAA, it is
appropriate for EPA to gather the information required by this rule
because such information is relevant to EPA's carrying out a wide
variety of CAA provisions. For example, emissions from direct emitters
should inform decisions about whether and how to use section 111 to
establish NSPS for various source categories emitting GHGs, including
whether there are any additional categories of sources that should be
listed under section 111(b). Similarly, the information required of
manufacturers of mobile
[[Page 16455]]
sources should support decisions regarding treatment of those sources
under sections 202, 213 or 231 of the CAA. In addition, the information
from fuel suppliers would be relevant in analyzing whether to proceed,
and particular options for how to proceed, under section 211(c)
regarding fuels, or to inform action concerning downstream sources
under a variety of Title I or Title II provisions. For example, the
geographic distribution, production volumes and characteristics of
various fuel types and subtypes may also prove useful is setting NSPS
or Best Available Control Technology limits for some combustion
sources. Transportation distances from fuel sources to end users may be
useful in evaluating cost effectiveness of various fuel choices,
increases in transportation emissions that may be associated with
various fuel choices, as well as the overall impact on energy usage and
availability. The data overall also would inform EPA's implementation
of section 103(g) of the CAA regarding improvements in nonregulatory
strategies and technologies for preventing or reducing air pollutants.
This section, which specifically mentions CO2, highlights
energy conservation, end-use efficiency and fuel-switching as possible
strategies for consideration and the type of information collected
under this rule would be relevant. The above discussion is not a
comprehensive listing of all the possible ways the information
collected under this rule could assist EPA in carrying out any
provision of the CAA. Rather it illustrates how the information request
fits within the parameters of EPA's CAA authority.
D. Inventory of U.S. GHG Emissions and Sinks
The Inventory of U.S. Greenhouse Gas Emissions and Sinks
(Inventory), prepared by EPA's Office of Atmospheric Programs in
coordination with the Office of Transportation and Air Quality, is an
impartial, policy-neutral report that tracks annual GHG emissions. The
annual report presents historical U.S. emissions of CO2,
CH4, N2O, HFCs, PFCs, and SF6.
The U.S. submits the Inventory to the Secretariat of the UNFCCC as
an annual reporting requirement. The UNFCCC treaty, ratified by the
U.S. in 1992, sets an overall framework for intergovernmental efforts
to tackle the challenge posed by climate change. The U.S. has submitted
the GHG inventory to the United Nations every year since 1993. The
annual Inventory is consistent with national inventory data submitted
by other UNFCCC Parties, and uses internationally accepted methods for
its emission estimates.
In preparing the annual Inventory, EPA leads an interagency team
that includes DOE, USDA, DOT, DOD, the State Department, and others.
EPA collaborates with hundreds of experts representing more than a
dozen Federal agencies, academic institutions, industry associations,
consultants, and environmental organizations. The Inventory is peer-
reviewed annually by domestic experts, undergoes a 30-day public
comment period, and is also peer-reviewed annually by UNFCCC review
teams.
The most recent GHG inventory submitted to the UNFCCC, the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006 (April
2008), estimated that total U.S. GHG emissions were 7,054.2 million
metric tons of CO2e in 2006. Overall emissions have grown by
15 percent from 1990 to 2006. CO2 emissions have increased
by 18 percent since 1990. CH4 emissions have decreased by 8
percent since 1990, while N2O emissions have decreased by 4
percent since 1990. Emissions of HFCs, PFCs, and SF6 have
increased by 64 percent since 1990. The combustion of fossil fuels
(i.e., petroleum, coal, and natural gas) was the largest source of GHG
emissions in the U.S., and accounted for approximately 80 percent of
total CO2e emissions.
The Inventory is a comprehensive top-down national assessment of
national GHG emissions, and it uses top-down national energy data and
other national statistics (e.g., on agriculture). To achieve the goal
of comprehensive national emissions coverage for reporting under the
UNFCCC, most GHG emissions in the report are calculated via activity
data from national-level databases, statistics, and surveys. The use of
the aggregated national data means that the national emissions
estimates are not broken-down at the geographic or facility level. In
contrast, this reporting rule focuses on bottom-up data and individual
sources above appropriate thresholds. Although it would provide more
specific data, it would not provide full coverage of total annual U.S.
GHG emissions, as is required in the development of the Inventory
