Mandatory Reporting of Greenhouse Gases, 56260-56519 [E9-23315]
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by reference of certain publications
listed in the rule is approved by the
Director of the Federal Register as of
December 29, 2009.
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 86, 87, 89, 90, 94, 98,
1033, 1039, 1042, 1045, 1048, 1051,
1054, 1065
EPA has established a
docket for this action under Docket ID
No. EPA–HQ–OAR–2008–0508. All
documents in the docket are listed on
the www.regulations.gov Web site.
Although listed in the index, some
information is not publicly available,
e.g., confidential business information
(CBI) or other information whose
disclosure is restricted by statute.
Certain other material, such as
copyrighted material, is not placed on
the Internet and will be publicly
available only in hard copy form.
Publicly available docket materials are
available either electronically through
www.regulations.gov or in hard copy at
EPA’s Docket Center, Public Reading
Room, EPA West Building, Room 3334,
1301 Constitution Avenue, NW.,
Washington, DC 20004. 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.
ADDRESSES:
[EPA–HQ–OAR–2008–0508; FRL–8963–5]
RIN 2060–A079
Mandatory Reporting of Greenhouse
Gases
AGENCY: Environmental Protection
Agency (EPA).
ACTION: Final rule.
SUMMARY: EPA is promulgating a
regulation to require reporting of
greenhouse gas emissions from all
sectors of the economy. The final rule
applies to fossil fuel suppliers and
industrial gas suppliers, direct
greenhouse gas emitters and
manufacturers of heavy-duty and offroad vehicles and engines. The rule
does not require control of greenhouse
gases, rather it requires only that
sources above certain threshold levels
monitor and report emissions.
DATES: The final rule is effective on
December 29, 2009. The incorporation
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 and
implementation materials, please go to
the Web site www.epa.gov/
climatechange/emissions/
ghgrulemaking.html. You may also
contact the Greenhouse Gas Reporting
Rule Hotline at telephone number: (877)
444–1188; or e-mail: ghgmrr@epa.gov.
SUPPLEMENTARY INFORMATION:
Regulated Entities. The Administrator
determined that this action is subject to
the provisions of Clean Air Act (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.’’).
The final rule affects fuel and chemicals
suppliers, direct emitters of greenhouse
gases (GHGs) and manufacturers of
mobile sources and engines. Regulated
categories and entities include those
listed in Table 1 of this preamble:
TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY
Category
NAICS
Examples of affected facilities
Combustion
........................
Electricity Generation ................................
211
321
322
325
324
316, 326, 339
331
332
336
221
622
611
221112
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.
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.
Portland Cement manufacturing plants.
Ferroalloys manufacturing facilities.
Flat glass manufacturing facilities.
Glass container manufacturing facilities.
Other pressed and blown glass and glassware manufacturing facilities.
Chlorodifluoromethane manufacturing facilities.
General Stationary
Sources.
Fuel
Adipic Acid Production ..............................
Aluminum Production ................................
Ammonia Manufacturing ...........................
Cement Production ...................................
Ferroalloy Production ................................
Glass Production ......................................
325199
331312
325311
327310
331112
327211
327213
327212
325120
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HCFC–22 Production and HFC–23 Destruction.
Hydrogen Production ................................
Iron and Steel Production .........................
325120
331111
Lead Production ........................................
331419
331492
327410
325311
32511
325199
325110
Lime Production ........................................
Nitric Acid Production ...............................
Petrochemical Production .........................
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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.
Nitric acid manufacturing facilities.
Ethylene dichloride manufacturing facilities.
Acrylonitrile, ethylene oxide, methanol manufacturing facilities.
Ethylene manufacturing facilities.
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TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued
Category
NAICS
325182
324110
325312
322110
322121
322130
327910
325181
212391
325188
331419
331492
Petroleum Refineries ................................
Phosphoric Acid Production .....................
Pulp and Paper Manufacturing .................
Silicon Carbide Production .......................
Soda Ash Manufacturing ..........................
Titanium Dioxide Production .....................
Zinc Production .........................................
Municipal Solid Waste Landfills ................
562212
221320
112111
112120
112210
112310
112330
112320
211111
324110
221210
211112
325120
325120
333618
Manure Management ................................
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 .........................................
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 affected by this
action. Table 1 of this preamble lists the
types of facilities that EPA is now aware
could be potentially affected by the
reporting requirements. Other types of
facilities and suppliers not listed in the
table could also be subject to reporting
requirements. To determine whether
you are affected by this action, you
should carefully examine the
applicability criteria found in 40 CFR
part 98, subpart A or the relevant
Examples of affected 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.
Soda ash, natural, mining and/or beneficiation.
Titanium dioxide manufacturing facilities.
Primary zinc refining facilities.
Zinc dust reclaiming facilities, recovering from scrap and/or alloying purchased metals.
Solid waste landfills.
Sewage treatment facilities.
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.
Coal liquefaction at mine sites.
Petroleum refineries.
Natural gas distribution facilities.
Natural gas liquid extraction facilities.
Industrial gas manufacturing facilities.
Industrial gas 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.
criteria in the sections related to
manufacturers of heavy-duty and offroad vehicles and engines. 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 are affected by the
final 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 are
relevant for all reporters.
TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS
Source category
(and main applicable subpart)
Other subparts recommended for review to determine applicability
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General Stationary Fuel Combustion Sources.
Electricity Generation ...............................................................................
Adipic Acid Production .............................................................................
Aluminum Production ...............................................................................
Ammonia Manufacturing ...........................................................................
Cement Production ...................................................................................
Ferroalloy Production ...............................................................................
Glass Production ......................................................................................
HCFC–22 Production and HFC–23 Destruction ......................................
Hydrogen Production ................................................................................
Iron and Steel Production .........................................................................
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General Stationary Fuel Combustion, Suppliers of CO2.
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.
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.
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TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS—Continued
Source category
(and main applicable subpart)
Other subparts recommended for review to determine applicability
Lead Production .......................................................................................
Lime Manufacturing ..................................................................................
Nitric Acid Production ...............................................................................
Petrochemical Production .........................................................................
Petroleum Refineries ................................................................................
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, Adipic Acid.
General Stationary Fuel Combustion, Ammonia, Petroleum Refineries.
General Stationary Fuel Combustion, Hydrogen, Suppliers of Petroleum Products.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion.
Suppliers of Petroleum Products.
General Stationary Fuel Combustion.
General Stationary Fuel Combustion, 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.
Phosphoric Acid Production .....................................................................
Pulp and Paper Manufacturing .................................................................
Silicon Carbide Production .......................................................................
Soda Ash Manufacturing ..........................................................................
Titanium Dioxide Production ....................................................................
Zinc Production .........................................................................................
Municipal Solid Waste Landfills ................................................................
Manure Management ...............................................................................
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) ..........................................................
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Mobile Sources .........................................................................................
Judicial Review. Under section
307(b)(1) of the CAA, judicial review of
this final rule is available only by filing
a petition for review in the U.S. Court
of Appeals for the District of Columbia
Circuit by December 29, 2009. Under
CAA section 307(d)(7)(B), only an
objection to this final rule that was
raised with reasonable specificity
during the period for public comment
can be raised during judicial review.
This section also provides a mechanism
for us to convene a proceeding for
reconsideration, ‘‘[i]f the person raising
an objection can demonstrate to EPA
that it was impracticable to raise such
objection within [the period for public
comment] or if the grounds for such
objection arose after the period for
public comment (but within the time
specified for judicial review) and if such
objection is of central relevance to the
outcome of this rule.’’ Any person
seeking to make such a demonstration to
us should submit a Petition for
Reconsideration to the Office of the
Administrator, Environmental
Protection Agency, Room 3000, Ariel
Rios Building, 1200 Pennsylvania Ave.,
NW., Washington, DC 20004, with a
copy to the person listed in the
preceding FOR FURTHER INFORMATION
CONTACT section, and the Associate
General Counsel for the Air and
Radiation Law Office, Office of General
Counsel (Mail Code 2344A),
Environmental Protection Agency, 1200
Pennsylvania Ave., NW., Washington,
DC 20004. Note, under CAA section
307(b)(2), the requirements established
by this final rule may not be challenged
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separately in any civil or criminal
proceedings brought by EPA to enforce
these requirements.
Acronyms and Abbreviations. The
following acronyms and abbreviations
are used in this document.
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
CAIR Clean Air Interstate Rule
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CCS carbon capture and sequestration
CEMS continuous emission monitoring
system(s)
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
EAF electric arc furnace
ECOS Environmental Council of the States
EGUs electric generating units
EIA Energy Information Administration
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC–22 chlorodifluoromethane (or
CHClF2)
HCFCs hydrochlorofluorocarbons
HFC–23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
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HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate
Change
kg kilograms
LDCs local natural gas distribution
companies
LMP lime manufacturing plants
mmBtu/hr millions British thermal units
per hour
MSW municipal solid waste
MW megawatts
MY mileage year
N2O nitrous oxide
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
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
PSD Prevention of Significant Deterioration
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
R&D research and development
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RICE reciprocating internal combustion
engine
RIA regulatory impact analysis
SBREFA Small Business Regulatory
Enforcement Fairness Act
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scf standard cubic feet
SF6 sulfur hexafluoride
SIP State Implementation Plan
SOP standard operating procedure
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TRI Toxic Release Inventory
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
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
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Table of Contents
I. Background
A. Organization of This Preamble
B. Background on the Final Rule
C. Legal Authority
D. How does this rule relate to EPA and
U.S. government climate change efforts?
E. How does this rule relate to State and
regional programs?
II. General Requirements of the Rule
A. Summary of the General Requirements
of the Final Rule
B. Summary of the Major Changes Since
Proposal
C. Summary of Comments and Responses
on GHGs To Report
D. Summary of Comments and Responses
on Source Categories To Report
E. Summary of Comments and Responses
on Thresholds
F. Summary of Comments and Responses
on Level of Reporting
G. Summary of Comments and Responses
on Initial Reporting Year and Best
Available Monitoring Methods
H. Summary of Comments and Responses
on Frequency of Reporting and
Provisions To Cease Reporting
I. Summary of Comments and Responses
on General Content of the Annual GHG
Report
J. Summary of Comments and Responses
on Submittal Date and Making
Corrections to Annual Reports
K. Summary of Comments and Responses
on De Minimis Reporting
L. Summary of Comments and Responses
on General Monitoring Requirements
M. Summary of Comments and Responses
on General Recordkeeping Requirements
N. Summary of Comments and Responses
on Emissions Verification Approach
O. Summary of Comments and Responses
on the Role of States and Relationship of
This Rule to Other Programs
P. Summary of Comments and Responses
on Other General Rule Requirements
Q. Summary of Comments and Responses
on Statutory Authority
R. Summary of Comments and Responses
on CBI
S. Summary of Comments and Responses
on Other Legal Issues
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III. Reporting and Recordkeeping
Requirements for Specific Source
Categories
A. Overview
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. Municipal Solid Waste 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)
IV. Mobile Sources
A. Summary of Requirements of the Final
Rule
B. Summary of Changes Since Proposal
C. Summary of Comments and Responses
V. Collection, Management, and
Dissemination of GHG Emissions Data
A. Summary of Data Collection,
Management and Dissemination for the
Final Rule
B. Summary of Comments and Responses
on Collection, Management, and
Dissemination of GHG Emissions Data
VI. Compliance and Enforcement
A. Compliance and Enforcement Summary
B. Summary of Public Comments and
Responses on Compliance and
Enforcement
VII. Economic Impacts of the Rule
A. How were compliance costs estimated?
B. What are the costs of the rule?
C. What are the economic impacts of the
rule?
D. What are the impacts of the rule on
small businesses?
E. What are the benefits of the rule for
society?
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VIII. 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
K. Congressional Review Act
I. Background
A. Organization of This Preamble
This preamble is broken into several
large sections, as detailed above in the
Table of Contents. The paragraphs
below describe the layout of the
preamble and provide a brief summary
of each section.
The first section of this preamble
contains the basic background
information about the origin of this rule,
our legal authority, and how this
proposal relates to other Federal, State,
and regional efforts to address emissions
of GHGs.
The second section of this preamble
summarizes the general provisions of
the final GHG reporting rule and
identifies the major changes since
proposal. It also provides a brief
summary of public comments and
responses on key design elements such
as: (i) Source categories included, (ii)
the level of reporting, (iii) applicability
thresholds, (iv) selection of reporting
and monitoring methods, (v) emissions
verification, (vi) frequency of reporting
and (vii) duration of reporting. It also
addresses some of the legal comments
on the statutory authority for the rule
and the relationship of this rule to other
CAA programs.
The third section of this preamble
contains separate subsections
addressing each individual source
category of the proposed rule. Each
source category section contains a
summary of specific requirements of the
rule for that source category, identifies
major changes since proposal, and
briefly discusses public comments and
EPA responses specific to the source
category. For example, comments on
EPA’s general approach for selecting
monitoring methods are discussed in
Section II of this preamble, whereas,
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comments on specific monitoring
methods for individual source
categories are discussed in Section III of
this preamble.
The fourth section of this preamble
summarizes rule requirements and
addresses public comments pertaining
to mobile sources.
The fifth section of this preamble
explains how EPA plans to collect,
manage and disseminate the data, while
the sixth section describes the approach
to compliance and enforcement. In both
sections key public comments are
summarized and responses are
presented.
The seventh section provides the
summary of the cost impacts, economic
impacts, and benefits of the final rule
and discusses comments on the
regulatory impacts analyses. Finally, the
last section discusses the various
statutory and executive order
requirements applicable to this
rulemaking.
B. Background on the Final Rule
The fiscal year 2008 (FY2008)
Consolidated Appropriations Act,
signed on December 26, 2007,
authorized funding for EPA to ‘‘develop
and publish a draft rule not later than
nine months after the date of enactment
of [the] Act, and a final rule not later
than 18 months after the date of
enactment of [the] Act, to require
mandatory reporting of greenhouse gas
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 interpreted that
language to confirm that it was
appropriate for the Agency to exercise
its CAA authority to develop this
rulemaking. 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 (EGUs)’’ under section
821 of the 1990 CAA Amendments.
On April 10, 2009 (74 FR 16448), EPA
proposed the GHG reporting rule. EPA
held two public hearings, and received
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approximately 16,800 written public
comments. The public comment period
ended on June 9, 2009.
In addition to the public hearings,
EPA had an open door policy, similar to
the outreach conducted during the
development of the proposal. As a
result, EPA has met with over 4,000
people and 135 groups since proposal
signature (March 10, 2009). Details of
these meetings are available in the
docket (EPA–HQ–OAR–2008–0508).
EPA developed this final rule and
included reporting of GHGs from the
facilities that we determined
appropriately responded to the direction
in the FY2008 Consolidated
Appropriations Act 1 (e.g., capturing
approximately 85 percent of U.S. GHG
emissions through reporting by direct
emitters as well as suppliers of fossil
fuels and industrial gases and
manufacturers of heavy-duty and offroad vehicles and engines). There are,
however, many additional types of data
and reporting that the Agency deems
important and necessary to address an
issue as large and complex as climate
change (e.g., indirect emissions,
electricity use). In that sense, one could
view this final rule as narrowly focused
on certain sources of emissions and
upstream suppliers. As described in
Sections I.C and D of this preamble as
well as in the comment response
sections, there are several existing
programs at the Federal, regional and
State levels that also collect valuable
information to inform and implement
policies necessary to address climate
change. Many of these programs are
focused on cost-effectively reducing
GHG emissions through improvements
in energy efficiency and by other means.
These programs are an essential
component of the Nation’s climate
policy, and the targeted nature of this
rule should not be interpreted to mean
that the data EPA collects through this
program are the only data necessary to
support the full range of climate policies
and programs.
Today’s rule requires the reporting of
the GHG emissions that could result
from the combustion or use 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 directly emitted from
facilities (downstream sources) through
their processes and/or from fuel
combustion, as appropriate. Vehicle and
1 Consolidated Appropriations Act, 2008, Public
Law 110–161, 121 Stat. 1844, 2128. Congress
reaffirmed interest in a GHG reporting rule, and
provided additional funding, in the 2009
Appropriations Act (Consolidated Appropriations
Act, 2009, Public Law 110–329, 122 Stat. 3574–
3716).
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engine manufacturers are also required
to report emissions rate data on the
heavy-duty and off-road engines they
produce. The rule also establishes
appropriate thresholds and frequency
for reporting.
The rule requires reporting of annual
emissions of carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O),
sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and other
fluorinated gases (e.g., nitrogen
trifluoride (NF3) and hydrofluorinated
ethers (HFEs)). It also includes
provisions to ensure the accuracy of
emissions data through monitoring,
recordkeeping and verification
requirements. The rule applies to
certain downstream facilities that emit
GHGs (primarily large facilities emitting
25,000 metric tons or more of CO2
equivalent (CO2e) GHG emissions per
year) and to most upstream suppliers of
fossil fuels and industrial GHGs, as well
as to manufacturers of vehicles and
engines. Reporting is at the facility
level, except certain suppliers and
vehicle and engine manufacturers report
at the corporate level.
C. Legal Authority
As proposed, EPA is promulgating
this rule under its existing CAA
authority, specifically authorities
provided in CAA sections 114 and 208.
As discussed further below and in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Legal Issues’’, we are not
citing the FY 2008 Consolidated
Appropriations Act as the statutory
basis for this action. While that law
required that EPA spend no less than
$3.5 million on a rule requiring the
mandatory reporting of GHG emissions,
it is the CAA, not the Appropriations
Act, that EPA is citing as the authority
to gather the information required by
this rule.
Sections 114 and 208 of the CAA
provide EPA broad authority to require
the information mandated by this rule
because such data will inform and are
relevant to EPA’s carrying out a wide
variety of CAA provisions. As discussed
in the proposed rule, CAA section
114(a)(1) authorizes the Administrator
to require emissions sources, persons
subject to the CAA, or persons whom
the Administrator believes may have
necessary information to monitor and
report emissions and provide such other
information the Administrator requests
for the purposes of carrying out any
provision of the CAA (except for a
provision of title II with respect to
manufacturers of new motor vehicles or
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new motor vehicle engines).2 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. We note that
while climate change legislation
approved by the U.S. House of
Representatives would provide EPA
additional authority for a GHG registry
similar to today’s rule, and would do so
for purposes of that pending legislation,
this final rule is authorized by, and the
information being gathered by the rule
is relevant to implementing, the existing
CAA. We expect, however, that the
information collected by this final rule
will also prove useful to legislative
efforts to address GHG emissions.
As discussed in the proposal,
emissions from direct emitters should
inform decisions about whether and
how to use CAA section 111 to establish
new source performance standards
(NSPS) for various source categories
emitting GHGs, including whether there
are any additional categories of sources
that should be listed under CAA section
111(b). Similarly, the information
required of manufacturers of mobile
sources should support decisions
regarding treatment of those sources
under CAA sections 202, 213 or 231. In
addition, the information from fuel
suppliers would be relevant in
analyzing whether to proceed, and
particular options for how to proceed,
under CAA section 211(c) regarding
fuels, or to inform action concerning
downstream sources under a variety of
Title I or Title II provisions. The data
overall also would inform EPA’s
implementation of CAA section 103(g)
regarding improvements in nonregulatory strategies and technologies
for preventing or reducing air pollutants
(e.g., EPA’s voluntary GHG reduction
programs such as the non-CO2
partnership programs and ENERGY
STAR, described below in Section I.D of
this preamble and Section II of the
proposal preamble (74 FR 16448, April
10, 2009)).
D. How does this rule relate to EPA and
U.S. government climate change efforts?
This reporting rule is one specific
action EPA has taken, consistent with
the Congressional request contained in
the FY2008 Consolidated
Appropriations Act, to collect GHG
emissions data. EPA has recently
2 Although there are exclusions in CAA section
114(a)(1) regarding certain title II requirements
applicable to manufacturers of new motor vehicle
and motor vehicle engines, CAA section 208
authorizes the gathering of information related to
those areas.
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announced a number of climate change
related actions, including proposed
findings that GHG emissions from new
motor vehicles and engines contribute
to air pollution which may reasonably
be anticipated to endanger public health
and welfare (74 FR 18886, April 24,
2009, ‘‘Proposed Endangerment and
Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a)
of the Clean Air Act’’), and an intent to
regulate light duty vehicles, jointly
published with U.S. Department of
Transportation (DOT) (74 FR 24007,
May 22, 2009, ‘‘Notice of Upcoming
Joint Rulemaking To Establish Vehicle
GHG Emissions and CAFE Standards’’).
The Administrator has also announced
her reconsideration of the memo
entitled ‘‘EPA’s Interpretation of
Regulations that Determine Pollutants
Covered By Federal Prevention of
Significant Deterioration (PSD) Permit
Program’’ (73 FR 80300, December 31,
2008), and granted California’s request
for a waiver for its GHG vehicle
standard (74 FR 32744, July 8, 2009).
These are all separate actions, some of
which are related to EPA’s response to
the U.S. Supreme Court’s decision in
Massachusetts v. EPA. 127 S. Ct. 1438
(2007). This rulemaking does not
indicate EPA has made any final
decisions on pending actions. In fact the
mandatory GHG reporting program will
provide EPA, other government
agencies, and outside stakeholders with
economy-wide data on facility-level
(and in some cases corporate-level) GHG
emissions, which should assist in future
policy development.
Accurate and timely information on
GHG emissions is essential for
informing many future climate change
policy decisions. Although additional
data collection (e.g., for other source
categories or to support additional
policy or program needs) will no doubt
be required as the development of
climate policies evolves, the data
collected in this rule will provide useful
information for a variety of polices.
Through data collected under this rule,
EPA, States and the public will gain a
better understanding of the relative
emissions of specific industries across
the nation and the distribution of
emissions from individual facilities
within those industries. The facilityspecific data will also improve our
understanding of the factors that
influence GHG emission rates and
actions that facilities could in the future
or already take to reduce emissions,
including under traditional and more
flexible programs.
As discussed in more detail in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
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Comments, Legal Issues’’ and elsewhere,
EPA is promulgating this rule to gather
GHG information to assist EPA in
assessing how to address GHG
emissions and climate change under the
Clean Air Act. However, we expect that
the information will prove useful for
other purposes as well. For example,
using the rich data set provided by this
rulemaking, EPA, States and the public
will be able to track emission trends
from industries and facilities within
industries over time, particularly in
response to policies and potential
regulations. The data collected by this
rule will also improve the U.S.
government’s ability to formulate
climate policies, and to assess which
industries might be affected, and how
these industries might be affected by
potential policies. 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 and
implement emission reduction
opportunities. These data can also be
coupled with efforts at the local, State
and Federal levels to assist corporations
and facilities in determining their GHG
footprints and identifying opportunities
to reduce emissions (e.g., through
energy audits or other forms of
assistance).
This GHG reporting program
supplements and complements, rather
than duplicates, existing U.S.
government programs (e.g., climate
policy and research programs). For
example, EPA anticipates that facilitylevel GHG emissions data will lead to
improvements in the quality of the
Inventory of U.S. Greenhouse Gas
Emissions and Sinks (Inventory), which
EPA prepares annually, with input from
several other agencies, and submits to
the Secretariat of the United Nations
Framework Convention on Climate
Change (UNFCCC).
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, Energy
Star). This mandatory reporting program
has broader coverage of U.S. GHG
emissions than most voluntary
programs, which typically focus on a
specific industry and/or goal (e.g.,
reduction of CH4 emissions or
development of corporate inventories).
It will improve EPA’s understanding of
emissions from facilities not currently
included in these programs and increase
the coverage of these industries. That
said, we expect ongoing and potential
new voluntary programs to continue to
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play an important role in achieving lowcost reductions in GHG emissions.
In addition to EPA’s programs
mentioned above, U.S. Department of
Energy (DOE) EIA implements a
voluntary GHG registry under section
1605(b) of the Energy Policy Act, which
is further discussed in Section II of the
proposal preamble (74 FR 16458, April
10, 2009). 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.3 EPA’s mandatory
GHG reporting rule covers a much
broader set of reporters, primarily at the
facility rather than entity-level, but this
reporting rule is not designed with the
specific intent of reporting of emission
reductions, as is the 1605(b) program.
For additional information about
these programs, please see Sections I
and II of the preamble to the proposed
GHG reporting rule (74 FR 16454, April
10, 2009).
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E. How does this rule relate to other
State and Regional Programs?
There are several existing State and
regional GHG reporting and/or
reduction programs summarized in
Section II of the proposal preamble (74
FR 16457, April 10, 2009). These are
important programs that not only led
the way in reporting of GHG emissions
before the Federal government acted but
also assist in quantifying the GHG
reductions achieved by various policies.
Many of these programs collect different
or additional data as compared to this
rule. For example, State programs may
establish lower thresholds for reporting
or request information on areas not
addressed in EPA’s reporting rule (e.g.,
electricity use or emission related to
other indirect sources). States collecting
additional information have determined
that these data are necessary to
implement their specific climate
policies and programs. EPA agrees that
State and regional programs are crucial
to achieving emissions reductions, and
this rule does not preempt any other
programs.
EPA’s GHG reporting rule is a specific
single action that was developed in
response to the Appropriations Act, and
therefore is targeted to accomplish the
purpose of the language of the
Appropriations Act and serve EPA’s
purposes under the CAA. As State
3 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/)
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experience has demonstrated, we
recognize that in order to address the
breadth of climate change issues there
will likely be a need to collect
additional data from sources subject to
this rule as well as other sources. The
timing and nature of these additional
needs will be dependent on the types of
programs and actions the Agency has
underway or may develop and
implement in response to future policy
developments and/or new requests from
Congress. Addressing climate change
will require a suite of policies and
programs and this reporting rule is just
one effort to collect information to
inform those policies.
EPA is committed to working with
State and regional programs to
coordinate implementation of reporting
programs, reduce burden on reporters,
provide timely access to verified
emissions data, establish mechanisms to
efficiently share data, and harmonize
data systems to the extent possible. See
Section II.O of this preamble for a
summary of public comments and
responses on the role of States and the
relationship of this GHG reporting rule
to other programs. See Section VI.B of
this preamble for a summary of
comments and responses on State
delegation of rule implementation and
enforcement. As mentioned above, for
additional information about existing
State and regional programs please see
Section II of the proposal preamble (74
FR 16457, April 10, 2009) and the
docket EPA–HQ–OAR–2008–0508.
II. General Requirements of the Rule
The rule requires reporting of annual
emissions of CO2, CH4, N2O, SF6, HFCs,
PFCs, and other fluorinated gases (as
defined in 40 CFR part 98, subpart A)
in metric tons. The final 40 CFR part 98
applies to certain downstream facilities
that emit GHGs, and to certain upstream
suppliers of fossil fuels and industrial
GHGs. For suppliers, the GHG emissions
reported are the emissions that would
result from combustion or use of the
products supplied. The rule also
includes provisions to ensure the
accuracy of emissions data through
monitoring, recordkeeping and
verification requirements. Reporting is
at the facility 4 level, except that certain
4 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
than a single facility based on distinct and
independent functional groupings within
contiguous military properties.
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suppliers of fossil fuels and industrial
gases would report at the corporate
level.
In addition, GHG reporting by
manufacturers of heavy-duty and offroad vehicles and engines is required,
by incorporating new requirements into
the existing reporting requirements for
motor vehicles and engine
manufacturers in 40 CFR parts 86, 87,
89, 90, 94, 1033, 1039, 1042, 1045, 1048,
1051, 1054, and 1065. A summary of the
reporting requirements for
manufacturers of motor vehicles and
engines is contained in Section IV of
this preamble. A discussion of public
comments and responses that pertain to
motor vehicles is also contained in
Section IV of this preamble and in the
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Motor Vehicle and Engine
Manufacturers.’’
The remainder of this section
summarizes the general provisions of 40
CFR part 98, identifies changes since the
proposed rule, and summarizes key
public comments and responses on the
general requirements of the rule.
A. Summary of the General
Requirements of the Final Rule
1. Applicability
Reporters must submit annual GHG
reports for the following facilities and
supply operations.
• Any facility that contains any
source category (as defined in 40 CFR
part 98, subparts C through JJ) that is
listed below in any calendar year
starting in 2010.5 For these facilities, the
annual GHG report covers all source
categories and GHGs for which
calculation methodologies are provided
in 40 CFR part 98, subparts C through
JJ.
—Electricity generating facilities that
are subject to the Acid Rain Program
(ARP) or otherwise report CO2 mass
emissions year-round through 40 CFR
part 75.
—Adipic acid production.
—Aluminum production.
—Ammonia manufacturing.
—Cement production.
—HCFC–22 production.
—HFC–23 destruction processes that are
not co-located 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.
5 Unless otherwise noted, years and dates in this
notice refer to calendar years and dates.
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—Phosphoric acid production.
—Silicon carbide production.
—Soda ash production.
—Titanium dioxide production.
—Municipal solid waste (MSW)
landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e
or more per year, as determined
according to 40 CFR part 98, subpart
HH.
—Manure management systems that
emit CH4 and N20 (combined) in
amounts equivalent to 25,000 metric
tons CO2e or more per year, as
determined according to 40 CFR part
98, subpart JJ.
• Any facility that contains any
source category (as defined in 40 CFR
part 98, subparts C through JJ) that is
listed below and 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 in this paragraph in any
calendar year starting in 2010. For these
facilities, the annual GHG report must
cover all source categories and GHGs for
which calculation methodologies are
provided in 40 CFR part 98, subparts C
through JJ.
—Ferroalloy Production.
—Glass Production.
—Hydrogen Production.
—Iron and Steel Production.
—Lead Production.
—Pulp and Paper Manufacturing.
—Zinc Production.
• Any facility that in any calendar
year starting in 2010 meets all three of
the conditions listed in this paragraph.
For these facilities, the annual GHG
report covers emissions from stationary
fuel combustion sources only. For 2010
only, the facilities can submit an
abbreviated GHG report according to 40
CFR 98.3(d).
—The facility does not meet the
requirements described in the above
two paragraphs;
—The aggregate maximum rated heat
input capacity of the stationary fuel
combustion units at the facility is 30
million British thermal units per hour
(mmBtu/hr) or greater; and
—The facility emits 25,000 metric tons
CO2e or more per year from all
stationary fuel combustion sources.6
• Any supplier (as defined in 40 CFR
part 98, subparts LL through PP) of any
of the products as listed below in any
calendar year starting in 2010. For these
suppliers, the annual GHG report covers
all applicable products for which
6 This does not include portable equipment,
emergency generators, or emergency equipment as
defined in the rule.
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calculation methodologies are provided
in 40 CFR part 98, subparts KK through
PP.
—Coal-based liquid fuels: All producers
of coal-to-liquid fuels; importers and
exporters of coal-to-liquid fuels with
annual imports or annual exports that
are equivalent to 25,000 metric tons
CO2e or more per year.
—Petroleum products: All petroleum
refiners that distill crude oil;
importers and exporters of petroleum
products with annual imports or
annual exports that are equivalent to
25,000 metric tons CO2e or more per
year.
—Natural gas and natural gas liquids
(NGLs): All natural gas fractionators
and all local natural gas distribution
companies (LDCs).
—Industrial GHGs: All producers of
industrial GHGs; importers and
exporters of industrial GHGs with
annual bulk imports or exports of
N2O, fluorinated GHGs, and CO2 that
in combination are equivalent to
25,000 metric tons CO2e or more per
year.
—CO2: All producers of CO2; importers
and exporters of CO2 with annual
bulk imports or exports of N2O,
fluorinated GHGs, and CO2 that in
combination are equivalent to 25,000
metric tons CO2e or more per year.
• Research and development
activities (as defined in 40 CFR 98.6) are
not considered to be part of any source
category subject to the rule.
It is important to note that the
applicability criteria apply to a facility’s
annual emissions or a supplier’s annual
quantity of product supplied.7 For
example, while a facility’s emissions
may be below 25,000 metric tons CO2e
in January, if the cumulative emissions
for the calendar year are 25,000 metric
tons CO2e or more at the end of
December, the rule applies and the
reporter must submit an annual GHG
report for that facility. Therefore, it is in
a facility’s or supplier’s interest to
collect the GHG data required by the
rule if they think they will meet or
exceed the applicability criteria in 40
CFR 98.2 by the end of the year. EPA
plans to have tools and guidance
available to assist potential reporters in
assessing whether the rule applies to
their facilities or supply operations.
2. Schedule for Reporting
Reporters must begin collecting data
on January 1, 2010. The first annual
GHG report is due on March 31, 2011,
for GHGs emitted or products supplied
7 Supplied means produced, imported, or
exported.
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during 2010. For a portion of 2010, the
rule allows reporters to use best
available monitoring methods for
parameters that cannot reasonably be
measured according to the monitoring
and quality assurance/quality control
(QA/QC) requirements of the relevant
subpart as described in Sections II.A.3
and II.G of this preamble.
Reports are submitted annually. For
EGUs that are subject to the ARP,
reporters must continue to report CO2
mass emissions quarterly, as required by
the ARP, in addition to providing
annual GHG reports under this rule.
Reporters must submit GHG data on an
ongoing, annual basis. The snapshot of
information provided by a one-time
information collection request (ICR)
would not provide the type of ongoing
information which could inform the
variety of potential CAA policy options
being evaluated for addressing climate
change.
Once subject to this reporting rule,
reporters must continue to submit GHG
reports annually. A reporter can cease
reporting if the required annual GHG
reports demonstrate that reported GHG
emissions are either (1) less than 25,000
metric tons of CO2e per year for five
consecutive years or (2) less than 15,000
metric tons of CO2e per year for three
consecutive years. The reporter must
notify EPA that they intend to cease
reporting and explain the reasons for the
reduction in emissions. This provision
applies to all facilities and suppliers
subject to the rule, regardless of their
applicability category (i.e., whether rule
applicability was initially triggered by
an ‘‘all-in’’ source category or a source
category with a 25,000 metric tons CO2e
threshold). The reporter must keep
records for all five consecutive years in
which emissions were less than 25,000
metric tons per year, or all three
consecutive years in which emissions
were less than 15,000 metric tons per
year, as appropriate. If GHG emissions
(or quantities in products supplied)
subsequently increase to 25,000 metric
tons CO2e in any calendar year, the
reporter must again begin annual
reporting. The rule also contains a
provision to allow facilities and
suppliers to notify EPA and stop
reporting if they close all GHG-emitting
processes and operations covered by the
rule.
If reporters discover or are notified by
EPA of errors in an annual GHG report,
they must submit a revised GHG report
within 45 days.
3. What has to be included in the annual
GHG report?
Reporters must include the following
information in each annual GHG report:
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• Facility name or supplier name (as
appropriate) and physical street address
including the city, State, and zip code.
• Year and months covered by the
report, and date of report submittal.
• For facilities that directly emit
GHG:
—Annual facility emissions (excluding
biogenic CO2), expressed in metric
tons of CO2e per year, aggregated for
all GHG from all source categories in
40 CFR part 98, subparts C through JJ
that are located at the facility.
—Annual emissions of biogenic CO2
(i.e., CO2 from combustion of
biomass) aggregated for all applicable
source categories in subparts C
through JJ located at the facility.
—Annual GHG emissions for each of the
source categories located at the
facility, by gas. Gases are: CO2
(excluding biogenic CO2), biogenic
CO2, CH4, N2O, and each fluorinated
GHG.
—Within each source category,
emissions broken out at the level
specified in the respective subpart
(e.g., some source categories require
reporting for each individual unit or
each process line).
—Additional data specified in the
applicable subparts for each source
category. This includes activity data
(e.g., fuel use, feedstock inputs) that
were used to generate the emissions
data and additional data to support
QA/QC and emissions verification.
—Total pounds of synthetic fertilizer
produced through nitric acid or
ammonia production and total
nitrogen contained in that fertilizer.
• For suppliers: 8
—Annual quantities of each GHG that
would be emitted from combustion or
use 9 of the products supplied,
imported, or exported during the year.
Report this for each applicable supply
category in 40 CFR part 98 subparts
KK through PP, by gas. Also report the
total quantity, expressed in metric
tons of CO2e, aggregated for all GHGs
from all applicable supply categories.
—Additional data specified in the
applicable subparts for each supply
category. This includes data used to
calculate GHG quantities or needed to
support QA/QC and verification.
• A written explanation if the
reporter changes GHG calculation
methodologies during the reporting
period.
8 Suppliers include producers, importers, and
exporters of fuels and industrial gases. The level of
reporting for suppliers is specified in the rule. Most
report at the facility level. Imports and exports are
reported at the corporate level.
9 ‘‘Use’’ for purposes of industrial GHGs presumes
that there will be 100 percent release of the GHG.
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• If best available monitoring
methods were used for part of calendar
year 2010, a brief description of the
methods used.
• Each data element for which a
missing data procedure was used
according to the procedures of an
applicable subpart and the total number
of hours in the year that a missing data
procedure was used for each data
element.
• A signed and dated certification
statement provided by the Designated
Representative of the owner or operator.
Note that in some cases, the same
facility is subject to the rule
requirements for direct emitters as well
as for suppliers. For example, petroleum
refineries are suppliers of petroleum
products (40 CFR part 98, subpart NN)
and also directly emit GHGs from
petroleum refining (40 CFR part 98,
subpart Y), general stationary fuel
combustion (40 CFR part 98, subpart C),
and possibly other source categories
located at a refinery. In such cases,
reporters must report the information in
both the facility and supplier bullets
listed above.
EPA will 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 shall be available to the public
and cannot be withheld as CBI.10
Special Provisions for Reporting Year
2010. During January 1, 2010 through
March 31, 2010, reporters may use best
available monitoring methods for any
parameter (e.g., fuel use, daily carbon
content of feedstock by process line)
that cannot reasonably be measured
according to the monitoring and QA/QC
requirements of a relevant subpart. The
reporter must still use the calculation
methodologies and equations in the
‘‘Calculating GHG Emissions’’ sections
of each relevant subpart, but may use
the best available monitoring method for
any parameter for which it is not
reasonably feasible to acquire, install,
and operate a required piece of
monitoring equipment by January 1,
2010. Starting no later than April 1,
2010, the reporter must begin following
all applicable monitoring and QA/QC
requirements of this part, unless they
submit a request to EPA showing that it
is not reasonably feasible to acquire,
10 Although CBI determinations are usually made
on a case-by-case basis, EPA has discussed in an
earlier Federal Register notice what constitutes
emissions data that cannot be withheld as CBI (956
FR 7042–7043, February 21, 1991). In addition, as
discussed in Section II.R of this preamble, EPA will
be initiating a separate notice and comment process
to make CBI and emissions data determinations for
the categories of data collected under this
rulemaking.
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install, and operate a required piece of
monitoring equipment by April 1, 2010,
and EPA approves the request. EPA will
not approve use of best available
methods beyond December 31, 2010.
Best available monitoring methods
include any of the following methods:
• Monitoring methods currently used
by the facility that do not meet the
specifications of a relevant subpart.
• Supplier data.
• Engineering calculations.
• Other company data.
Abbreviated GHG Report for Facilities
Containing Only General Stationary
Fuel Combustion Sources. In lieu of a
full annual GHG report, reporters may
submit an abbreviated GHG report for
2010 emissions from existing facilities
that were in operation as of January 1,
2010, and are required to report only
their stationary combustion source
emissions per 40 CFR 98.2(a)(3). The
abbreviated report contains total facility
GHG emissions aggregated for all
stationary combustion units calculated
according to any of the methods in 40
CFR 98.33(a) and expressed in metric
tons of CO2, CH4, N2O, and CO2e. While
the breakdown of emissions by
individual combustion units and the
activity data used to calculate the
emissions do not need to be reported as
part of the abbreviated GHG report, the
calculation variables used in the
selected method must be reported. For
calendar year 2011, all reporters must
submit the full annual GHG report
containing all required information.
4. How is the report submitted?
The reports must be submitted
electronically, in a format to be
specified by the Administrator after
publication of the final rule.11 To the
extent practicable, we plan to adapt
existing EPA 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 EPA reporting mechanisms.
Each report must contain a signed
certification by a Designated
Representative of the facility. On behalf
of the owners and operators, the
Designated Representative must 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.
5. What records must be retained?
Each reporter must also retain and
make available to EPA upon request the
11 For more information about the reporting
format please see Section V of this preamble.
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following records for three years in an
electronic or hard-copy 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. These data include, but
are not limited to:
—The GHG emissions calculations and
methods used.
—Analytical results for the development
of site-specific emissions factors.
—The results of all required analyses for
high heat value, carbon content, or
other required fuel or feedstock
parameters.
—Any facility operating data or process
information used for the GHG
emissions calculations.
• The annual GHG reports.
• Missing data computations. For
each missing data event, also retain a
record of the duration of the event,
actions taken to restore malfunctioning
monitoring equipment, the cause of the
event, and the actions taken to prevent
or minimize occurrence in the future.
• A written GHG monitoring plan
containing the information specified in
40 CFR 98.3(g)(5).
• The results of all required
certification and quality assurance (QA)
tests of CEMS, fuel flow meters, and
other instrumentation used to provide
data for the GHGs reported.
• Maintenance records for all CEMS,
flow meters, and other instrumentation
used to provide data for the GHGs
reported.
• Any other data specified in any
applicable subpart of 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.
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B. Summary of the Major Changes Since
Proposal
EPA received approximately 16,800
public comments on the proposed
rulemaking. As mentioned earlier in this
preamble, we had two public hearings
and conducted an unprecedented level
of outreach between signature of the
proposal and the close of the public
comment period. Below are the major
changes to the program since the
proposal. The rationale for these and
any other significant changes can be
found in this preamble or in the
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments.’’
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• Reduced the number of source
categories included in the final rule as
we further consider comments and
options on several categories.12
• Added a mechanism in 40 CFR 98.2
to allow facilities and suppliers that
report less than 25,000 metric tons of
CO2e for five consecutive years, or less
than 15,000 metric tons for 3
consecutive years, to cease annual
reporting to EPA.
• Added a mechanism in 40 CFR 98.2
to allow facilities and suppliers that
stop operating all GHG-emitting
processes and operations covered by the
rule to cease annual reporting to EPA.
• Added a provision in 40 CFR 98.3
for submittal of revised annual GHG
reports to correct errors.
• Added provisions in 40 CFR 98.3 to
allow use of best available monitoring
methods for part of calendar year 2010.
• Added, in 40 CFR 98.3, calibration
requirements for monitoring
instruments including an accuracy
specification of plus or minus five
percent for flow meters.
• Excluded R&D activities from
reporting under 40 CFR part 98 by
adding an exclusion in 40 CFR 98.2.
• Revised the requirements of the
Designated Representative in 40 CFR
98.4 to align them with those in 40 CFR
part 75 (ARP regulations).
• Changed record retention to three
years instead of five years for most
records (40 CFR 98.3).
• In the recordkeeping section (40
CFR 98.3), clarified the contents of the
monitoring plan (called the quality
assurance performance plan (QAPP) at
proposal).
• Edited references to the stationary
fuel combustion subpart to improve
consistency and edited the CEMS
language in several subparts for
consistency and to clarify when CEMS
are used and under what circumstances
upgrades are needed.
• Revised several definitions in 40
CFR part 98, subpart A to address
comments.
• In several subparts of 40 CFR part
98, moved some of the data elements
listed in the recordkeeping section of
the proposed rule to the reporting
section. In general, these changes were
made to provide sufficient data for EPA
12 See the following sections of this preamble for
discussion of source categories not included in
today’s final rule: sections III.I (electronics
manufacturing), III.J (ethanol production), III.L
(fluorinated GHG production), III.M (food
processing), III.T (magnesium production), III.W (oil
and natural gas systems), III.DD (SF6 from electrical
equipment), III.FF (underground coal mines), III.HH
(industrial landfills are not included in today’s rule,
but MSW landfills are covered by the rule), III.II
(wastewater treatment), and III.KK (suppliers of
coal).
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to verify the reported emissions using
the verification approach described in
Section II.N of this preamble. Specific
changes and reasons for them are
summarized in the relevant source
category sections within Section III of
this preamble.
C. Summary of Comments and
Responses on GHGs To Report
This section contains a brief summary
of major comments and responses on
the issue of which GHGs to report. A
large number of comments were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments,
Selection of Reporting Thresholds,
Greenhouse Gases, and De Minimis
Provisions.’’ Reponses to comments on
fluorinated gases can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Suppliers of Industrial
GHGs.’’
Comment: Many commenters
supported reporting of the GHGs
included in the proposed rule: CO2,
CH4, N2O, HFCs, PFCs, SF6, and other
fluorinated compounds. Many
commenters noted that IPCC and
national inventories focus on these
gases, and that they are directly emitted
by human activities, long-lived in the
atmosphere, and contribute to global
climate change. A few of these also
stated that collection of data on these
gases is useful for future GHG policy
development. While some commenters
suggested collecting data on fewer gases
or requiring reporting of additional
gases, most agreed with the proposed
list.
Some commenters raised concerns
that the proposed definition of
fluorinated GHGs was broad and
included compounds for which global
warming potentials (GWPs) were not
currently available.
Response: The final rule requires
reporting of the same gases as the
proposed rule. These are the most
abundantly emitted GHGs that result
from human activity. They are not
currently controlled by mandatory
Federal programs and, with the
exception of the CO2 emissions data
reported by EGUs subject to the ARP,
data on their emissions are also not
reported under mandatory Federal
programs. CO2 is the most abundant
GHG directly emitted by human
activities, and is a significant driver of
climate change. The global
anthropogenic combined heating effect
of CH4, N2O, HFCs, PFCs, SF6, and the
other fluorinated compounds are also
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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 (O3) 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 a major
focus of the climate change research and
policy communities. The IPCC also
included methods for accounting for
emissions from several specified
fluorinated gases in the 2006 IPCC
Guidelines for National Greenhouse Gas
Inventories.13 These gases include
fluorinated ethers, which are used in
electronics, in anesthetics, and as heat
transfer fluids. These fluorinated
compounds are long-lived in the
atmosphere and have high GWPs, like
the HFCs, PFCs, and SF6. In many cases
these fluorinated gases are used in
growing industries (e.g., electronics) or
as substitutes for HFCs. As such, EPA is
requiring 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 including in this rule: water
vapor, chlorofluorocarbons (CFCs),
hydrochlorofluorocarbons (HCFCs),
halons, tropospheric O3, and black
carbon. The reasons why we are not
requiring reporting of these gases and
aerosols under this rule are contained in
Section IV.A of the preamble to the
proposed rule (74 FR 16464, April 10,
2009) and in the ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments,
Selection of Reporting Thresholds,
Greenhouse Gases, and De Minimis
Provisions.’’
In response to comments, the
definition of fluorinated gases to report
has been changed. See Section III.OO of
this preamble (Suppliers of Industrial
GHGs) for the response to comments on
fluorinated gases to be reported.
13 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).
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D. Summary of Comments and
Responses on Source Categories To
Report
This section contains a brief summary
of major comments and responses on
which source categories must report. A
large number of comments were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments,
Selection of Source Categories to Report
and Level of Reporting.’’
1. Reduction in Number of Source
Categories Included in the Final Rule
Comment: While many commenters
agreed with the source categories
selected for inclusion in the proposed
rule, some commenters objected to the
inclusion of specific source categories.
Some also expressed concern that there
might not be sufficient time for EPA to
consider and address public comments
and finalize the rules by fall 2009 for
particular source categories.
Response: In today’s notice EPA is
promulgating subparts that require
reporting for most of the source
categories included in the proposed
rule. For these categories, EPA fully
considered and addressed the public
comments, and has determined that the
source categories should be included in
the rule for reasons stated in Section
IV.B of the preamble for the proposed
rule (74 FR 16465, April 10, 2009), the
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments: EPA’s Response to Public
Comments, Selection of Source
Categories to Report and Level of
Reporting’’, and the relevant comment
response volumes for each of the
individual source categories. However,
at this time EPA is not going final with
the following subparts as we further
evaluate public comments:
• Electronics manufacturing
• Ethanol production
• Fluorinated GHG production
• Food processing
• Magnesium production
• Oil and natural gas systems
• SF6 from electrical equipment
• Underground coal mines
• Industrial landfills
• Wastewater treatment
• Suppliers of coal
We plan to further review public
comments and other information before
finalizing these subparts. Additional
discussion of our reasons for not
finalizing these particular source
categories at this time can be found in
the individual subsections in Section III
of this preamble.
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2. Scope of Source Categories Covered
Comment: Several commenters
suggested that the scope of reporting
and the source categories covered
should be broader. Some indicated that
the rule should require reporting of net
rather than gross emissions, including
reporting of offset projects. In addition,
some of the comments suggested
requiring reporting of emissions and
sequestration from forestry practices.
Response: EPA selected the source
categories required to report under the
rule after considering the language of
the Appropriations Act, the
accompanying explanatory statement,
the CAA, 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.’’ EPA interpreted this to
mean direct emissions from facilities
over a certain threshold as well as the
emissions associated with fuel or
industrial gases when completely
combusted or used, but not necessarily
project-based reductions or
sequestration.14 Calculation and
reporting of net emissions (emissions at
a facility less any sequestration
occurring at the facility) was determined
to be outside of the scope of this rule.
In selecting source categories, EPA
considered all anthropogenic sources of
GHG emissions (those produced as a
result of human activities) included in
the U.S. GHG Inventory and reviewed
the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories and
existing voluntary and regulatory GHG
reporting programs for additional source
categories that might be relevant. EPA
systematically reviewed the list of
source categories developed from the
U.S. GHG Inventory and the IPCC
guidance to ensure the inclusion of
those that emit the most significant
amounts of GHG emissions while
minimizing the number of reporters.
Some sources were deemed
inappropriate for inclusion in this rule
for a variety of reasons including the
current ability to monitor and verify the
emissions or products with sufficient
accuracy and consistency. For further
discussions of sources included and
excluded please see Section IV.B of the
preamble to the proposed rule (74 FR
16465). In total, the rule is estimated to
14 For the discussion of the CAA authority to
collect these data, see Section II.Q of this preamble.
Also see the relevant source category sections
within Section III of this preamble.
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cover approximately 85 percent of U.S.
GHG emissions.
With respect to emissions and
sequestration from agricultural sources
and other land uses, the rule does not
require reporting of emissions or
sequestration associated with
deforestation, carbon storage in living
biomass or harvested wood products.
These categories were excluded because
currently available, practical reporting
methods to calculate facility-level
emissions for these sources can be
difficult to implement and can yield
uncertain results. Currently, there are no
direct GHG emission measurement
methods available except for research
methods that are very expensive and
require sophisticated equipment.
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 or sequestration using
emission factor or carbon stock
exchange approaches, it would be
necessary for landowners to report on
management practices and a variety of
data inputs. The activity data collection
and emission factor development
necessary for emissions calculations at
the scale of individual reporters can be
complex and costly. Due to the current
lack of reasonably accurate facility-level
emissions/stock change factors and the
ability to accurately measure all facilitylevel calculation variables at a
reasonable cost to reporters, the
reporting of emissions and sequestration
associated with deforestation and
carbon sequestration from forestry
practices was excluded as a source
category.
While this reporting rule does not
require reporting by facilities or
suppliers in every source category, the
U.S. GHG Inventory does provide
national estimates of emissions from all
U.S. anthropogenic GHG sources. In the
case of land-based emissions, this
includes all emissions by sources and
removals by sinks on lands that are
managed. The Inventory is prepared
annually by EPA, in collaboration with
other Federal agencies, and is an
impartial, policy-neutral report that
tracks annual GHG emissions at the
national level and presents historical
emissions from 1990 to 2007. The
Inventory also calculates carbon dioxide
emissions that are removed from the
atmosphere by ‘‘sinks,’’ such as through
the uptake of carbon by forests,
vegetation, and soils.
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Offsets projects are of interest to many
stakeholders because they could be an
important component of a potential
future cap and trade system. Some
commenters requested EPA to include
accounting methods for offsets in this
reporting rule. We believe that this issue
is beyond the scope of this rulemaking
and the Congressional request that
initiated it. However, EPA will continue
to monitor policy needs and
developments in the future and is
prepared to initiate additional reporting
efforts at the appropriate time.
3. Reporting by Both Upstream and
Downstream Sources
Comment: Some commenters were
concerned that requiring reporting by
both fuel and industrial GHG suppliers
(upstream sources) and direct emitters
(downstream sources) results in double
counting of GHG emissions and could
lead to overestimation of emissions.
Some commenters thought reporting by
both upstream and downstream sources
was duplicative, confusing,
unnecessary, or burdensome and
recommended the rule be revised to
eliminate double reporting. Other
commenters agreed with EPA’s
proposed selection of source categories
to report and that reporting by upstream
sources and downstream sources is
needed to inform development of GHG
policies and programs.
Response: This rule responds to a
specific request from Congress to collect
data on GHG emissions from both
upstream production and downstream
sources, as appropriate. The rule
requires reporting by facilities that
directly emit GHGs above the selected
threshold as a result of combustion of
fuel or industrial processes
(downstream sources). The majority of
these reporters are large facilities in the
electricity generation and industrial
sectors. The rule also requires upstream
suppliers of fossil fuels and industrial
GHGs to report the GHG emissions that
could be emitted from combustion or
use of the quantity of fuels or industrial
gases supplied into the economy. 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. To cover these direct emissions
would require reporting by hundreds or
thousands of small facilities. To avoid
this impact, the rule does not include all
of those emitters but instead requires
reporting by the suppliers of industrial
gases and suppliers of fossil fuels.
The data collected under this rule are
consistent with the appropriations
language and provide valuable
information to EPA and stakeholders in
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the development of climate change
policy and programs. Potential policies
such as low carbon fuel standards can
only be applied upstream, whereas enduse 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. Eliminating reporting by either
upstream sources or downstream
sources would not satisfy EPA’s data
needs and policy objectives of this rule.
EPA acknowledges that there is
inherent double reporting of emissions
in a program that includes both
upstream and downstream sources.
However, as discussed in Sections I.D
and IV.B of the preamble to the
proposed rule (74 FR 16448, April 10,
2009) EPA does not intend to use
emissions data collected by this rule as
a replacement for the national emission
estimates found in the annual Inventory
of GHG emissions.
E. Summary of Comments and
Responses on Thresholds
This section contains a brief summary
of major comments and responses on
EPA’s approach and rationale for
selection of reporting thresholds. See
sections III.C through PP of this
preamble for summaries of comments
and responses on specific threshold
analyses for the individual source
categories contained in 40 CFR part 98,
subparts C through PP. A large number
of comments were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Selection of
Reporting Thresholds, Greenhouse
Gases, and De Minimis Provisions.’’
Comment: Many commenters
supported the proposed threshold of
25,000 metric tons of CO2e per calendar
year. These commenters generally
agreed that the 25,000 metric ton
threshold level achieves a reasonable
balance between the percentage of
national emissions covered and the
number of reporters, resulting in a
sufficiently comprehensive dataset
while minimizing the impact on small
facilities. Some also commented that
this threshold is consistent with other
existing GHG programs or likely future
programs. Some commenters supported
a 100,000 metric ton CO2e threshold
because they believe this level covers an
appropriate percentage of national GHG
emissions while easing the reporting
burden on industry. Some commenters
supported an emission threshold of
10,000 metric tons CO2e to enable
collection of emissions data for smaller
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sources. Some of these commenters also
noted that a 10,000 metric ton CO2e
threshold is more appropriate in order
to monitor leakage of emissions to
smaller sources (since 25,000 metric
tons of CO2e is a likely threshold for
future emissions reductions mandates).
Some commenters suggested
quantitative evaluation of intermediate
threshold options in addition to the four
evaluated by EPA (1,000; 10,000;
25,000; and 100,000); several of these
suggested EPA analyze a threshold of
50,000 metric tons CO2e to reduce the
number of reporting facilities.
Response: As described in the
preamble to the proposed rule (74 FR
16448, April 10, 2009), EPA considered
four threshold levels, as well as
capacity-based thresholds where
appropriate, and we proposed a
threshold of 25,000 metric tons of CO2e
for many source categories, and
capacity-based or ‘‘all in’’ thresholds for
other categories. Based on comments
received, we reexamined the threshold
analyses both in general and for each
industry, taking into account additional
data provided, and we considered
whether there were reasons to develop
different thresholds in specific industry
sectors. The specific elements of these
analyses are discussed in the relevant
source category discussions in this
preamble and the accompanying
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments’’ volumes for each source
category. At the general level, we also
considered non-quantitative factors,
such as consistency with State and other
programs (the majority have established
thresholds for GHG reporting at 25,000
metric tons or lower, such as 10,000 or
5,000 metric tons), and the need to
select a threshold level that best satisfies
the objective of the reporting rule to
collect a national data set that is
sufficiently comprehensive for use in
analyzing a range of GHG policies and
programs.
From these analyses, we concluded
that a 25,000 metric ton threshold suited
the needs of the reporting program by
providing comprehensive coverage of
emissions with a reasonable number of
reporters, thereby creating the robust
data set necessary for the quantitative
analyses of the range of likely GHG
policies, programs and regulations.
Moreover, the 25,000 metric ton
threshold covers similarly sized sources
as covered by many current CAA
programs (e.g., NSPS applies PM
emissions limits to oil-fired and coalfired units larger than 30 mmBtu per
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hour).15 And, as mentioned previously,
this level is consistent with (or higher
than) the majority of other GHG
reporting programs. Furthermore,
having a uniform threshold 16 was an
equitable approach because like
facilities could be compared across
sectors and no one industry would be
disproportionately affected or subjected
to a lower or higher threshold. A
uniform threshold is also essential for
evaluating potential policies and
programs that could have a single
emissions threshold across source
categories (e.g., PSD), and simplifies the
applicability determination for facilities
that emit GHGs from more than one
source category under the rule.
As discussed in Section IV.C of the
preamble to the proposed rule (74 FR
16448, April 10, 2009), we considered
four potential thresholds (the range of
1,000 to 100,000 metric tons of CO2e)
and from our analysis and the
comments we concluded we had
enough information to select an
appropriate threshold for the final rule
and that detailed quantitative analyses
of additional intermediate thresholds
would not change EPA’s decision. For
example, in reviewing our threshold
analyses, we determined that the
intermediate options between 25,000
and 100,000 metric tons would not
provide an alternative threshold that
substantially reduced the number of the
reporters relative to other options
considered or substantially improved
the cost effectiveness. (See ‘‘Review of
Threshold Analyses’’ memorandum in
docket EPA–HQ–OAR–2008–0508.)
Based on our proposal analysis on the
data available, we saw that the majority
of the affected facilities or suppliers had
emissions either considerably above or
below 25,000 metric tons CO2e per year.
(As previously explained, supplier GHG
quantities represent the emissions that
could be released when the products
they supply are combusted or used.)
The selected threshold took into
account our finding that while a
threshold other than 25,000 metric tons
of CO2e might appear to achieve an
appropriate balance between the
number of facilities and emissions
covered for a limited number of source
categories, there are several additional
15 As explained in section II.A of this preamble,
facilities that only have stationary combustion units
as their only source of emissions and have units
with an aggregate maximum heat input of less than
30 mmbtu are not included in this rule.
16 Although the thresholds were expressed in
different ways (e.g., ‘‘all-in’’, annual emissions)
most corresponded to, or were consistent with, an
annual facility-wide emission level of 25,000 metric
tons of CO2e.
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reasons for selecting the threshold of
25,000 metric tons of CO2e per year.
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. At proposal, we
explained that we did not select either
of these thresholds because although
both broaden national emissions
coverage, they do so by
disproportionately increasing the
number of affected facilities. With the
data available at proposal and from the
comment period, we remain convinced
that the 1,000 metric ton CO2e/year
threshold would increase the number of
reporters by an order of magnitude, thus
changing the focus of the program from
large to small emitters and imposing
reporting costs on tens of thousands of
small businesses that in total would
amount to less than 10 percent of
national GHG emissions. Our analysis
indicates that a 10,000 metric ton CO2e/
yr threshold would approximately
double the number of reporters, but
would only increase national emissions
coverage by one percent. (See the
Regulatory Impacts Analysis for the
final rule for the estimated number of
facilities and GHG emissions covered by
the alternative thresholds examined.)
While some proposals (e.g., WCI and
H.R. 2454, American Clean Energy and
Security Act) contain a 10,000 metric
ton threshold for reporting, EPA
concluded for policy evaluation
purposes, the 25,000 metric ton
threshold more effectively targets large
industrial emitters and suppliers, covers
approximately 85 percent of U.S.
emissions, and minimizes the burden on
smaller facilities.
We also reviewed the 100,000 metric
tons of CO2e per year as an alternative
threshold but concluded that it fails to
satisfy key objectives. It excludes a
number of 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 some large
industry sectors would be rather
significantly fragmented, resulting in an
incomplete understanding of direct
emissions from that sector. We
concluded that this threshold would not
sufficiently cover the types of facilities
that are typically regulated under the
CAA and would be inadequate for the
intended use of analyzing potential
policies and developing future CAA
programs.
Based on our review, EPA has
determined that the selected 25,000
metric ton CO2e threshold will cover
many of the types of facilities and
suppliers typically regulated under the
CAA, while appropriately balancing
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emission coverage and burden. At this
threshold, EPA will be able to evaluate
the effects of a number of options and
policies that could address GHG
emissions without placing an undue
burden on a large number of smaller
facilities and sources. In addition, this
threshold level is largely consistent with
many of the existing GHG reporting
programs and different legislative
proposals in Congress. Furthermore,
many industry stakeholders that EPA
met with and the majority of public
commenters, representing a wide variety
of stakeholders, expressed support for a
25,000 metric ton CO2e threshold,
agreeing with the Agency’s assessment
of coverage.
F. Summary of Comments and
Responses on Level of Reporting
This section contains a brief summary
of major comments and responses on
the level of reporting. A large number of
comments were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Selection of Source
Categories to Report and Level of
Reporting.’’
Comment: Many commenters
supported facility-level reporting rather
than corporate-level reporting. The
reasons they gave included: Facilitylevel reporting is consistent with most
air rules and permitting programs,
environmental managers are used to
facility-level reporting, facility-level
data would be needed to implement
likely future regulatory programs such
as a cap and trade program, this
approach is simpler to implement and
minimizes administrative burden, a
facility’s corporate status can change
during the year, and tying data to
physical sources makes emissions easier
to track and monitor over time. On the
other hand, several commenters favored
corporate-level reporting. The reasons
they gave included: The effect of GHG
emissions is global, therefore the
location where the GHGs are emitted is
not important; various other GHG
programs require corporate-level
reporting and have mechanisms for
handling ownership changes; the overall
carbon footprint of a corporation is
important; a company’s entire emissions
should be reported, not just those
facilities that are above a threshold; and
facility-level data are more likely to be
CBI.
Response: In response to comments,
EPA reviewed our initial views outlined
in Sections IV.D and V of the proposal
preamble (74 FR 16448, April 10, 2009)
in light of our data needs under the
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CAA, our interpretation of the
Congressional request, and the feedback
received. Based on these considerations,
we determined that the final rule will
retain the same reporting level as the
proposed rule. Facility-level reporting is
required, with the exception of some
supplier source categories (e.g.,
importers of fuels or industrial GHGs or
manufacturers of motor vehicles and
engines). If a facility is covered by the
rule, the reporter must report the
facility’s GHG emissions from all source
categories for which the rule contains
GHG emission methods. The total
emissions for the facility are reported, as
well as emissions broken out by source
category within the facility. Subparts for
some source categories specify further
breakout of emissions by process line or
unit.
We retained this approach because
the purpose of this rule is to collect data
from suppliers and from facilities with
direct GHG emissions above selected
thresholds for use in analyzing,
developing, and implementing potential
future CAA GHG policies and programs.
Facility-level data are needed to support
analyses of some types of potential GHG
reduction programs, such as NSPS. The
data collected from facility-level
reporting under this rule will improve
our ability to formulate a set of climate
change policy options and to assess
which facilities and industries would be
affected by the options and how they
would be affected. (Note, we expect that
similarly, facility-level data will also be
useful to States, the public, and other
stakeholders to formulate State and
regional programs and track emission
trends over time.) Reporting by
individual facilities is also consistent
with most existing air regulatory such as
ARP, NSPS and national emission
standards for hazardous air pollutants
(NESHAP), and permitting programs.
Many facility environmental managers
are already experienced with facilitylevel emissions reporting under such
programs and can likewise submit
reports under the mandatory GHG
reporting rule.
Corporate-level reporting was not
selected because corporate reporting
without facility-specific details would
not provide sufficient data to assess
many potential CAA GHG policies and
programs. EPA understands that some
corporate-level GHG reporting programs
have mechanisms to establish reporting
responsibilities under complex and
changing ownership situations, but we
find corporate-level reporting overly
complex for this rulemaking given that
facility level data are needed, and it is
simpler to place reporting responsibility
directly on individual facilities. We note
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that while EPA requires facility-level
reporting, it is up to the facility owners
and operators to select the designated
representative who will submit the
report for a facility, and reporters can
also establish any internal corporate
review processes they deem
appropriate.
While EPA agrees with the
commenters who indicated that
information on corporate carbon
footprints is useful for various purposes,
collection of such information is outside
the scope of this rulemaking. With that
said, we are exploring options for
adding additional data elements to the
reports, such as name of parent
company and NAICS code(s), to allow
easier aggregation of facility-level data
to the corporate level under this
program. EPA expects to subject any
additional requests to notice and
comment rulemaking. In any event, we
expect that the facility-level data
collected under this rule will be useful
for programs that request or require
corporate reporting. But, as explained in
Sections I.D and I.E of this preamble,
this reporting rule is one action to
respond to a specific request from
Congress. Various other Federal and
State programs are collecting and will
continue to collect corporate-level data
on direct and indirect emissions, energy
efficiency, and other data as part of a
broad array of climate change
initiatives.
For the response to the commenters’
concern about CBI, see Section II.R of
this preamble.
G. Summary of Comments and
Responses on Initial Reporting Year and
Best Available Monitoring Methods
This section contains a brief summary
of major comments and responses on
the initial reporting year. A large
number of comments were received
covering numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Initial Year of
Reporting, Duration of the Reporting
Program, and Provisions to Cease
Reporting.’’
Comment: The proposed rule
included reporting of calendar year
2010 emissions in March 2011, which
would require reporters to collect data
starting on January 1, 2010. The
preamble to the proposed rule also
discussed options of allowing reporting
of best available data for 2010, or
delaying reporting by one year (64 FR
16471, April 10, 2009). Many industries
with source categories covered by the
proposed rule commented that a data
collection start date of January 1, 2010,
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does not provide sufficient time to
review the final rule, purchase and
install required monitoring equipment,
train staff, and develop internal
electronic data management and
recordkeeping systems needed to
comply with the rule. Many indicated
that they do not currently have all the
meters and monitoring equipment
required by the rule. Most of these
commenters strongly stated that
calendar year 2011 should be the first
reporting year. Many of them also stated
that if EPA decides data collection must
begin in 2010, a best available data
approach should be allowed for
calculating and reporting 2010
emissions.
Conversely, Congressional inquiries
and a large number of public
commenters including States, NGOs,
and the general public, emphasized that
data collection must start in 2010
because time is of the essence for
developing and implementing GHG
policies and programs. These
commenters urged EPA to require
reporting of calendar year 2010 GHG
emissions and not to delay data
collection until calendar year 2011.
Some of the commenters made
suggestions about the types of data and
methods that could be allowed if EPA
chose to use a best available data
approach for 2010.
Response: EPA carefully reviewed
input from all commenters with the goal
of balancing the urgent need for data
against the legitimate concerns raised
regarding timing. As a result, we have
revised the approach for the final rule.
The final rule requires data collection
for calendar year 2010, but has been
changed since proposal to allow use of
best available monitoring methods for
the first quarter of 2010.
Schedule. EPA decided to require
reporting of calendar year 2010
emissions because the data are crucial to
the timely development of future GHG
policy and regulatory programs. In the
Appropriation Act, Congress requested
EPA to develop this reporting program
on an expedited schedule, and
Congressional inquiries along with
public comments reinforce that data
collection for calendar year 2010 is a
priority. Delaying data collection until
calendar year 2011 would mean the data
would not be received until 2012, which
would likely be too late for many
ongoing GHG policy and program
development needs.
However, EPA understands that
because the final rule is not being
promulgated until fall of 2009, facilities
that do not already have the monitoring
systems required by the rule in place
might not have time to install and begin
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operating them by January 1, 2010.
Under the schedule in the
Appropriations Act, the final rule would
have been signed at the end of June
2009, which would have allowed
approximately six months to prepare for
data collection in January 2010. Given
the delay in promulgating the rule, there
is less time between signature of the
rule and a January 1, 2010 start date. In
light of this fact, and the industry
comments indicating that facilities do
not currently have all of the required
monitoring systems, EPA has decided to
provide flexibility by establishing a best
available monitoring methods option for
the first quarter of calendar year 2010.
This approach will provide time
comparable to what would have
occurred had EPA met the schedule in
the Congressional request. We will post
the rule on EPA’s Web site soon after
signature, allowing reporters to see the
final requirements and begin
compliance planning even before the
rule is published in the Federal
Register.
For the time period of January 1
through March 31, 2010, the rule allows
use of best available monitoring
methods for parameters that cannot
reasonably be measured according to the
monitoring and QA/QC requirements of
the relevant subpart. Starting no later
than April 1, 2010, the reporter must
begin following all applicable
monitoring and QA/QC requirements of
this part, unless they submit an
extension request showing that it is not
reasonably feasible to acquire, install,
and operate a required piece of
monitoring equipment by the specified
date and EPA approves the request. EPA
may approve such requests for a set time
period, but will not approve the use of
best available methods beyond
December 31, 2010. See the paragraph
heading ‘‘Extension Request Process’’
near the end of this response for further
details.
EPA has concluded that the time
period allowed under this schedule
(including the provision for facilityspecific requests) will allow facilities
that do not currently have the required
monitoring systems sufficient time to
begin implementing the monitoring
methods required by the rule. In
general, the required monitors, such as
flow meters, are widely available and
are not time consuming to install. By
allowing the additional time, many
facilities may also be able to install the
equipment during other planned (or
unplanned) process unit downtime,
thus avoiding process interruptions.
Definition of Best Available
Monitoring Methods. In determining
methods that would be allowed under a
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best available monitoring methods
approach, EPA considered the goal of
collecting consistent data to provide
information of sufficient quality to
inform policy and program
development, while recognizing that not
all facilities may be able to implement
the full monitoring methods required by
the rule by January 2010. We reviewed
the public comments as well as the
California Air Resources Board (CARB)
mandatory reporting rule, and we
considered options falling between full
flexibility to use any method and the
full requirements of EPA’s mandatory
reporting rule.
The least stringent approach would be
to allow facilities to calculate GHG
emissions using any data, methods,
calculation procedures, or emission
factors they choose during the best
available monitoring period and submit
minimal supporting data. This approach
would provide maximum flexibility to
industry, but EPA did not select this
approach because the usefulness of the
collected data would be questionable
given that it would be obtained using
inconsistent methods and it could not
be verified with sufficient confidence.
Instead, EPA developed a hybrid
approach that falls between full
flexibility and implementation of full
monitoring requirements in January
2010. Under the final rule, during
January 1, 2010, through March 31,
2010, reporters may use best available
monitoring methods for any parameter
(e.g., fuel use, daily carbon content of
feedstock by process line) if that
parameter cannot reasonably be
measured following the monitoring and
QA/QC requirements of a relevant
subpart. The reporter must use the
calculation procedures and equations in
the ‘‘Calculating GHG Emissions’’
sections of each relevant subpart, but
may use the best available monitoring
method for any parameter for which it
is not reasonably feasible to acquire,
install, and operate a required piece of
monitoring equipment by January 1,
2010. Best available monitoring
methods include the following:
• Monitoring methods currently used
by the facility that do not meet the
specifications of a relevant subpart.
• Supplier data.
• Engineering calculations.
• Other company data.
Reporters must submit an annual
GHG report for 2010. This calendar year
2010 report (submitted March 31, 2011)
includes the same information as in
subsequent years, but also requires brief
descriptions of each best available
monitoring method used, the parameter
measured using that method, and the
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time period during which the method
was used.
EPA selected this approach because it
is responsive to commenters’ concerns
that monitoring equipment cannot be
installed by January 1, 2010, while also
ensuring timely submission of more
consistent and verifiable data than the
alternatives. We have concluded that
the data will be more consistent because
all reporters will use the same basic
emissions calculation equations that are
in the rule, with best available inputs,
rather than the wide range of calculation
methods that would likely be used
under a full flexibility approach.
Furthermore, the selected approach
requires reporting of sufficient
information for EPA to verify the
emissions data. We have therefore
determined that this approach for
collection and reporting of the calendar
year 2010 data will fulfill the objectives
of this reporting rule.
It should also be noted that, like the
proposed rule, the final rule allows
facilities that must report only
emissions from general stationary fuel
combustion equipment (and do not have
other covered source categories) to
determine calendar year 2010 emissions
using any of the methods (tiers) in 40
CFR part 98, subpart C, and submit an
abbreviated GHG report. Full reporting
starts with calendar year 2011. This
allows such facilities, which are less
likely to have experience with
emissions monitoring and reporting, an
extra year to begin full reporting using
all the procedures required by the rule.
Extension Request Process. We expect
that the vast majority of facilities will
begin complying with the full
monitoring requirements of the rule no
later than April 1, 2010, and will not
require or be granted an extension.
However, EPA is providing facilities
with specific circumstances an
opportunity to request an extension in
the use of best available monitoring
methods. EPA will review extension
requests to determine whether they
should be approved. We envision that
extensions will apply primarily to
situations when needed monitoring
instrumentation could not be obtained
within the timeframe despite good faith
efforts by the facility, or when
installation of monitoring
instrumentation would require a process
unit shutdown that could not feasibly be
scheduled prior to April 1, 2010.
Timing. Reporters must submit
extension requests to EPA no later than
30 days after the effective data of the
GHG reporting rule. EPA intends to
review each submitted request and may
approve or disapprove the requests. EPA
may approve the request for a specified
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time period, but will not approve the
use of best available methods beyond
December 31, 2010. If EPA disapproves
an extension request, then the reporter
is required to implement the full
monitoring methods required by the
rule by April 1, 2010.
Content of Request. Requests must
contain the following information:
• A list of specific monitoring
instrumentation for which the request is
being made and the locations where
each piece of monitoring
instrumentation will be installed.
• Identification of the specific rule
requirements (by rule subpart, section,
and paragraph numbers) for which the
instrumentation is needed.
• A detailed description of the
reasons why the needed equipment
could not be obtained and installed
before April 1, 2010.
• If the reason for the extension is
that the equipment cannot be purchased
and delivered by April 1, 2010, include
supporting documentation such as the
date the monitoring equipment was
ordered, investigation of alternative
suppliers and the dates by which
alternative vendors promised delivery,
backorder notices or unexpected delays,
descriptions of actions taken to expedite
delivery, and the current expected date
of delivery.
• If the reason for the extension is
that the equipment cannot be installed
without a process unit shutdown,
include supporting documentation
demonstrating that it is not possible to
isolate the equipment, piping, or line
and install the monitoring instrument
without a full process unit shutdown.
Also include the date of the most recent
process unit shutdown, the frequency of
shutdowns for this process unit, and the
date of the next planned shutdown
during which the monitoring equipment
can be installed. If there has been a
shutdown or if there is a planned
process unit shutdown between
promulgation of this rule and April 1,
2010, include a justification of why the
equipment could not be obtained and
installed during that shutdown.
• A description of the specific actions
the facility will take to obtain and
install the equipment as soon as
reasonably feasible and the expected
date by which the equipment will be
installed and operating.
Approval Criteria. EPA will approve a
request if it contains all of the
information required by the rule and if
it demonstrates to the Administrator’s
satisfaction that it is not reasonably
feasible to acquire, install, and operate
a required piece of monitoring
equipment by April 1, 2010.
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For example, EPA is likely to approve
a request for an extension if the
documentation provided by the reporter
shows that they ordered monitoring
equipment in a timely manner,
attempted to find a supplier who could
deliver it in time, and could not control
the fact that the equipment was not
received for installation prior to April 1,
2010.
If a reporter requests an extension
because equipment cannot be installed
without a process unit shutdown, EPA
is likely to approve such a request if the
documentation clearly demonstrates
why it is not feasible to install the
equipment without a process unit
shutdown, shows there is not a planned
shutdown (and has not been a
shutdown) prior to April 1, 2010, during
which the monitoring instrument could
be installed. There are many locations
where monitors can be installed without
a process unit shutdown, because there
is often some redundancy in process or
combustion equipment or in the piping
that conveys fuels, raw materials and
products. For example, many facilities
have multiple combustion units and
fuel feed lines such that when one
combustion unit is not operating they
can obtain the needed steam, heat, or
emissions destruction by using other
combustion devices. Some facilities
have multiple process lines that can
operate independently, so one line can
be temporarily shut down to install
monitors while the facility continues to
make the same product in other process
lines to maintain production goals. If a
monitor needs to be installed in a
section of piping or ductwork, it can be
possible in some cases to isolate a line
without shutting down the process unit
(depending on the process
configuration, mode of operation,
storage capacity, etc.). If the line or
equipment location where a monitor
needs to be installed can be temporarily
isolated and the monitor can be
installed without a full process unit
shutdown, it is less likely EPA will
approve an extension request.
While there might be other unique
facility-specific situations for which an
extension might be granted, EPA
expects few of these. There have been
several changes to the rule since
proposal that would reduce the need for
extensions. For example, fewer source
categories are included in the final rule;
changes have been made to the
monitoring requirements of some rule
subparts to allow more flexibility in
monitoring methods; and provisions
have been added to the general
stationary fuel combustion, petroleum
refineries, and petrochemical
productions subparts allowing facilities
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additional time to perform some
monitor calibrations. These changes
address many of the specific situations
about which commenters raised
concerns.
It is highly unlikely we would
approve extension requests for
parameters that are measured by
periodic sampling and analyses.
Facilities should be able to make
arrangements to collect periodic
samples and send them off-site for
analyses (if they don’t have on-site
analytical capabilities) without the need
for an extension. Similarly, extensions
for design of electronic recordkeeping
systems seem unnecessary. Many
facilities already have electronic
recordkeeping systems that can be
altered to keep the records needed for
this rule. Furthermore, reporters can
keep the specified records in any type
of hard copy or electronic format they
choose, as long as it is in a form suitable
for expeditious inspection and review.
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H. Summary of Comments and
Responses on Frequency of Reporting
and Provisions To Cease Reporting
This section contains a brief summary
of major comments and responses on
the frequency of reporting and on
whether reporters should be allowed to
stop submitting annual reports if
emissions are reduced below a
threshold level. A large number of
comments were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Initial Year of
Reporting, Duration of the Reporting
Program, and Provisions to Cease
Reporting’’ and ‘‘Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to
Public Comments, Subpart A:
Applicability and Reporting Schedule.’’
1. Provisions To Cease Reporting if
Emissions Decrease
Comment: The majority of public
commenters favored annual reporting as
opposed to more or less frequent
reporting. Many commenters, especially
industrial facilities required to report
under the rule, objected to the ‘‘once in
always in’’ reporting approach in the
proposed rule and requested a
mechanism to stop reporting if
emissions fall below the 25,000 metric
tons CO2e per year annual threshold.
Others suggested a level different from
25,000 metric tons CO2e per year to
cease reporting. Some commented that
the lack of such a mechanism is a
disincentive to reduce facility
emissions. Conversely, other
commenters supported the proposed
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once in always in approach in order to
create a consistent, long term data set
covering the same population of
facilities over time that could be used to
track trends and understand factors that
influence emission levels.
Response: After reviewing the
comments, EPA has not changed the
frequency of reporting since the
proposed rule. Affected facilities and
suppliers must submit annual GHG
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. We have
determined that annual reporting is
sufficient for policy and regulatory
development. It is also consistent with
other existing mandatory and voluntary
GHG reporting programs at the State and
Federal levels (e.g., The Climate
Registry (TCR), several individual State
mandatory GHG reporting rules, EPA
voluntary partnership programs, the
DOE voluntary GHG registry).
In response to comments on ‘‘once in,
always in,’’ however, EPA has added
provisions to allow facilities and
suppliers to stop submitting annual
reports under certain conditions. These
provisions apply to facilities and
suppliers regardless of their
applicability threshold as it is based on
the annual report.
• Under the first provision, if any
facility’s annual GHG reports
demonstrate emissions of less than
25,000 metric tons of CO2e per year for
five consecutive years, they can cease
submitting annual reports. Similarly, if
any supplier’s annual reports
demonstrate that the products supplied
equate to less than 25,000 metric tons of
CO2e per year for five consecutive years,
they can cease submitting annual
reports.
• Under the second provision, if any
facility’s or supplier’s annual GHG
reports demonstrate emissions of less
than 15,000 metric tons CO2e per year
for three consecutive years, they can
cease submitting annual reports.
In either case, before they can stop
reporting, the facility or supplier must
submit a notification to EPA that
announces the cessation of reporting
and explains the reasons for the
reduction in emissions so EPA can
understand the reason for the decrease
in emissions to help aid in evaluating
emission reduction options across the
industry.
If emissions subsequently increase to
25,000 metric tons of CO2e or more in
any calendar year, the facility or
supplier must again begin annual
reporting. Importantly, although a
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source may not know its emissions (or
quantities supplied) exceeded the
reporting threshold until later in the
year, the requirements of the rule apply
as of January 1, unless the increase is a
result of a physical or operational
change covered by 40 CFR 98.3(b). Thus
sources close to the threshold should
consider monitoring their emissions
according to requirements of 40 CFR
part 98 if they determine there is a
chance they will meet or exceed the
threshold. EPA is developing tools and
guidance to assist facilities and
suppliers in assessing whether the
requirements of the rule apply to them.
EPA concluded that adding the
provisions to allow cessation of
reporting balances the need for a
complete dataset with the burden of
continued annual reporting by facilities
where there has been a change that has
consistently reduced emissions (or
supplier quantities) below 25,000 metric
tons CO2e. This approach rewards
actions taken to reduce emissions and
reduces the reporting burden. It is
consistent with other reporting
programs, such as the CARB mandatory
reporting rule and the WCI program,
both of which have mechanisms to
allow facilities to cease reporting if their
emissions are below a specified
threshold for multiple consecutive
years.
For the first provision, EPA selected
25,000 metric tons CO2e per year
because it is the same as the general
applicability threshold for this rule.17
We selected a 5-year period, instead of
a shorter time frame, because it allows
reporters that consistently report less
than 25,000 metric tons CO2e to stop
reporting, but avoids the situation
where a facility or supplier near this
level would be constantly moving in
and out of the reporting program due to
small variations from one year to the
next. Because this reporting rule is
based on actual rather than potential
emissions, such a situation would make
tracking of facilities and analyses of
trends difficult.
The second provision (cease reporting
if emissions were below 15,000 metric
tons for three consecutive years) was
added to reduce the duration of
reporting for facilities and suppliers that
reduce emissions to well below 25,000
metric tons. In such cases, a 5-year
period is longer than necessary to
17 Applicability thresholds for different source
categories are expressed in different ways (e.g.,
actual emissions, production capacity, ‘‘all-in’’), but
most correspond to a facility-wide emission level of
25,000 metric tons per year. The provision to cease
reporting applies to reporters regardless of the
specific applicability threshold that triggered
reporting for their facility or supply operation.
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demonstrate that annual emissions will
remain below 25,000 metric tons per
year. If emissions are less than 15,000
metric tons for three consecutive years,
it is unlikely that annual variation in
emissions would cause the facility or
supplier to exceed the threshold of
25,000 metric tons per year. The shorter
time period provides an incentive for
facilities that significantly reduce their
GHG emissions.
2. Provisions To Cease Reporting Due to
Closures
Comment: Several commenters
suggested that EPA add a provision to
allow closed facilities, or facilities or
suppliers that stop operating their GHGemitting processes, to cease annual
reporting.
Response: In response to comments,
EPA has added a mechanism to allow
facilities or suppliers that close all of
their GHG-emitting processes or
operations covered by the rule to cease
annual reporting. The reporter must
submit an annual report covering the
calendar year during which the closure
occurs. The reporter must also notify
EPA that they intend to cease reporting
and must certify that all GHG-emitting
processes and operations for which
there are methods in the rule have been
closed. EPA agrees that it does not make
sense for closed facilities or facilities
that close all of their GHG-emitting
processes to continue reporting
indefinitely or for the 5-year period
needed to demonstrate that emissions
are less than 25,000 metric tons CO2e
per year (or the 3-year period needed to
demonstrate emissions are less than
15,000 metric tons CO2e per year).
However, notification is required so that
we can track facilities and understand
why facilities stop reporting. If a facility
or supplier that was once subject to the
reporting rule and ceased reporting
under this provision restarts any of the
GHG-emitting processes or operations
formerly reported, then they must
resume annual reporting regardless of
whether they exceed the thresholds in
40 CFR 98.2(a) when they restart. This
provision is important so that EPA can
consistently track emissions from
facilities covered by the rule. If after the
restart, annual reports show emissions
of less than 25,000 metric tons CO2e per
year for five consecutive calendar years
or less than 15,000 metric tons CO2e per
year for three consecutive years, then
the facility could be exempt under the
separate mechanism discussed in
Section II.H.1 of this preamble.
It is important to note that the
provision to stop reporting is not
intended to apply to seasonal or longer
temporary cessation of operation. The
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mechanism is intended for long-term
closure situations. It should also be
noted that in order to use this provision
to cease reporting, a facility or supplier
must close all of their processes and
operations that are required to report
emissions. For example, consider a
facility that is required to report process
emissions from one or more source
categories covered by 40 CFR part 98
and general stationary fuel combustion
source emissions. If the facility closes
some of the process units subject to the
rule but continues to operate other
process units covered by the rule or
continues to operate stationary fuel
combustion sources, then they must
continue to submit annual reports until
the required annual GHG reports
demonstrate emissions of less than
25,000 metric tons of CO2e per year for
five consecutive years (or less than
15,000 metric tons of CO2e per year for
three consecutive years) and the facility
qualifies for the separate provisions to
stop reporting discussed in Section
II.H.1 of this preamble.
I. Summary of Comments and
Responses on General Content of the
Annual GHG Report
This section contains a brief summary
of major comments and responses on
the emissions information to be reported
under the general provisions (40 CFR
part 98, subpart A). See sections III.C
through PP of this preamble for
summaries of comments and responses
on specific reporting requirements for
the individual source categories
contained in 40 CFR part 98, subparts C
through PP. A large number of
comments on emission information to
report under the general provisions
were received covering numerous
topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart A: Content of the
Annual Report, the Abbreviated
Emission Report, Recordkeeping, and
Monitoring Plan.’’
Comment: EPA received a variety of
comments on the general content of the
annual GHG reports. Some commenters
objected to the level of detail required
in the annual GHG reports. Some
suggested reporting only facility-level
emissions and keeping as records more
detailed emissions breakouts (e.g., by
source category, process line, or unit)
and activity data used to calculate
emissions. Other commenters supported
the proposed general reporting
requirements.
Response: After reviewing the
comments, we have not made any major
changes in the general content of the
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annual GHG reports since proposal. The
final rule requires facilities to report
emissions from all source categories at
the facility for which methods are
defined in the rule. The General
Provisions (40 CFR part 98, subpart A)
require facilities to report total annual
GHG emissions in metric tons CO2e and
to separately present annual mass
emissions of each individual GHG
emitted from each source category at the
facility. 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 maintains
transparency, is valuable for future
policy and regulatory development, and
will help EPA quantify the relative
contribution of each gas to a source
category’s emissions and maintain
transparency.
Individual rule subparts for each
source category, rather than the General
Provisions, identify the specific data
elements to be reported for that source
category. Comments received on the
need for specific data elements are
described and responded to in Section
III of this preamble and in relevant
source category volumes of the
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments’’. Where appropriate, the
final rule has been modified based on
those comments. In general, reporting of
such data is required primarily to enable
emissions verification and ensure the
consistency and accuracy of data
collected under this rule. The
information is also needed to support
analyses of GHG emissions for future
CAA policy and program development.
Besides total facility emissions, it
benefits policy makers to understand:
(1) The specific sources of 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.
Many of these data are already routinely
monitored and recorded by facilities for
business reasons. Further discussion of
the selection of general reporting
requirements is contained in Section
IV.G of the proposal preamble (74 FR
16472, April 10, 2009). Other responses
to comments on the reporting
requirements in 40 CFR Part 98, Subpart
A, and discussion of some clarifications
made to the rule, are contained in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart A: Applicability
and Reporting Schedule’’, ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
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A: Content of the Annual Report, the
Abbreviated Emission Report,
Recordkeeping, and Monitoring Plan’’,
and ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart A:
Definitions, Incorporation by Reference,
and Other Subpart A Comments’’.
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J. Summary of Comments and
Responses on Submittal Date and
Making Corrections to Annual Reports
1. Submittal Date for Annual Report
Comment: Several commenters
requested that EPA change the annual
submittal date for GHG reports from
March 31 to a later date, such as April
30 or June 30. Several commenters
stated that March 31 does not provide
adequate time for data collection,
aggregation and disaggregation, GHG
calculations, QA, management review,
and certification, and explained that
this is a complex process for large
industrial sites that have many
individual GHG emission sources. Some
of these commenters indicated that
unexpected issues can arise during GHG
emissions calculations and QA that take
time to resolve. Some of these
commenters suggested a date of June 30
to align this mandatory reporting rule
with the submittal dates for other
reporting programs such as California
Climate Action Registry (CCAR), TCR,
Climate Leaders, and Toxic Release
Inventory (TRI). Some commented that
the same personnel who will prepare
the GHG reports are also involved in
preparing other EPA mandated reports
and that completing multiple reporting
activities in the first quarter is a large
workload. Other commenters favored
the March 31 reporting date so that the
data could be disseminated and
available for use by policy makers, EPA,
States, and the public in a timely
fashion.
Response: After reviewing and
addressing both general comments and
comments received on this issue for
specific source categories, and
considering the need to balance prompt
reporting with the burden on reporters,
EPA has determined that the reporting
deadline of March 31 allows a sufficient
amount of time for compiling,
reviewing, certifying, and submitting
annual GHG reports. The March
deadline will ensure timely collection of
the data necessary to inform decisions
regarding future GHG policy and
program development. Since the data
needed to calculate emissions and
prepare the report must be collected on
an ongoing basis throughout the year,
reporters can begin to compile the data
for the report and initiate QA activities
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during the year as the data are collected.
Reporters would then only have to
compile the most recently collected
information, complete the final
calculations, and review and certify the
annual report after the reporting period
has ended. Because the reports required
by the rule rely on well-defined
calculation methodologies, EPA
determined that three months is a
sufficient amount of time to complete
the report. Moreover, as discussed in
Section III of this preamble for the
specific subparts, we have made several
changes to reporting requirements that
will ease burden and further facilitate
reporting by March 31. In addition, EPA
intends to provide outreach and training
on rule requirements and an electronic
reporting system that will help expedite
report submission.
The March 31 reporting deadline is
also consistent with the reporting
deadline implemented in 2005 for
reporting GHG emissions under the EU
Emissions Trading System and is longer
than the deadlines allowed for reporting
under many other CAA programs. For
example, many NESHAPs and NSPSs,
including those for large complex
industrial facilities such as chemical
plants and refineries, require reports of
excess emissions and monitoring system
performance to be submitted within 30
calendar days of the end of each
compliance period. The ARP and
Regional Greenhouse Gas Initiative
(RGGI) programs, which are established
emission cap and trade programs that
rely on the same types of data many
sources will have to submit under the
GHG reporting rule, require facilities to
submit their quarterly emissions reports
within 30 days of the end of each
quarter.
requires the reporters to submit a
revised GHG report within 45 days of
discovering or being notified by EPA of
errors in an annual GHG report. The
revised report must correct all identified
errors. We agree that it is important for
facilities to correct errors, regardless of
whether they are discovered by the
reporter or by EPA. In order to ensure
accurate data for future GHG policies
and programs, known errors should be
corrected. Furthermore, adding a
requirement to submit corrected reports
is consistent with other EPA reporting
programs, such as ARP and TRI, as well
as State and other GHG programs. EPA
intends to review the annual GHG
reports submitted under this rule by
performing electronic data QA checks
and a range of other emission
verification activities. When we find
reporting errors (as we have in ARP and
other reporting programs), we will
notify reporters of errors and require
them to submit revised reports. The
time period of 45 days was selected to
allow reporters time to retrieve any
needed data, perform revised
calculations, and resubmit the report.
Because data for the calendar year
covered by the report has already been
collected and must be retained
according to the rule, it should be
readily available for any reanalyses
needed to correct a reporting error.
Given that facilities are allowed three
months from the end of a reporting
period to submit the annual report,
revising a report to address a known
error would logically require less time
and EPA concluded that 45 days is
sufficient.
2. Making Corrections to Annual
Reports
Comment: Several commenters
representing multiple stakeholders
suggested the rule should include
provisions to submit revised annual
reports. Many commented that even
with good-faith efforts to follow all the
monitoring and reporting requirements,
there will likely be unintentional errors
that are not discovered by the reporter
or by EPA until after an annual report
is submitted. Some commenters added
that given the stringency of the selfcertification provisions and potential
penalties involved, reporters need a way
to submit corrected data, and some
provided examples of other reporting
rules that include provisions to submit
revised reports.
Response: EPA has addressed this
comment in the final rule. We have
added a provision in 40 CFR 98.3 that
Comment: Some commenters
suggested that de minimis cutoffs or
simplified methods for de minimis
sources should be provided to be
consistent with other programs, such as
the California mandatory GHG reporting
rule. The commenters argued that it
makes sense to focus effort on the
significant emissions sources at a
facility, rather than spending a lot of
effort to precisely calculate emissions
from sources that are a small percent of
a facility’s total emissions.
Response: EPA considered public
comments on de minimis reporting,
both general comments and those
received on individual source
categories, in addition to the analyses of
de minimis provisions we conducted at
proposal of the rule. Based on these
considerations, we concluded that de
minimis provisions are not necessary for
this rule.
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K. Summary of Comments and
Responses on De Minimis Reporting
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As discussed in the preamble to the
proposal (74 FR 16448, April 10, 2009),
many existing reporting programs
require corporate level reporting of all
emissions, including emissions from
numerous remote facilities and small
onsite equipment (e.g., lawn mowers).
Other reporting programs require
reporting at the facility level but require
reporting of emissions from all types of
emission sources.18 These reporting
programs recognize that it may not be
possible or efficient to specify the
reporting methods for every source that
must be reported and include de
minimis provisions to reduce the
reporting burden. The de minimis
provisions included in these programs
either allow the reporter to exclude a
portion of their emissions (e.g., the DOE
1605(b) voluntary reporting program
allows up to three percent of facilitylevel emissions to be excluded) or allow
simplified calculation methods for small
sources.
Since reporters must determine the de
minimis emissions even when reporting
is not required, the trend for both
mandatory and voluntary reporting
programs is to require reporting of all
emissions but allow simplified
calculation methods for small sources of
emissions. Hence, the de minimis
provisions included in many existing
reporting programs are designed to
avoid potentially unreasonable
reporting burdens. For example, TCR
allows reporters to use simplified
calculation methods of their own design
for calculating up to five percent of their
emissions. Some programs recognize
that a small percentage of emissions
may still represent a large mass of
emissions. For this reason, some
existing reporting programs include a
cap on the mass of de minimis
emissions. For example, both the
California mandatory reporting rule and
EU Emissions Trading System cap de
minimis emissions at 20,000 metric tons
CO2e/year cap. 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–
2008–0508–0048).
In contrast to such existing programs,
this rule already avoids burdensome
reporting requirements for smaller
emissions sources in two ways. First,
the rule excludes small facilities
through the application of the 25,000
metric tons of CO2e threshold. As
18 For additional information about these
programs please see overview of existing programs
(EPA–HQ–OAR–2008–0508–0052) and the de
minimis memo (EPA–HQ–OAR–2008–0508–0048).
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described earlier in this preamble, that
threshold appropriately balances the
number and size of reporter with the
coverage of emissions. The source
categories included in the rule are
typically for larger sources of emissions.
Second, reporters must report only the
emissions from sources for which
calculation methods are provided in the
rule. Calculation methods are generally
not included for smaller sources of
emissions (e.g., coal piles on industrial
sites). In some cases, where a source
category includes relatively small
sources, the rule provides simplified
emissions calculation methods for those
sources. For example, reporters may use
a default emission factor and heat rate
to calculate emissions from small
stationary combustion units, rather than
the fuel measurements required for
larger stationary combustion units.
Given that this rule has taken steps to
avoid burdensome calculations, we have
concluded that de minimis reporting
cutoffs are not necessary.
Furthermore, de minimis cutoffs
would compromise the quality of the
data collected. The goal of this rule is
to collect accurate and consistent data of
sufficient quality to inform future CAA
policy and regulatory decisions.
Allowing sources to report up to 20,000
metric tons CO2e emissions annually
using their own simplified calculation
methods (as allowed under some
programs) would impact the usefulness
of the data. The reported emissions
would not be comparable across a given
industry because the calculation
methods, accuracy and reliability of a
portion of the reported emissions would
vary substantially from one reporter to
another.
In response to comments, we have
made several changes to this rule that
further reduce any need for a de
minimis reporting provision. As
discussed in Section III of this preamble
for individual source categories, we
have revised monitoring and reporting
requirements to allow simpler GHG
calculation methods for many
combustion units and other source
categories. These changes reduce the
reporting burden for various types of
small emission sources. Also, as noted
earlier in Section II.D of this preamble,
there are a number of source categories
that are not being finalized at this time.
A few of them (e.g., industrial landfills
and wastewater) represent the type of
emission sources that commenters
referenced as de minimis at some
facilities. EPA is taking some additional
time with these source categories, which
affects commenters in two ways: (1)
Until EPA promulgates a final rule for
these source categories, these emissions
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would not be included in a facility’s
annual report and (2) EPA can further
consider the comments and evaluate our
options with respect to the methods for
these source categories to ensure the
methods adequately address our need
for high quality data as well as
recognize the commenters’ requests for
additional flexibility for smaller
sources.
L. Summary of Comments and
Responses on General Monitoring
Approach
This section contains a brief summary
of major comments and responses on
general monitoring requirements. See
sections III.C through PP of this
preamble for summaries of comments
and responses on specific monitoring
requirements for the individual source
categories contained in 40 CFR part 98,
subparts C through PP. A large number
of comments were received on general
monitoring requirements covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, General Montoring
Approach, the Need for Detailed
Reporting, and Other General Rationale
Comments.’’
Comment: Many commenters favored
the general monitoring approach
contained in the proposed rule, which
is a combination of direct emissions
measurement and facility-specific
calculations. These commenters agreed
that the selected approach results in
high quality data and strikes a
reasonable balance between data
accuracy and cost. Other commenters
believed that the approach contained in
the proposed rule is overly stringent and
costly. They contended that since the
data are not being used to demonstrate
compliance with a cap and trade
program or other regulation with
emission limits or emissions reduction
requirements, a lower level of accuracy
is acceptable, simpler monitoring
approaches should be allowed, and/or
facilities should have flexibility to
choose monitoring methods. Some
commenters requested clarification on
whether there were accuracy
requirements or performance standards
for flow monitoring equipment, outside
of the accuracy requirements already
required for CEMS. Some commenters
requested clarification on whether
upgrades to CEMS were needed under
various circumstances. Some requested
additional time for upgrading CEMS or
installing and calibrating other
equipment such as flow meters.
Response: After reviewing the
comments in light of the analysis
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presented in Section IV.H of the
preamble to the proposed rule (74 FR
16474, April 10, 2009), EPA decided not
to change the general monitoring
approach from the proposal. In general,
the rule requires direct measurement of
emissions from certain units that
already are required to collect and
report data using CEMS under other
programs (e.g., ARP, NSPS, NESHAP,
State Implementation Plans (SIPs)). In
some cases, this may require upgrading
existing CEMS that currently monitor
criteria pollutants to also monitor CO2
or add a volumetric flow meter. For
facilities with units that do not have
CEMS installed, reporters have the
choice to either install and operate
CEMS to directly measure emissions or
to use facility-specific GHG calculation
methods. The measurement and
calculation methods for each source
category are specified in each subpart.
As policies and programs evolve and/or
particular calculation or monitoring
equipment improves EPA will evaluate
whether or not to update the
methodologies in this rule.
The data collected by the rule are
expected to be used in analyzing and
developing a range of potential CAA
GHG policies and programs. A
consistent and accurate data set is
crucial to serve this intended purpose.
Therefore, the selected monitoring
approach that combines direct
measurement and facility-specific
calculations is warranted even though
the rule does not contain any emissions
limits or emissions reduction
requirements. EPA remains convinced
that this approach strikes an appropriate
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., the California
mandatory reporting rule, WCI, RGGI,
TCR, and Climate Leaders). Because this
option specifies methods for each
source category, it will result in data
that are comparable across facilities.
EPA chose not to adopt simplified
calculation methods as a general
monitoring approach (e.g., using default
emission factors) because the data
would be less accurate than under the
selected option and would not make use
of site-specific data that many facilities
already have available and refined
calculation approaches that many
facilities are already using. EPA is not
allowing reporters full flexibility to use
any method because the accuracy and
reliability of the data would be
unknown. Because consistent methods
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would not be used under such an
approach, the reported data would not
be comparable across similar facilities.
While the general approach is
unchanged, it is important to note that
EPA has made changes to the General
Provisions and to the specific
monitoring requirements for particular
source categories in response to public
comments on the proposal. EPA has
added to the General Provisions (40 CFR
part 98, subpart A) an accuracy
specification of plus or minus five
percent for the calibration of flow
meters used to collect data for the
emissions calculations under this rule.
It provides procedures for calculating
calibration error, including specific
procedures for orifice, nozzle, and
venturi flow meters. Given the
comments that were submitted
regarding concerns on the timing of
performing meter calibration, EPA is
providing flexibility to reporters subject
to certain operational limitations. For
example, facilities that operate
continuously may postpone calibration
until the next scheduled maintenance
outage to avoid operational disruptions.
Individual rule subparts for each
source category, rather than the General
Provisions, contain the specific
monitoring methods for that source
category. Comments received on the
specific methods are described and
responded to in Section III of this
preamble and in the relevant source
category volumes of ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments.’’ Where
appropriate, the final rule has been
modified based on those comments. For
example, since proposal, in response to
public comments, EPA has made
changes to individual subparts of 40
CFR part 98 to clarify when CEMS and
CEMS upgrades are required and has
made other changes to reduce the
monitoring burden. Interested parties
are encouraged to review the relevant
sections of the preamble and rule.
Furthermore, some subparts for which
significant monitoring approach
comments were received are not
included in the final rule and will be
finalized later as explained in Section
II.D of this preamble. These changes to
the rule address monitoring approach
concerns raised by some commenters.
Comment: Some commenters
expressed concern that duplicative
reporting would occur if the rule was
interpreted to require a reporter to
submit data on general stationary fuel
combustion emissions at a facility both
under 40 CFR part 98, subpart C and
also under one of the other source
category subparts that applies to the
same facility. Some of them indicated
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that language used in the source
category subparts to reference subpart C
was not sufficiently clear and
consistent. Other commenters indicated
the proposed rule was not clear about
whether CEMS can be used to report
combustion emissions, process CO2
emissions, or combined emissions.
Response: EPA reviewed each subpart
in light of these comments and
acknowledges that the proposed rule
language referencing 40 CFR part 98
subpart C and the language discussing
the of CEMS was inconsistent between
subparts and was not always clear. EPA
has revised the final rule to clarify our
intent.
As indicated by the commenters,
many manufacturing facilities are
subject to one of the source category
subparts and also to the general
stationary fuel combustion subpart. For
most facilities, emissions from
stationary fuel combustion sources (e.g.,
boilers or engines) are emitted from
separate equipment and through
separate stacks/emission points than
process GHG emissions covered by 40
CFR part 98, subparts E through GG. We
have edited the rule to make it clear that
in such cases, the reporter would report
stationary fuel combustion emissions
under 40 CFR part 98, subpart C, and
they would report process GHG
emissions under each applicable source
category subpart.
We have further clarified those source
category subparts that require reporting
of process CO2 emissions. We have
made it clear that the reporter can elect
to monitor and report process CO2
emissions by either: (1) Installing and
operating CEMS and following the Tier
4 methodology in 40 CFR part 98,
subpart C, or (2) using the source
category-specific monitoring and
calculation procedure specified in the
subpart. In either case, process CO2
emissions would be reported under the
source category subpart. The source
category subparts have also been revised
to specify that if process CO2 emissions
are comingled with and emitted through
the same stack as emissions from
combustion units or process equipment
required to use CEMS, than the reporter
must use the CEMS and follow the Tier
4 methodology to report combined
emissions from the common stack under
the specified subpart. This approach
makes sense for comingled emissions
because CEMS accurately measure total
stack CO2 emissions and the reporter
would not be able to accurately separate
the fraction of the CO2 emissions that
came from the combustion units and
process emission points that are
comingled in the same stack.
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Source categories with direct-fired
equipment (e.g., kilns, furnaces) present
a special situation. Examples include
cement production, glass production,
lead production, lime manufacturing,
and soda ash manufacturing. In directfired units, fuel combustion emissions
and process emissions are both
generated within the kiln or furnace and
are always emitted together. If CEMS are
used on such units, the CEMS will
always be measuring combined
combustion and process emissions. The
language regarding CO2 reporting and
use of CEMS for these source categories
has been clarified and harmonized to
reflect this situation.
• For kilns or furnaces in these source
categories that have CEMS in place and
meet specified conditions, the reporter
must use the CEMS and follow Tier 4
methodology to determine combined
process and combustion CO2 emissions.
The combined emissions are reported
under the relevant source category
subpart (e.g., for cement production,
combined combustion and process
emissions from a kiln with a CEMS
would be reported under 40 CFR part
98, subpart H, Cement Production).
• For other kilns or furnaces in these
source categories, the reporter has the
choice to (1) install and operate CEMS
to measure combined process and
combustion CO2 emissions, or (2)
calculate process CO2 emissions using
the source category-specific monitoring
and calculation procedures contained in
the subpart. If reporters don’t have
CEMS and choose the source categoryspecific calculation approach, then they
report process CO2 emissions under the
relevant source category subpart, and
report combustion emissions under 40
CFR part 98, subpart C (general
stationary fuel combustion).
See the sections for the relevant
source categories in Section III of this
preamble for summary and discussion
of the specific monitoring and reporting
requirements for each source category.
M. Summary of Comments and
Responses on General Recordkeeping
Requirements
This section contains a brief summary
of major comments and responses on
the general recordkeeping requirements
contained in the general provisions (40
CFR part 98, subpart A). See sections
III.C through PP of this preamble for
summaries of comments and responses
on specific recordkeeping requirements
for the individual source categories
contained in 40 CFR part 98, subparts C
through PP. A large number of
comments were received on general
recordkeeping requirements covering
numerous topics. Responses to
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significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart A, Content of
the Annual Report, the Abbreviated
Emission Report, Recordkeeping, and
the Monitoring Plan’’ and in the
individual source category volumes of
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments.’’
1. Record Retention
Comment: Several commenters
suggested that EPA require retention of
records for three years rather than the
five years specified in the proposed
rule. Some of these commenters stated
that three years is consistent with ARP,
which is a comparable program that
requires electronic reporting of similar,
detailed data. Many contended that
retaining the large amount of data
required by this rule for five years rather
than three years is overly burdensome
and is not necessary. They indicated
that three years of records is sufficient
to allow verification of annual GHG
reports. A smaller number of
commenters supported record retention
for five years, which is consistent with
permitting and other programs.
Response: In response to public
comments, EPA has changed the record
retention requirement in the final rule
from five years to three years.19 We
agree that a 3-year time period is
sufficient to allow for EPA audit and
review of records needed to verify the
emissions data submitted in annual
reports. Changing the record retention
duration to three years will reduce the
recordkeeping burden for many
facilities reporting under this rule. As
stated by various commenters, a 3-year
record retention requirement would be
consistent with the recordkeeping
provisions of the ARP and other Federal
reporting programs, including the TRI
rules and the DOE Energy Information
Administration’s 1605(b) Voluntary
Reporting of GHG Emission and
Reductions program.
2. Monitoring Plan
Comment: We received several
comments on the QAPP recordkeeping
requirement in proposed 40 CFR 98.3(g).
Some had questions about the content
and level of detail required in the
19 As described earlier in this section, facilities or
suppliers that have emissions or products with
emission less than 25,000 metric tons CO2e for five
years in a row may cease reporting. Those that cease
reporting must have records to cover those five
years of emissions. Similarly, reporters who
demonstrate emissions less than 15,000 metric CO2e
for three years is a row may cease reporting, and
must have records to cover those three years of
emissions.
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QAPP, and indicated it would be a
costly and burdensome requirement.
Others stated that the QAPP would be
duplicative of their facility SOPs or
documentation kept under ARP or other
programs. Some commenters indicated
that the list of items to report in 40 CFR
98.3(g) was repetitive because a few of
the items listed separately would
typically be contained in a QAPP.
Response: The final rule requires a
‘‘monitoring plan.’’ The ‘‘QAPP’’
terminology in the proposed rule caused
confusion because ‘‘QAPP’’ is used in a
variety of other contexts, has various
connotations to different readers, and
caused readers to presume requirements
EPA did not intend. The final rule
specifies monitoring plan contents such
as:
• Identification of persons
responsible for collecting emissions
data.
• Explanation of the processes and
methods used to collect the necessary
data for the GHG emissions calculation.
• Description of the procedures that
are used for QA, maintenance, and
repair of all CEMS, flow meters, and
other instrumentation used to provide
data for the GHG emissions reported
under 40 CFR part 98.
The first two items in this list were
formerly listed as separate line items in
the recordkeeping requirements, but
would logically be a part of the
monitoring plan, so were consolidated
under the monitoring plan to avoid
repetition.
The monitoring plan paragraph in the
final rule explicitly states that the
monitoring plan can rely on references
to existing corporate documents. Such
documents include SOPs, QA programs
under Appendix F to 40 CFR part 60 or
Appendix B to 40 CFR part 75, and
other documents provided that the
information required by the monitoring
plan is clearly recognizable. The
provision allowing the monitoring plan
to refer to such documents avoids
duplicative effort and addresses the
commenters’ concerns that monitoring
plan information is already contained in
other documents.
The final rule also contains a
provision to update the monitoring
plan. Reporters need their monitoring
plan to be up to date in order to ensure
that facility or supplier personnel follow
the right monitoring and QA procedures
and that the reporter meets the
requirements of the reporting rule.
Likewise, EPA needs to be able to view
an up-to-date monitoring plan during
facility audits. Updates to the plan
would be needed if, for example, the
facility makes a process change, changes
monitoring instrumentation or QA
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procedures, or improves procedures for
maintenance and repair of monitoring
systems to reduce the frequency of
monitoring equipment downtime.
N. Summary of Comments and
Responses on Emissions Verification
Approach
This section contains a brief summary
of major comments and responses on
emissions verification of the GHG
reports. A large number of comments
were received covering numerous
topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Approach to Verification
and Missing Data.’’
Comment: Many commenters,
including most facilities and suppliers
required to report under the rule and
several other stakeholders, supported
EPA’s proposal to require selfcertification with EPA verification of
GHG reports. These commenters
provided a variety of reasons. Many
supported EPA emissions verification
because the alternative of third party
verification would be more costly to
reporters. Several also commented that
EPA emissions verification would
provide a consistent and transparent
data set.
Other commenters suggested that EPA
require third party verification of GHG
reports, and they provided a variety of
reasons. A few noted that third party
verification is consistent with other
GHG reporting systems (e.g., the
European Emissions Trading Scheme,
The Climate Registry, the California
mandatory GHG reporting rule, and
other State programs). Many stated that
third party emissions verification will
improve the quality of the data
submittals and told us that third party
verification led to the correction of
inaccuracies in GHG emission reports
submitted under other programs. Some
of the commenters questioned whether
EPA would have the time to conduct
verification, given the number of reports
and volume of supporting data that
must be submitted. Others were
concerned that EPA verification requires
submittal of detailed supporting data
and contended that some of these
supporting data would be CBI.
A smaller number of commenters
favored self-certification without
independent emissions verification.
They believed the designated
representative provisions in the rule
would cause reporters to take selfcertification seriously and ensure the
emissions they report are correct. Some
also stated that independent verification
is not needed for a reporting program
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that does not require emissions
reductions.
Response: In selecting the approach to
emissions verification, EPA reviewed all
of the comments, as well as emissions
verification requirements and
procedures under a number of existing
EPA regulatory programs and domestic
and international GHG reporting
programs. Based on this review, EPA
considered three alternatives: (1) Selfcertification without independent
verification, (2) self-certification with
third party verification, and (3) selfcertification with EPA verification. For
this particular program, EPA is not
changing the verification approach from
the proposal and is requiring selfcertification with EPA emissions
verification. We decided to retain this
verification approach because it
provides greater assurance of accuracy
and impartiality than self-certification
without verification, and has a number
of advantages over third party
verification for this type of Federal
program. Our objective with emissions
verification in this program is to ensure
collection and dissemination of highquality data while providing the
reporters a ‘‘level playing field’’ in terms
of requirements and process.
To enable effective review of the large
volume of data reported, the rule
requires reporters to submit data
electronically in a standard format
through a centralized data system. EPA
is developing this system and intends to
make it available to reporters, along
with training and instructional
materials, before the reporting
deadlines. To the extent possible, EPA
will leverage existing reporting systems
and work with other State and regional
programs and systems to develop a
reporting scheme that minimizes the
burden on reporters.
In implementing the emissions
verification under this rule, EPA
envisions a two step process. First, we
will conduct an initial centralized
review of the data which will be largely
automated. EPA intends to build into
the data system an electronic data QA
program for use by reporters and EPA to
help assure the completeness and
accuracy of data. In addition, to verify
reported data and ensure consistency,
EPA may review facility-level
monitoring plans and procedures, and
will perform detailed, automated checks
on data utilizing recent and historical
data submittals, comparison against like
facilities and/or other electronic audit
tools where appropriate. Second, EPA
intends to follow-up with facilities
should potential errors, discrepancies,
or questions arise through the review of
reported data and conduct on-site audits
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of selected facilities. The on-site audits
may be conducted by private verifiers
contracted by EPA or by Federal, State
or local personnel, as appropriate. We
plan to coordinate closely with the
States to develop an efficient approach
toward on-site auditing that can meet
the needs of multiple programs. We do
not anticipate conducting on-site audits
of every facility every year.
EPA decided to finalize the rule with
EPA emissions verification for several
reasons. First, we determined that the
combination of comprehensive
electronic review and a flexible and
adaptive program of on-site auditing
will enable us to effectively target
verification resources while also
providing the necessary consistency and
quality in the data. Utilizing the
national data set developed under this
rule will provide unique resources for
the review of reports. A centralized
emissions verification system provides
greater ability for EPA to identify trends
and outliers in data and thus assist with
targeted follow-up review, and our
approach can evolve over time as we
gain experience with GHG reporting.
This approach also provides
opportunity to work closely with and
leverage both the experience and
ongoing activities of States and others
already engaged in similar and different
types of GHG reporting.
Our emissions verification approach
in this rule is consistent with other EPA
emission reporting programs and
follows a model similar to the ARP
which is a highly successful emissions
cap and trade program that consistently
produces credible, high-quality data.
Facilities regulated under ARP must
have a Designated Representative sign
data reports to self-certify that the
reported data are accurate. Then,
facilities and EPA use a series of
electronic tools to ensure proper data
collection and reporting, including
establishing a monitoring plan,
calibrating equipment to certain
specifications, frequent testing and data
submittal. Similar to what we are
intending with this program, EPA
conducts site audits on those facilities
targeted during the electronic review as
having been outliers or had anomalies
in their reported data. These audits are
done by EPA personnel, States and/or
contractors to EPA. We support these
audits by providing a field audit manual
to both government and private auditors
as well as additional training to State
and Federal auditors.
Second, this approach is the best way
to address the many comments we
received on the importance of obtaining
2010 data and making the data widely
available. EPA has determined that this
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verification approach will enable us to
make data available more quickly than
under a third party verification
approach. We will be able to share a
complete data set promptly upon
completion of the electronic review
(subject to relevant CBI concerns, please
see the discussion of our plans to
address CBI and emissions data in
Section II.S of this preamble and
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Legal Issues’’). We
determined that the third party
verification approach could take from
three to six months after initial data
submission, and EPA would still need
to review and perform consistency
checks after the third party verification
was complete.
In addition, developing the third
party verification approach would
require EPA to establish and develop
emissions verification protocols and a
system to qualify and accredit the third
party verifiers, and to develop and
administer a process to ensure that
verifiers hired by 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. Even if EPA were to partner
with an existing program or
organization to accredit verifiers, EPA
would still need to develop the criteria
and systems described above to
implement this rule and ensure high
quality emissions verification given the
unique reporting requirements of this
rule. These efforts would slow down
implementation of the rule and sharing
of data.
Finally, we agree with many of the
commenters regarding their concerns
about the cost of third party verification.
Given the information currently
available to us, under a third party
verification approach we would have
required that each facility verify its
submission each year. As a national
reporting program with a substantially
larger number of reporters than existing
State programs, we determined that the
costs to the reporters of third party
verification would have been
substantial. By finalizing selfcertification with EPA emissions
verification for this rule, it also ensures
a lower cost burden for reporters.
EPA’s decision to use self certification
with EPA emissions verification was
made in the context of the specific
scope of this rulemaking, the types of
data to be collected, and the intended
uses of the emissions data. For other
types of programs (e.g., offsets,
corporate footprinting, energy
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efficiency) other verification approaches
may be more suitable. We recognize that
many GHG reporting and reduction
programs developed by the States and
Regions are broader in scope and for
this and other reasons, the use of third
party verifiers is an appropriate way to
verify the data they collect. EPA’s
decision in this rulemaking does not
preempt State GHG reporting programs
or any other programs from requiring
third party verification. More
importantly, the selection of EPA
emissions verification for this rule is not
intended to suggest that third party
verification cannot result in accurate,
high quality data.
EPA received a smaller number of
comments in support of selfcertification without emissions
verification. While recognizing that this
approach would place a low burden on
both reporters and the government, it
also has major disadvantages. Without
any verification of submitted reports,
there is far greater potential for
inconsistent and inaccurate data and
this will result in less confidence at EPA
and with public stakeholders in the
data. These disadvantages would make
the data collected under this option less
useful for informing decisions on
climate policy and supporting the
development of potential future policies
and regulations.
Comment: Commenters asked what
role State and local regulatory agencies
will have in verification of reported
emissions data. Some suggested that
State and local agencies should assist
with emissions verification because they
already have detailed knowledge of the
facilities in their areas. Some indicated
that States would need resources to play
a role in verification and other rule
implementation activities.
Response: While EPA is responsible
for emissions verification as explained
in the previous response, EPA will
likely enlist State assistance, when it is
available, during the implementation
phase of the final rule. (However, State
and local agencies will not be required
to provide EPA any assistance with
verification or implementation
activities, given State and local agency
resource constraints and priorities.) For
example, in concert with their routine
inspection and other compliance and
enforcement activities for other CAA
programs, State and local agencies
could, as resources allow, assist with
educating facilities and assuring
compliance at facilities subject to this
rule.
Assistance from State and local
agencies could include such activities as
identifying the facilities for on-site
audits or conducting audits where
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appropriate. This type of assistance
from State and local governments has
been valuable in other programs. State
and local air pollution control agencies
routinely interact as part of other
regulatory programs with many of the
sources that would report under this
rule. States have knowledge of specific
facilities and sources that would be
required to report under this rule. In
addition, many States have already
implemented or are in the process of
implementing GHG reporting and
reduction programs. Therefore, some
State and local agencies could serve a
role in communicating the requirements
of the rule and providing compliance
assistance.
O. Summary of Comments and
Responses on the Role of States and
Relationship of This Rule to Other
Programs
This section contains a brief summary
of major comments and responses. A
large number of comments on the
relationship between this rule and other
programs were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Relationship to Other
GHG Reporting Programs’’ and
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Legal Issues.’’
Comment: Several commenters
requested that EPA make it clear that
States can collect additional GHG data
under State rules and GHG programs
and are not limited to collecting only
the data in this Federal mandatory
reporting rule. Other commenters
requested that this rule preempt or
supersede State GHG reporting rules.
Response: EPA reaffirms that States
can collect additional data under State
rules and GHG programs, and that this
rule does not preempt or replace State
reporting programs. This rule has been
developed in response to a specific
request from Congress (in the
Appropriations Act) and is narrower
and more targeted than many existing
State programs that are coupled with
GHG emission reduction programs. As
EPA stated in Section II of the proposal
preamble (74 FR 16457, April 10, 2009)
and Section I.E of this preamble, many
State programs are broader in scope, in
a more advanced state of development,
and have different policy objectives
than this rulemaking. These are
important programs that not only led
the way in reporting of GHG emissions
before the Federal government acted but
also have catalyzed important GHG
reductions.
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EPA supports and recognizes the
success and necessity of State programs
as a vital component in achieving GHG
emissions reductions, particularly those
focused on energy efficiency
improvements. It is appropriate that
State and regional GHG reporting and
reduction programs have different
scopes or implementation schedules,
and that they require reporting of
different information than this rule for
various program-specific reasons. For
example, some State programs might
require reporting of electricity
purchases and other data to provide
information for energy efficiency
programs; they may require or allow
reporting of a variety of indirect
emissions to gather data to help
facilities reduce their carbon footprint;
they may require or allow reporting of
emissions such as from fleet vehicles to
encourage fleet operators to take steps to
reduce emissions; or they may be
developing or implementing GHG
reduction rules including cap and trade
programs, and require specific
information on emissions and offsets to
implement those programs. State
programs already have, or may evolve to
include, additional monitoring and
reporting requirements than those
included in this rule. Many States are
actively collecting additional data they
need for their programs and policies,
and this reporting rule does not preempt
State programs.
Comment: Some commenters were
concerned that the Federal GHG
reporting rule will result in duplicative
reporting for facilities that are also
reporting GHG emissions under State
rules or voluntary GHG reporting
programs. Some requested that to
reduce burden, facilities should be
required to submit data only once, and
not have to submit different data to
multiple different programs. Some
commenters strongly recommended that
the electronic data systems used by this
reporting rule and other programs need
to be consistent and allow data
exchange between this rule and TCR,
State rules, National Emissions
Inventory (NEI), ARP, or other
programs. Many commenters supported
submittal of all data directly to EPA,
while others favored delegation of data
collection to State agencies to encourage
consistency between State and Federal
data collection efforts.
Response: EPA carefully considered
the issue of State delegation,
particularly in light of the leadership
and experience of several States in
developing GHG reporting and
reduction programs, and also in the
context of the pressing need for a
national reporting program and the
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strong emphasis placed by the vast
majority of the commenters on this rule
for EPA to ensure that data collection
begins on January 1, 2010 and that data
are reported early in 2011. We
determined that developing a program
to delegate to States would take
additional time and would not be
available for 2010 reporting, and we also
determined that a significant number of
States would likely not request
delegation, which would increase the
complexity of assembling a consistent
national data set. For these reasons, we
determined that the most effective way
to achieve nationwide GHG reporting of
2010 data was for reporters to submit
data directly to EPA, as proposed.
Additional reasons for selection of this
data flow approach are described in the
response on emissions verification in
Section II.N of this preamble, the
responses on collection, management,
and dissemination of GHG emissions
data in Section V of this preamble, and
the responses on compliance and
enforcement in Section VI of this
preamble.
While EPA is not formally delegating
rule implementation and enforcement to
States, we are committed to working in
partnership to address the issues
expressed in their comments on
interaction between State and Federal
reporting programs. Design and
implementation of electronic systems
for data systems has been an area of
particular focus in determining how to
ease reporting burdens and facilitate use
of the many different types of data
collected by State and Federal reporting
programs by all levels of government.
EPA is committed to working with
States to develop electronic reporting
tools that can both collect and share
data in an efficient and timely manner.
At this time, EPA is in the process of
developing the reporting format and
tools and therefore has not specified the
exact reporting format, other than it will
be electronic, in order to maintain
flexibility to modify the reporting
format and tools in a timely manner. To
the extent possible, EPA will work with
existing reporting programs and systems
to develop a reporting scheme that
minimizes the burden on sources.
EPA recognizes the need to develop
reporting tools that can support
reporting across programs that collect
different types of data, and we intend to
coordinate with States and other
organizations to explore development of
shared web-based tools that can
simplify and expedite reporting. We
recognize that State and regional
programs may be collecting additional
GHG information beyond what is
required in this rule. For example, many
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of these programs collect emissions data
on fleet vehicles, indirect emissions
data for utility purchase, and other data
not required by the Federal rule.
Moreover, our rule requires reporting of
additional data necessary for emissions
verification, which is likely more
expansive than what many existing
State and regional programs are
collecting. For example this rule
requires reporting of emissions at the
process or unit level for many source
categories, rather than the company or
facility level as allowed by various other
mandatory and voluntary reporting
programs. We will also collect detailed
monitoring data and activity data used
to calculate emissions, which will
enable emissions verification. We are
interested in working with others to
determine the extent to which shared
tools can be designed to facilitate
reporting across multiple programs,
consistent with obligations regarding
CBI.
EPA carefully reviewed Federal, State,
and international voluntary and
mandatory programs during
development of the reporting rule and
attempted to be consistent with the GHG
protocols and requirements within these
rules, to the extent feasible given the
differing scopes and policy objectives.
(See Section II of the preamble for the
proposed rule (74 FR 16457, April 10,
2009), the Review of Existing Programs
memorandum (EPA–HQ–OAR–2008–
0508–052), and the memorandum
summarizing State mandatory rules
(EPA–HQ–OAR–2008–0508–054).) EPA
has worked with and will continue to
coordinate closely with other Federal,
State, and regional programs to facilitate
data exchange when designing the data
reporting systems that will be used for
the rule and planning implementation
activities. We will work with the States,
TCR, and others on data exchange
standards to ease sharing of data
between systems, consistent with CBI
obligations. And finally, we see
substantial opportunities for EPA and
States to cooperate on strategic efforts to
identify uses of the data collected under
this rule and work together on a broad
array of climate change issues.
P. Summary of Comments and
Responses on Other General Rule
Requirements
This section contains a brief summary
of major comments and responses on
other general rule requirements. A large
number of other general comments were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
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Response to Public Comments’’ volumes
on subpart A.
1. Research and Development
Comment: Commenters representing
institutions and industries subject to the
reporting rule requested an exclusion
for R&D activities. They noted that the
aluminum production and glass
production subparts of the proposed
rule excluded R&D process units, but
requested that R&D be excluded from
the rule as a whole, not only from the
two subparts. Some also commented
that the exclusion should encompass
R&D activities other than R&D process
units, including bench scale laboratory
research and pilot plants. Commenters
pointed out that many other EPA air
rules exclude R&D and they explained
that R&D activities are small-scale,
emissions change frequently as the
focus and scope of the R&D activity
changes, reliable information on CO2e
emissions during any particular phase
of the research might not be available,
and quantifying R&D emissions would
impose a high burden relative to the
quantity of emissions.
Response: In response to these public
comments, EPA has added an R&D
exclusion in 40 CFR 98.2(a)(5) stating
that R&D activities are not considered to
be part of any source category defined
in 40 CFR part 98. Because R&D
activities are not included in any source
category, their GHG emissions are not
reported. EPA agreed with the
commenters that R&D process units and
laboratory R&D for new processes,
technologies, or products should be
excluded. It is not reasonable to
calculate GHG emissions from processes
and activities that continually change as
the research focus changes and have
highly variable inputs and operating
conditions due to their R&D nature.
Also, emissions from R&D are expected
to be small. Therefore, the final rule
defines R&D as activities conducted in
process units or at laboratory bench
scale settings whose purpose is to
conduct R&D for new processes,
technologies, or products, and whose
purpose is not for the manufacture of
products for commercial sale, except in
a de minimis manner.
We point out that the exclusion
applies to each individual R&D activity
that meets the R&D definition, not to an
entire facility as a whole. For example,
a facility that has some commercial
process units and some R&D process
units can exclude only the R&D process
units. A facility that meets the
applicability criteria in 40 CFR part 98,
subpart A and contains general
stationary combustion sources must
report emissions from the combustion
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units, even if the steam, heat, or
electricity generated by a combustion
unit is used in an R&D process unit.
Laboratory activities are excluded only
if they are for R&D purposes. Laboratory
analyses activities conducted for
commercial purposes, process operating
purposes, or to comply with a rule
would not be excluded.
We decided not to include pilot
plants in the definition of R&D. Pilot
plants that meet the rule applicability
criteria must report their GHG
emissions. Pilot plants tend to be
relatively large in scale compared to the
excluded R&D activities. Because pilot
plants are designed to prove the
viability of a particular process or
technology rather than to research a
wide range of processes and products,
their operations and emissions are more
consistent than the excluded R&D
activities. Pilot plants also tend to be
operated for relatively long periods of
time and in some cases are converted to
commercial facilities. For these reasons,
EPA views the data as more useful and
has not applied the R&D exclusion to
pilot plants.
2. Determining Applicability
Comment: Some commenters were
concerned that the GHG reporting rule
will virtually require every commercial
and industrial facility to collect fuel
usage data and perform relatively
complex calculations, and in some cases
modeling, in strict accordance with the
prescribed monitoring methodologies
and emissions calculation procedures,
to determine if they are subject to the
rule. The commenters added that this
will be burdensome, especially for small
sources that will just be documenting
that the calculated GHG emissions from
the facility are well below the reporting
threshold. They also indicated that
recordkeeping would be needed to show
that facilities are below the reporting
threshold, and anticipated that the rule
will be nearly as burdensome on
facilities that do not have to report, as
on those that must report. Many of the
commenters asked that EPA provide
simplified source category thresholds to
determine applicability, like the 30
mmBtu/hr aggregate maximum rated
heat input capacity for stationary fuel
combustion units, to reduce the burden
on the majority of facilities making
applicability determinations.
Response: We disagree that the initial
applicability determination process is
burdensome. While the rule requires
reporters who are subject to the rule to
determine applicability using the
calculation procedures required in the
rule, the rule does not contain any
requirements for facilities that are not
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subject to the rule. Therefore, the rule
does not necessarily require monitoring
in 2010 to determine applicability. To
determine applicability, anyone who
believes their facility might be subject to
the rule could start by calculating
emissions using the relevant equations
provided in each applicable subpart
along with the available data from
company records and the likely
operating scenario for the reporting year
that would lead to worst case GHG
emissions. For example, for the input
parameters needed for the equations,
use the 2010 production goals from the
company’s business plan, company
records, process knowledge, engineering
judgment, and vendor data (e.g., vendor
information could be used to estimate
the carbon content of feedstocks, using
the highest likely carbon content of
those feedstocks.) EPA expects that for
most facilities, emissions calculated in
this manner are likely to be significantly
above or below the 25,000 metric ton
CO2e per year threshold, such that most
potential reporters can determine their
applicability to the rule solely using the
available data.
For those facilities with estimated
emissions that are near the 25,000 tons/
year threshold using available data, the
company will have to make the decision
on whether to install monitoring
equipment to calculate emissions during
the 2010 reporting year for purposes of
determining applicability and/or
reporting emissions. It is in a facility’s
interest to collect the GHG data required
by the rule if they think they will meet
or exceed the applicability criteria in 40
CFR 98.2 by the end of the year. EPA
anticipates that relatively few potential
reporters will face uncertainty in
making this decision.
Given the large number of industrial
and commercial facilities potentially
subject to the rule due to stationary fuel
combustion emissions, EPA has
provided in 40 CFR 98.2 simplified
procedures for calculating emissions
from fuel combustion. These facilities
may first assess applicability based on
the aggregate heat input capacity of all
their fuel combustion units. Per 40 CFR
98.2(a)(3), facilities with an aggregate
maximum rated heat input capacity of
less than 30 mmBtu/hour are
automatically not covered under the
rule, because emissions of CO2e will be
less than 25,000 metric tons of CO2e per
year in all cases. If a facility is not below
the 30 mmBTU/hour cutoff, the next
logical step to determine applicability is
to use any of the four calculation
methods provided in subpart C, as
allowed by 40 CFR 98.2(b). The simplest
of the four methods requires
determination of only one parameter—
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annual fuel use. Most companies
already record fuel use, and can use this
to calculate emissions and determine
applicability.
To assist facilities in determining
applicability, EPA plans to provide
implementation guidance with
simplified means to determine
applicability. For combustion sources,
EPA plans to publish tables that will
specify by fuel type both an annual fuel
consumption level and maximum heat
input capacity that correlates with
emissions of 25,000 metric tons per year
of CO2e. For non-combustion source
categories with a 25,000 metric ton CO2e
threshold, EPA plans to publish
guidance, as feasible, on equipment
capacities, production levels, or other
parameters that correlate with emissions
of 25,000 metric tons per year of CO2e.
The capacity and production levels
provided in these tables would be based
on worst-case assumptions, but would
allow facilities to quickly and easily
determine if they need to develop more
precise estimates or plan to implement
monitoring in 2010.
Q. Summary of Comments and
Responses on Statutory Authority
This section contains a brief summary
of some major comments and responses.
A large number of comments on
statutory authority were received
covering numerous topics. This section
will highlight only two of the key
categories of comments. Additional
discussion on these comments and
others can be found in the comment
response documents.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues’’.
Comment: EPA received numerous
comments on whether the CAA or the
FY 2008 Consolidated Appropriations
Act authorized the rule. Some
commenters argued that EPA was
required to issue the reporting rule
under the authority created by the
Appropriations Act, not the CAA.
Others argued that the Appropriation
Act could not create new authority, and
therefore either (1) EPA had to rely on
the CAA, or (2) EPA was not authorized
to issue the rule at all.
Response: As noted above, EPA is
relying on the authority provided in the
CAA, not the Appropriations Act, for
this final rule. While the Appropriations
Act required that EPA spend a certain
amount of money on a rule requiring
mandatory reporting of GHG emissions,
the authority to gather such information
already existed in the CAA. Indeed, EPA
could have promulgated this rule in the
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absence of the Appropriations Act.
Thus, the comments about the inability
of an appropriations law to create new
legal authority are inapposite to this
rulemaking.
Comment: Commenters opined on
whether the statute in question (either
the Appropriations Act or the CAA)
contained sufficient authority for
various elements of the rule, ranging
from broad issues like the scope and
duration of the rule as a whole, to more
specific issues related to particular
source categories covered, and specific
monitoring, recordkeeping and
reporting requirements.
Several commenters argued that the
appropriations language contained
limitations on the scope of the rule EPA
could promulgate, regardless of the
underlying authority for the rule. For
example, some commenters contended
that because the appropriations were for
a single fiscal year, EPA was authorized
to promulgate only a one-time data
collection. Others argued that the
Appropriations Act authorized the
collection solely of GHG emissions, and
not any of the additional data elements
related to verification of emissions data.
As for the CAA, some commenters
questioned whether section 114
authorized a broad reporting rule, as
opposed to the targeted 114 information
requests used by EPA in the past. Many
commenters questioned whether EPA
had adequately linked the requirements
of the reporting rule to particular
provisions of the CAA that EPA was
carrying out. Others questioned EPA’s
general ability to gather information
about GHGs before it had made an
endangerment finding and/or regulated
GHGs under the CAA.
Not all comments were negative.
Some commenters supported EPA’s
interpretation of the CAA, and agreed
that it authorized the proposed
reporting rule.
Response: We disagree that the
language in the Appropriations Act
limited EPA’s authority for this rule.
First, the Environmental Programs and
Management (EP&M) funds Congress
appropriated for the GHG reporting rule
are available for two fiscal years as are
the funds EPA historically has used for
most other Agency rules. The fact that
the appropriations EPA uses to develop
rules are available for specified fiscal
years does not mean that the
effectiveness of the rules is limited by
the same period of time that the funds
are available. Moreover, as noted above,
EPA is issuing this rule under the
authority of the CAA, and indeed EPA
could have issued this rule absent the
direct instruction from Congress to
spend at least a certain amount of
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money on a mandatory GHG reporting
rule. Thus, we do not agree that the
appropriations language limited EPA’s
ability to collect the information under
this rule, either in duration or scope of
the information requested.
Regarding the scope of the rule, while
it is true that EPA has used section 114
in a more targeted fashion in the past,
there is nothing in the CAA that so
limits our ability. EPA is undertaking a
comprehensive evaluation of GHGs
under the CAA and hence, is issuing a
comprehensive reporting rule.
Moreover, as noted above, CAA
sections 114 and 208 authorize EPA to
gather the information under this rule,
which will prove useful to EPA in
carrying out numerous provisions of the
CAA. This final rule imposes
requirements on direct sources of GHG
emissions. These sources are clearly
persons from whom the Administrator
may gather information under CAA
section 114, as long as that information
is for purposes of carrying out any
provision of the CAA. As discussed
further in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Selection of Source
Categories to Report and Level of
Reporting’’ and ‘‘Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to
Public Comments, Legal Issues,’’ the
information provided by direct emitters
will prove invaluable to the Agency in
several areas, including the evaluation
of the appropriate action to take under
section 111 regarding NSPS, and the
investigation into non-regulatory
strategies to encourage pollution
prevention pursuant to section 103(g).
For example, the Agency currently has
pending before it a court remand,
comments in an ongoing rulemaking, a
petition for reconsideration, notices of
intent to sue and litigation regarding
EPA’s treatment of GHGs under section
111.
The requirements applicable to
manufacturers of mobile sources are
authorized by section 208 because they
will help inform various options
regarding the regulation of these sources
under title II of the CAA. The Agency
currently has pending before it several
petitions requesting that the Agency
regulate emissions from a variety of
mobile sources, including motor
vehicles, aircraft, nonroad engines and
marine engines.
Finally, the final rule also gathers
information from upstream suppliers of
industrial GHGs and fossil fuels (except
for suppliers of coal). The information
gathered from suppliers of fossil fuels,
in particular petroleum products, is
relevant to an evaluation of possible
regulation of fuels under title II of the
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CAA, as well as for potential efforts to
address GHG emissions at downstream
sources. Information from suppliers of
industrial GHGs is relevant to
understanding the quantities and types
of gases being supplied to the economy,
in particular those that could be emitted
downstream which will aid in
evaluating action under CAA section
111 as well as various sections of title
VI (e.g., 609 and 612) that address
substitutes to ozone depleting
substances (ODS). Additional
discussion on this issue is available in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Selection of Source
Categories to Report and Level of
Reporting’’ and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’
Finally, we disagree with commenters
who argue that we cannot use CAA
sections 114 of 208 to gather
information on a pollutant until we
have issued an endangerment finding
for that pollutant, or actually decided to
regulate it under the CAA. The statute
is not so inflexible. 20 For example, the
information collected under sections
114 and 208 could inform the
contribution element of endangerment
determinations (e.g., whether emissions
from the relevant sector contribute to air
pollution which may reasonably be
anticipated to endanger public health or
welfare). Similarly, information
gathered under these sections could
inform decisions on whether to regulate
a pollutant or source category.
Commenters’ interpretation would
prevent EPA from gathering information
that could be critical to key decisions
until after those decisions are made.
EPA does not agree with, and will not
adopt, such an interpretation.
Thus, as discussed in more detail
above and in ‘‘Mandatory Greenhouse
Gas Reporting Rule: EPA’s Response to
Public Comments, Legal Issues,’’ EPA
has adequate authority to issue this rule.
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R. Summary of Comments and
Responses on CBI
This section contains a brief summary
of major comments and responses on
CBI issues. A large number of comments
were received covering numerous
topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Legal Issues.’’
20 We note that the statute is ambiguous, and thus
EPA may adopt any reasonable interpretation. See
Chevron v. NRDC et al., 467 U.S. 837, 864 (1984).
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Comment: EPA received numerous
comments addressing the issue of CBI.
Industry commenters generally
expressed concern that much of the
information reported under this rule
would be CBI (e.g., production and
process data). Many commenters also
presented arguments regarding why
certain information would not be
‘‘emissions data’’ under the CAA.
Among the various recommendations
were that the final rule (i) not require
the reporting of such information at all,
(ii) require only that the source maintain
such information on site, but not report
it to EPA, and/or (iii) clearly state that
some classes of information are CBI.
Some commenters expressed concern
about EPA’s ability to maintain the
confidentiality of CBI, and thus
suggested that EPA should provide
further detail regarding how we will
protect CBI from disclosure. The
agricultural industry expressed
particular concerns about making
information about the location of
facilities public due to concerns about
biosecurity and other potential threats.
Other commenters favored the wide
dissemination of information, and
argued that the information gathered
under this rule should be ‘‘emissions
data’’ and hence not protected as CBI.
Response: As discussed in Section
II.N of this preamble, EPA is finalizing
its proposal that EPA verify the
information collected by this rule. Data
regarding inputs into emissions
calculations and monitoring are critical
elements of that verification process.
Because EPA will routinely need this
data in order to verify the information
collected under this rule, we are not
adopting the recommendation that
sources maintain such information on
site and only provide it during an
inspection or when otherwise
specifically requested.
EPA also recognizes the importance of
this issue to both reporters and the
public. EPA’s public information
regulations contain a definition of
‘‘emissions data’’ at 40 CFR 2.301, and
EPA has discussed in an earlier Federal
Register notice what data elements
constitute emissions data that cannot be
withheld as CBI (56 FR 7042–7043,
February 21, 1991). We further
recognize that while determinations
about whether information claimed as
CBI meets the definition of CBI, as well
as whether it meets the definition of
emissions data, are usually made on a
case-by-case basis, such an approach
would be cumbersome given the scope
of this rule and the potential
inconsistencies across reporters and
source categories and the compelling
need to make data that are not CBI, or
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are emissions data, available to the
public. For this reasons, EPA intends to
undertake an effort similar to what was
done in 1991 for the data elements
collected in this rule. Through a notice
and comment process, we will establish
those data elements that are ‘‘emissions
data’’ and therefore will not be afforded
the protections of CBI. As part of that
exercise, in response to requests
provided in comments, we may identify
classes of information that are not
emissions data, and are CBI. EPA plans
to initiate this effort later this year, or
in early 2010. We will consider the
comments received on this issue as part
of that notice and comment process.
As stated in the proposed rule, EPA
will protect any information claimed as
CBI in accordance with regulations in
40 CFR part 2, subpart B. As we noted
previously however, in general the CAA
prohibits the treatment of emission data
collected under CAA sections 114 and
208 as CBI.
S. Summary of Comments and
Responses on Other Legal Issues
This section contains a brief summary
of major comments and responses on
other legal issues. A large number of
other legal issue comments were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’
Comment: We received numerous
comments on EPA’s statements in the
proposed rule that a final rule requiring
the monitoring and reporting of GHG
emissions would not render GHGs
‘‘regulated pollutants’’ under the CAA.
See, e.g., ‘‘EPA’s Interpretation of
Regulations that Determine Pollutants
Covered By Federal Prevention of
Significant Deterioration (PSD) Permit
Program’’ (Dec. 18, 2008) (‘‘PSD
Interpretive Memo). Some agreed, while
others took issue with the position in
the memorandum.
Response: As we noted in the
proposal, EPA is reconsidering the PSD
Interpretive Memo and will be seeking
public comment on the issues raised in
it. That proceeding, not this rulemaking,
is the appropriate venue for submitting
comments on the substantive issue of
whether monitoring regulations under
the CAA should make GHGs subject to
regulation. At this time however, the
PSD Interpretive Memo reflects EPA’s
current position, and hence, this final
rule does not make GHGs subject to
regulation under the CAA.
Comment: EPA also received
numerous comments about whether the
requirements imposed by this rule are
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‘‘applicable requirements’’ under the
title V operating permit program. The
majority of the comments took the
position that the current definitions of
‘‘applicable requirement’’ at 40 CFR
70.2 and 71.2 do not include a rule such
as this, promulgated under CAA section
114(a)(1) and 208. Commenters
requested that EPA confirm their
interpretation of the regulations.
Response: As currently written, the
definition of ‘‘applicable requirement’’
in 40 CFR 70.2 and 71.2 does not
include a monitoring rule such as
today’s action, which is promulgated
under CAA sections 114(a)(1) and 208.
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III. Reporting and Recordkeeping
Requirements for Specific Source
Categories
A. Overview
Once a reporter has determined that
its facility or supply operation meets
any of the reporting rule applicability
criteria in 40 CFR 98.2(a), the reporter
must calculate and report GHG
emissions or alternate information as
required (e.g., suppliers report
quantities supplied and the quantity of
CO2e that could be emitted when the
products they supply are combusted or
used). The applicability threshold
determination is separately assessed for
suppliers (fossil fuel suppliers and
industrial GHG suppliers) and
downstream source categories (facilities
with direct GHG emissions).
The required GHG information must
be reported for all source categories at
the facility for which there are
measurement methods provided. For
suppliers (facilities or corporations) that
trigger only the applicability criteria for
upstream fossil fuel or industrial GHG
supply (40 CFR part 98, subparts KK
through PP), reporters need only follow
the methods and report the information
specified in those respective subparts.
For downstream facilities that contain
exclusively direct emitting source
categories covered in 40 CFR part 98,
subparts C through JJ, and are not
suppliers, reporters must monitor and
report GHG emissions the methods
presented in each applicable subpart.
Some reporters will need to report
under multiple subparts because
multiple source categories are
collocated at their facility. For example,
a facility with petrochemical production
processes (described in Section III.X of
the preamble), should also review
Sections III.C (general stationary fuel
combustion), III.G (ammonia
manufacturing) and III.Y (petroleum
refineries) of this preamble. In some
cases, such as petroleum refineries that
supply petroleum products and also
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meet applicability criteria for direct
emissions from the refinery, reporters
will have to report on both supply
operations and direct facility emissions.
Table 2 of this preamble (in the
SUPPLEMENTARY INFORMATION section of
this preamble) provides a cross walk to
aid facilities and suppliers in
identifying potentially relevant source
categories. The cross-walk 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 III
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 will be relevant to all
reporters.
Consistent with the requirements in
the 40 CFR part 98, subpart A, reporters
must report GHG emissions from all
source categories located at their facility
including stationary combustion 40 CFR
part 98, subpart C) and process
emissions (e.g., from adipic acid
production, iron and steel production,
and other source categories in 40 CFR
subparts C through JJ), as well as the
required data for any supplier source
categories (KK through PP). The
methods presented typically account for
normal operating conditions, as well as
startup, shutdown, or malfunction
(SSM), where significant (e.g., HCFC–22
production and oil and gas systems).
Although SSM is not specifically
addressed for many source categories,
emissions calculation methodologies
relying on CEMS or mass balance
approaches would capture these
different operating conditions.
For many facilities, calculating
facility-wide emissions will simply
involve adding GHG emissions from
combustion sources calculated under
Section III.C of this preamble (General
Stationary Fuel Combustion Sources)
and process GHG emissions calculated
under the applicable the source category
subpart(s). The rule also clarifies
reporting for more complex situations,
such as where combustion and process
emissions are comingled. See Section
II.L of this preamble for a response to
comments on the general monitoring
and reporting approach for facilities
with both combustion and process
emissions. See sections III.C through PP
of this preamble for discussion of the
specific monitoring and reporting
requirements for each source category.
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B. Electricity Purchases
1. Summary of the Final Rule
The final rule does not require
facilities to report their electricity
purchases or indirect emissions from
electricity consumption.
2. Summary of Major Changes Since
Proposal
There have been no changes since
proposal. The proposed rule did not
require reporting of electricity
purchases and neither does the final
rule.
3. Summary of Comments and
Responses
The proposal preamble (74 FR 16479,
April 10, 2009) requested comments on
the value of collecting information on
electricity purchases under this rule. It
also outlined three options for reporting
and requested comments on these
options:
• Option 1: Do not require any
reporting on electricity purchases or
associated indirect emissions from
purchased electricity as part of this rule.
• Option 2: Require reporting of
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 emission
threshold (including indirect emissions
from the purchased electricity).
Reporting under this option could be
either in terms of electricity purchases
or calculated CO2e emission based on
purchased electricity.
While EPA is not including reporting
requirements for electricity purchases in
the final rule at this time, below we
have provided a brief summary of major
comments and our initial responses. As
EPA considers next steps, we will be
reviewing the public comments and
other relevant information.
In Favor of Collecting Data on
Electricity Purchases
Comment: Commenters in favor of
collecting data on purchased electricity
stated that collection of this data, in
conjunction with data on direct
emissions from facilities, will present a
more comprehensive picture of
emissions nationwide. They argued that
collection of this data will also serve to
spur investment in energy efficiency
and renewable energy since companies
will want to improve their emissions
numbers once the information is made
public. Several commenters noted that
while this reporting should occur, it
should happen at the corporate level,
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rather than at the facility level. Others
stated that the collection should begin at
a later time, perhaps in a second phase
of this rule.
Response: While EPA is not collecting
data on electricity purchases in this
rule, we understand that acquiring such
data may be important in the future.
Therefore, we are exploring options for
possible future data collection on
electricity purchases and indirect
emissions, and the uses of such data.
Such a future data collection on indirect
emissions would complement EPA’s
interest in spurring investment in
energy efficiency and renewable energy.
Energy efficiency is a low cost, vital first
step toward reducing GHG emissions.
To this end, EPA has in place several
programs in which corporations and
individual facilities can participate to
reduce their contribution to GHG
emissions through increased energy
efficiency of buildings and industry.
These include EPA’s ENERGY STAR
and Climate Leaders programs.
EPA has been working for more than
a decade through the ENERGY STAR
program to help companies reduce their
energy use through cost-effective energy
efficiency investments and practices.
ENERGY STAR provides nonresidential
building owners and operators and
energy intensive industries with a wide
variety of tools and resources to assist
in their efforts to reduce building energy
use. These include an online energy
benchmarking and tracking tool called
Portfolio Manager, Guidelines for
Energy Management, technical
resources to assist in assessing building
upgrades, and many others.
Through the Climate Leaders
Program, EPA works corporate-wide
with companies to develop
comprehensive climate change
strategies. Partner companies commit to
reducing their impact on the global
environment by completing a corporatewide inventory of their GHG emissions
based on a quality management system,
setting aggressive reduction goals to be
achieved over 5 to 10 years, and
annually reporting their progress to
EPA. Through program participation,
companies create a credible record or
audit of their accomplishments and
receive EPA recognition as corporate
environmental leaders.
In addition to these programs that
support GHG emissions reductions in
both the private and public sectors,
EPA’s Climate and Energy State and
Local Program assists governments in
their clean energy efforts by providing
technical assistance, analytical tools,
and outreach support. While EPA assists
States in this way, we also have much
to learn from their efforts. Throughout
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the country, States are engaged in
activities on energy efficiency, energy
auditing, and some collect data on
electricity purchases for use in
inventories and in energy efficiency
programming.
Since the goal of today’s rule is to
collect data on emissions from
downstream direct emitters and
upstream production, the collection of
indirect emissions will not be included
at this time. In exploring the possibility
of collecting data on electricity
purchases nationwide, EPA will be
looking to the States as examples. While
facility level collection is a possibility,
collection from other sources, such as
load serving entities will also be
explored. Moreover, the collection of
indirect emissions data from the types
of facilities covered by this rule (e.g.,
facilities and suppliers with emissions
over 25,000 metric tons of CO2e) would
not provide the complete picture or
focus on the types of facilities that likely
have large indirect emissions. Reports
from additional facilities could be
required in any future data collection.
Against Collecting Data on Electricity
Purchases
Comment: Many commenters were
against the collection of data on
purchased electricity for several
reasons. Primarily they felt it would
constitute double counting if electricity
data are collected from electric utilities
and EPA also collects the same data
from facilities and adds it together.
Others stated that collecting information
on electricity purchases was outside the
scope of the rule, that it is not useful
information in attempting to quantify
emissions, that it would be burdensome
for facilities, and that it is CBI that
companies are not able to share with
EPA. Those commenters suggested
instead the data should come from
utilities, as EPA proposed.
Response: The final rule does not
require facilities to report their
electricity purchases or indirect
emissions from electricity consumption.
While EPA is not collecting data on
electricity purchases in this rule, we
understand that acquiring such data
may be important in the future.
Therefore, we are exploring options for
possible future data collection on
electricity purchases and indirect
emissions, and the uses of such data. In
the event that a future data collection
effort is pursued, EPA will consider the
issues raised by these commenters with
regard to the most effective source for
this data, and methods to reduce burden
on reporting entities.
With regard to, double reporting and/
or double counting of the same data, the
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data collected under this rule is
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. Eliminating
reporting by either upstream or
downstream sources would not satisfy
EPA’s data needs and policy objectives
of this rule. Any future rule makings to
collect data on electricity purchases and
indirect emissions will follow a similar
approach in order to inform policy
decisions.
With regard to CBI, EPA recognizes
the importance of this issue to both
reporters and the public. EPA’s public
information regulations contain a
definition of ‘‘emissions data’’ at 40 CFR
2.301, and EPA has discussed in an
earlier Federal Register notice what
data elements constitute emissions data
that cannot be considered CBI (56 FR
7042–7043, February 21, 1991).
As explained in Section II.R. of this
preamble, EPA intends to undertake a
similar effort regarding the data
elements collected in this rule, and any
subsequent rules. Through a notice and
comment process, we will establish
those data elements that are ‘‘emissions
data’’ and therefore will not be afforded
the protections of CBI.
C. General Stationary Fuel Combustion
Sources
1. Summary of the Final Rule
Source Category Definition. Stationary
fuel combustion sources are devices that
combust any solid, liquid, or gaseous
fuel to:
• Produce electricity, steam, useful
heat, or energy for industrial,
commercial, or institutional use; or
• Reduce the volume of waste by
removing combustible matter.
These devices include, but are not
limited to, boilers, combustion turbines,
engines, incinerators, and process
heaters.
Portable equipment, emergency
generators, and emergency equipment
are excluded from this source category.
Stationary combustion devices that
combust hazardous waste must report
emissions only from the co-firing of any
fuels that are covered by 40 CFR part 98,
subpart C. Flares are also excluded from
subpart 40 CFR part 98, subpart C. Flare
emissions must be reported only if
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required by the provisions of another
subpart of part 98.
Reporters must submit annual GHG
reports for stationary fuel combustion
units if the facility meets the
applicability criteria in the General
Provisions (40 CFR 98.2) as summarized
in Section II.A of this preamble.
EGUs that are subject to the ARP and
other EGUs that are required to monitor
and report to EPA CO2 mass emissions
year-round according to 40 CFR part 75,
are covered under 40 CFR part 98,
subpart D (Electricity Generation).
GHGs to Report. For stationary fuel
combustion, report:
• CO2, CH4, and N2O emissions from
each stationary fuel combustion unit.
For each unit, CO2, CH4, and N2O
emissions must be reported for each fuel
combusted (including biomass).
Reporters can aggregate emissions from
multiple units in certain cases.
• Facility-level CO2 emissions from
combustion of biomass (in addition to
unit-level reporting).
GHG Emissions Calculation and
Monitoring. Reporters must use the
following methodologies to calculate
emissions:
• Calculating CO2 Emissions from
Combustion: Calculate CO2 emissions
using one of four methodological tiers,
subject to certain restrictions based on
unit size, type of fuel burned, and other
factors. For each Tier, CO2 mass
emissions are determined as follows:
—Tier 1: Use annual fuel consumption
(from company records) together with
fuel-specific default high heat values
and default CO2 emission factors.
—Tier 2: Use annual fuel consumption
(from company records) together with
measured fuel-specific high heat
values and default CO2 emission
factors.
—Tier 3: Use annual fuel consumption,
either from company records (for
solid fuels) or directly measured with
fuel flow meters (for liquid and
gaseous fuels) together with periodic
measurements of fuel carbon content.
—Tier 4: Use CEMS. Use Tier 4 only for
combustion units that have certain
types of existing CEMS in place and
that meet several other specific
criteria, such as fuel type and hours
of operation. Sources that have all of
the necessary CEMS installed and
certified by January 1, 2010 are
required to use Tier 4 in 2010.
However, for sources that need
additional time to upgrade their
CEMS, the use of CEMS can begin on
January 1, 2011; and a lower tier
calculation methodology may be used
in 2010.
—As an alternative to any of the four
tier methods, the rule provides that
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units that report to EPA year-round
heat input data under 40 CRF part 75
can calculate CO2 mass emissions
using part 75 calculation methods.
• Calculating CO2 Emissions From
Sorbent Use. For fluidized bed boilers
that use sorbent injection and units
equipped with wet flue gas
desulfurization systems, calculate CO2
emissions from sorbent use using
methods provided in the rule, except
when CO2 emissions are measured with
CEMS.
• Calculating CO2 Emissions From
Biomass Fuel Combustion. Calculate
CO2 emissions from biomass
combustion for only the specific types
of biomass that are listed in the rule.
The approach used for most units is to
use a default high heat value and default
CO2 emission factor to estimate
emissions. For determining the biomass
fraction of CO2 emissions from units
that burn MSW or mixed fuels, and from
units that co-fire biomass with fossil
fuels and measure CO2 emissions using
CEMS, use the specific methods
provided in the rule.
• Calculating N2O and CH4 Emissions
From Combustion. Calculate N2O and
CH4 emissions only for units that are
required to report CO2 emissions under
this subpart and only for fuels for which
default emission factors are provided in
40 CFR part 98, subpart C.
• Fuel Sampling and Analysis. The
Tier 2 and Tier 3 calculation
methodologies require periodic
measurements of fuel heating value and
carbon content. The minimum required
frequency of these measurements is
daily, weekly, monthly, quarterly, or
semiannually, depending on the type of
fuel combusted and other factors.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are needed for EPA
verification of the reported GHG
emissions from stationary combustion.
The specific data to be reported are
found in 40 CFR part 98, subpart C.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. These records are described
in 40 CFR part 98, subpart C.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
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or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart C: General
Stationary Fuel Combustion Sources.’’
• Exemptions to GHG emissions
reporting have been added for
unconventional types of fuel. Reporters
are required to calculate GHG emissions
only for fuels that are listed in Table C–
1 of subpart C, except that units larger
than 250 mmBtu/hr, also must calculate
GHG emissions for any other fuels that
provide, on average, at least 10 percent
of the annual heat input to the unit.
• The use of the Tier 2 calculation
method for CO2 emissions has been
expanded to include units greater than
250 mmBtu/hr that combust only
pipeline natural gas and/or distillate oil.
• Two new alternative methods have
been added, allowing sources that
monitor and report heat input according
to 40 CFR part 75, but are not required
to report CO2 mass emissions, to use
established Part 75 CO2 emissions
calculation methods to meet the 40 CFR
part 98 reporting requirements.
• A definition of ‘‘company records’’,
as it pertains to quantifying fuel
consumption in Tiers 1, 2, and 3, has
been added to 40 CFR 98.6.
• The required fuel sampling
frequency in Tiers 2 and 3 has been
reduced for many fuels, particularly
those that are homogeneous or that are
delivered in shipments or lots.
• Averaging of fuel sampling results
is allowed for many fuels when the
frequency of sampling and analysis is
less than the minimum monthly
frequency.
• The rule has been clarified to affirm
that the use of fuel sampling results
provided by the fuel supplier is
permissible, and that the use of fuel
billing records to quantify fuel
consumption is also allowed.
• Additional deadline extensions for
calibrating the fuel flow meters are
provided in certain situations.
• The use of Tier 4 has been clarified;
i.e., all of the conditions listed in 40
CFR 98.33(b)(4)(ii) and all of the
conditions listed in 40 CFR
98.33(b)(4)(iii) must be met before Tier
4 is required.
• Units that must upgrade their
existing CEMS to meet Tier 4
requirements may use either Tier 2 or
Tier 3 in 2010.
• The methods for calculating CH4
and N2O emissions have been clarified.
• An expanded list of default
emission factors are provided for certain
solid, gaseous, and liquid biomass fuels.
• The use of steam production and
combustion unit efficiency to calculate
CO2 emissions is extended to other solid
fuels in addition to MSW. These
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parameters may also be used to quantify
the amount of biomass combusted in a
unit.
• The use of American Society for
Testing and Materials (ASTM) Methods
D7459–08 and D6866–06a to determine
CO2 emissions from combustion of
mixed biomass fuels has been expanded
to include the combustion of other
biomass fuels in addition to those mixed
with MSW.
• The missing data provisions have
been made more flexible.
• The limit of 250 mmBtu/hr total
heat input for aggregating units into
groups for reporting purposes has been
lifted.
• The reporting of combined units
served by a common supply line, or
common pipe configuration, has been
clarified.
• The amount of required unit-level
data and emissions verification
information has been reduced for some
of the measurement Tiers.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Many comments on general stationary
fuel combustion were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart C: General
Stationary Fuel Combustion Sources.’’
Definition of Source Category
Comment: Several commenters asked
EPA to clarify whether sources such as
flares, hazardous waste incinerators,
thermal oxidizers, pollution control
devices, fume incinerators, burnout
furnaces, and small equipment such as
stoves and space heaters are included in
the stationary combustion source
category. Others suggested that EPA
should consider requiring that only the
GHG emissions from combustion of
traditional fossil fuels (if any) in these
types of sources be reported.
Comments were also received on the
proposed language for excluding
emergency generators and the associated
definitions.
Response: The final rule retains the
broad definition of a stationary fuel
combustion source, which is any device
that combusts fuel. Fuel is defined very
broadly to mean any combustible
material. However, in evaluating public
comments, we agree that in some cases
the reporting of GHG emissions is
unreasonable given the cost of
monitoring and the relative level of
GHG emissions. Monitoring can be
particularly burdensome for vents with
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highly variable gas characteristics (e.g.,
carbon content and heat value).
Accordingly, the final rule expands the
list of combustion sources and fuels that
are exempted from GHG emissions
reporting under 40 CFR part 98, subpart
C, as summarized below:
• Flares are exempted from 40 CFR
part 98, subpart C. However, flares at
some facilities might be covered by
other subparts of the rule.
• Stationary combustion units that
combust hazardous waste, as defined in
40 CFR 261.3, are also exempted. These
units would report only the emissions
from combustion of any fuels covered
by subpart C that are co-fired with
hazardous wastes.
• For calculations at the unit level,
units less than 250 mmBtu/hour heat
input are required to report GHG
emissions only for fuels for which EPA
has provided default emission factors in
the rule.
• Units larger than 250 mmBtu/hour
heat input GHG that combust
miscellaneous, non-traditional fuels
such as refinery gas, process gas, vent
gases, waste liquids, and others must
report only if CEMS are used or if these
fuels contribute 10 percent or more of
the annual unit heat input to the unit.
With this exclusion, we have concluded
that devices such as thermal oxidizers,
pollution control devices, fume
incinerators, burnout furnaces, and
other such equipment would report only
GHG emissions from the firing of
supplemental fossil fuels.
In response to comments on the
exclusion of emergency generators, EPA
removed proposed language that would
have required emergency generators to
be identified as such in the facility’s
State or local air permit in order to
qualify for an exemption. We also added
language to exclude other emergency
equipment. See Section III.D of this
preamble for the response to the
comments on exclusion of emergency
generators from 40 CFR part 98,
subparts C and D. See ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
A: Definitions, Incorporation by
Reference, and Other Subpart A
Comments’’ for responses to comments
on definitions, including changes to the
emergency generator definition and the
addition of a definition for emergency
equipment.
Comment: Multiple commenters
asked EPA to institute a ‘‘de minimis’’
provision in the rule to exclude
stationary combustion sources other
than the largest units at a facility.
Response: The final rule contains no
de minimis exclusions. However, to
simplify reporting, the rule allows small
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56291
units to be aggregated and reported as a
single emissions value, if certain
conditions apply. The final rule has
expanded the availability of this
provision. The proposed rule limited
the aggregation of any one group to a
combined maximum capacity of 250
mmBtu/hour heat input. The final rule
removes this limit and allows grouping
of any units that individually are less
than 250 mmBtu/hour heat input. EPA
has also clarified the use of the common
pipe metering option, so that all
stationary combustion units at a facility
using the same fuel that is metered
through a common supply line may
report a single emissions value under
this rule. In addition, the changes listed
above in Section III.C.2 of this preamble
will simplify emissions calculations for
many combustion units.
Method for Calculating GHG Emissions
Comment: EPA received numerous
comments on the proposed GHG
calculation methods for stationary
combustion sources. Most of the
comments centered on the use of the
four-tiered approach for calculating CO2
emissions. Several commenters
requested that EPA remove the 250
mmBtu/hr unit size restriction on the
use of Tier 1 and 2 calculation methods,
especially for the combustion of
relatively homogeneous fuels such as
natural gas and fuel oil. Objections were
raised to the specified frequency of fuel
sampling under Tiers 2 and 3, as being
excessive and unnecessary. Two
commenters recommended that annual
sampling be allowed for natural gas and
fuel oil. A number of commenters asked
the Agency to allow averaging of fuel
sampling results (to simplify the CO2
emissions calculations) and to affirm
that the use of fuel sampling results
provided by the fuel supplier is
permissible. Others sought confirmation
that fuel billing meters could be used to
quantify fuel usage. Multiple
commenters asked EPA to clarify who
must use the Tier 4 calculation method,
which requires the use of continuous
emission monitoring systems (CEMS) to
measure stack gas flow rate and CO2
concentration. A number of comments
were received requesting that sources
currently monitoring and reporting heat
input data under 40 CFR Part 75, but not
reporting CO2 mass emissions, be
allowed to implement established Part
75 CO2 emissions calculation methods
in lieu of using Tiers 1 through 4.
Finally, EPA received diverse comments
on the proposed calculation method for
CH4 and N2O emissions. Several
commenters recommended that these
emissions either not be reported at all,
or that emissions reporting should be
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excluded for certain fuel types. Others
asked for flexibility in determining the
appropriate emission factors for CH4
and N2O. Some suggested that the use
of operator-defined emission factors or
factors from other GHG registries should
be allowed.
Response: The final rule significantly
expands the use of Tier 1 and Tier 2
calculation methodologies. All units
rated at 250 mmBtu/hr or less are
allowed to use the Tier 1 or Tier 2
calculation methodologies, depending
on fuel sampling provisions at either the
facility or by the supplier of the fuel. In
addition, units rated at over 250
mmBtu/hr that combust pipeline quality
natural gas and distillate oil are allowed
to use the Tier 2 calculation
methodology, because of the
homogeneous nature and low variability
in the characteristics of these fuels.
However, the 250 mmBtu/hr unit size
cutoff remains for units that combust
residual oil, other gaseous fuels, and
solid fossil fuel.
The mandatory monthly fuel
sampling and analysis requirements for
traditional fossil fuels have been
dropped from Tiers 2 and 3. EPA agrees
with the commenters that for a
homogeneous fuel such as pipeline
natural gas, monthly sampling is not
necessary. Therefore, 40 CFR 98.34 has
been revised to require that natural gas
be sampled semiannually. For other
fuels such as oil and coal, which are
delivered in shipments or lots, requiring
monthly sampling may be impractical,
because new fuel lots or deliveries may
not be received on a monthly basis. For
fuel oil and coal, a representative
sample is required for each fuel lot, i.e.,
for each shipment or delivery. For other
liquid fuels and biogas, quarterly
sampling is required. For solid fuels
other than coal, excluding MSW, weekly
composite sampling with monthly
analysis is required. For gaseous fuels
other than natural gas and biogas, the
daily sampling requirement has been
retained, but only for facilities with
existing equipment in place that is
capable of providing the data.
Otherwise, weekly sampling is required
if such equipment for daily sampling is
not installed.
The final rule clarifies that fuel
sampling and analysis data provided by
the supplier may be used in the
emission calculations, and that fuel
billing meters may be used to quantify
fuel consumption. To simplify the
emission calculations in Tiers 2 and 3,
arithmetic averaging of higher heating
value and carbon content data over the
reporting year is permitted if these data
are collected less frequently than
monthly (see Equation C–2b in 40 CFR
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98.33). However, regardless of the
sampling frequency required by the
rule, reporters must use the results of all
available valid fuel analyses in the
emissions calculations.
Today’s rule clarifies the applicability
of the Tier 4 methodology. Many
commenters were unsure whether only
one or all six of the conditions listed in
proposed 40 CFR 98.33(b)(4)(ii) and all
three of the conditions listed in
proposed 40 CFR 98.33(b)(4)(iii) must be
met to trigger the requirement to use
CEMS. EPA’s intent has always been
that a source must meet all conditions
listed in those sections to require the
use of Tier 4. This has been made clear
in the final rule text.
The final rule adds two methods that
can be used as alternatives to any of the
four tier calculation methods. These
alternative methods apply to sources
that are currently required to monitor
and report heat input data according to
40 CFR part 75, but are not required to
report CO2 mass emissions. Many units
subject to the Clean Air Interstate
Regulation (CAIR) are in this category.
These alternative methods allow these
sources to use their 40 CFR part 75 heat
input data together with one of the CO2
emissions calculation methodologies in
part 75 to meet 40 CFR part 98 CO2
emissions reporting requirements. For
instance, sources monitoring hourly
heat input according to Appendix D of
40 CFR part 75 may use Equation G–4
in Appendix G of 40 CFR part 75 to
calculate CO2 emissions. Similarly, low
mass emitting sources monitoring heat
input under 40 CFR 75.19 may use
Equation LM–11 in 40 CFR 75.19 to
calculate CO2 emissions. Sources using
40 CFR part 75 flow rate and CO2 CEMS
to continuously monitor heat input may
use the CEMS measurements together
with an appropriate equation from
Appendix F of 40 CFR part 75 to
determine CO2 mass emissions.
The methodology for calculating CH4
and N2O emissions has been clarified in
the final rule. Reporting of these
emissions is required only for the fuels
listed in Table C–2 of 40 CFR part 98,
subpart C. Further, reporting of CH4 and
N2O emissions is required only for units
that are required to report CO2
emissions under 40 CFR part 98, subpart
C and only for fuels for which default
emission factors are provided in subpart
C. The emission factors in Table C–2 of
40 CFR part 98, subpart C are both fuelspecific and heat input-based.
Therefore, when more than one type of
fuel is combusted in a unit, direct
measurements or engineering estimates
of the annual heat input from each fuel
are needed to calculate the CH4 and N2O
emissions. Consequently, when CEMS
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(which are not fuel-specific) are used to
monitor the CO2 emissions and heat
input for a multi-fuel unit, the total heat
input measured by the CEMS must be
apportioned to each fuel type. The
owner or operator should use the best
available information (e.g., fuel feed
rates, high heat values) to do the
necessary heat input apportionment. To
provide greater consistency in reporting,
EPA has chosen to retain the
requirements for using the default
factors in Table C–2 of 40 CFR part 98,
subpart C, rather than allow reporters to
select their own emission factors.
Procedures for Estimating Missing Data
Comment: EPA received several
requests to modify the proposed missing
data substitution procedures in 40 CFR
part 98, subpart C. One commenter
recommended that a minimum data
capture requirement should be specified
rather than requiring the use of
substitute data to fill in missing data
gaps. Another commenter suggested that
only the ‘‘before’’ value be used for data
substitution, rather than the average of
the quality-assured values before and
after the missing data period. Others
favored using emission factors or the
‘‘best available estimates’’ for all
parameters, rather than following a
prescriptive missing data algorithm.
Finally, several commenters asserted
that 40 CFO part 75 missing data
procedures for CO2 are too conservative
(i.e., may overestimate emissions
significantly) and seem to be contrary to
the objectives of 40 CFR part 98.
Response: The final rule provides
additional flexibility to the missing data
provisions of 40 CFR part 98, subpart C.
The rule requires the use of ‘‘before and
after’’ average values for only three
parameters (fuel HHV, carbon content,
and molecular weight). If the ‘‘after’’
value is not yet available when the GHG
emissions report is due, the ‘‘before’’
value may be used for missing data
substitution. For all other parameters,
the reporter can substitute data values
that are based on the best available
estimates, based on all available process
information.
EPA does not agree with the
commenters who believe that the 40
CFR part 75 CO2 missing data
procedures are too conservative and
contrary to 40 CFR part 98 program
objectives. Nearly all 40 CFR part 75
sources maintain very high monitor data
availability (95 percent or better) and
use very little substitute data. Only
when the data availability drops below
80 percent (which very seldom occurs)
are the substitute data values
significantly higher than the true CO2
concentrations. Therefore, sources that
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monitor CO2 emissions according to 40
CFR part 75 should continue to use the
standard part 75 missing data
provisions, and no adjustments to those
substitute data values are deemed
necessary for 40 CFR part 98 reporting
purposes.
Data Reporting Requirements
Comment: A number of commenters
objected to the amount of unit-level data
and emissions verification information
that is required to be reported
electronically under 40 CFR 98.36 as
‘‘burdensome’’, ‘‘unnecessary,’’ and
‘‘excessive.’’ The commenters
recommended that the auxiliary
information should instead be kept on
file and made available to EPA upon
request. Several commenters
recommended that EPA remove the 250
mmBtu/hr limit on the cumulative heat
input capacity of units that can be
aggregated into groups for reporting
purposes. Other commenters asserted
that EPA should consider the 40 CFR
part 75 emissions data submitted under
the ARP to be sufficient to satisfy 40
CFR part 98 requirements, and that
there is no need to submit the same data
twice.
Response: EPA does not agree with
the assertion that the amount of unitlevel data to be reported is excessive,
burdensome, or unnecessary. For this
mandatory GHG emissions reporting
rule, two approaches to emissions data
verification were considered, EPA
verification and third-party verification.
The Agency decided on EPA emissions
verification. To verify GHG emissions
estimates, EPA needs supporting data
that are reported at the same level as the
emissions are calculated. Because the
rule requires that emissions be
calculated at the unit level, it is
imperative for EPA to obtain unit level
verification data, particularly given the
variety of requirements for estimating
fuel combustion emissions under 40
CFR part 98, subpart C. Subpart C
provides four different methods of
estimating CO2 emissions. The four
methods require measurement of
different parameters to estimate
emissions, and the use of the methods
is conditioned on a variety of operating
factors. In addition, facilities use fuel
combustion units of a variety of
different sizes, types, and fuel firing
scenarios. Under these circumstances,
EPA could not verify that the correct
methods were selected or applied
correctly without unit-level data. If unitlevel data were not submitted or were
aggregated at a gross level, EPA could
not reasonably verify the accuracy of
reported facility-wide GHG emissions
data, because EPA could not evaluate
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the relationship between unit capacity,
fuel characteristics, fuel consumption,
and emissions. However, as explained
below, in the final rule EPA has made
a number of significant adjustments to
the data reporting requirements to
clarify requirements and to reduce the
reporting burden.
First, for units that use Tiers 1, 2 and
3 to calculate CO2 mass emissions, the
cumulative 250 mmBtu/hr heat input
capacity limit on the aggregation of
units into groups has been dropped.
Rather, the 250 mmBtu/hr restriction
applies only to the individual units in
a group. Therefore, for reporting
purposes, individual units with
maximum rated heat input capacities of
250 mmBtu/hr or less may be aggregated
without limit into a single group,
provided that the Tier 4 methodology is
not required for any of the units, and all
units in the group use the same
calculation methodology for any
common fuels that they combust. Units
with maximum rated heat inputs greater
than 250 mmBtu/hr using Tiers 1, 2, and
3 must report as individual units, unless
they burn the same type of fuel and the
fuel is provided by a common pipe or
supply line. In that case, the owner or
operator may opt to aggregate emission
for all units fed by the common fuel
line. Units using Tier 4 must report as
individual units unless they share a
monitored common stack.
Second, the rule requires minimal
data to be reported for units that
monitor and report emissions and heat
input data according to 40 CFR part 75.
Units that meet these criteria include
units that are subject to the ARP, and
potentially units that are subject to
CAIR, and other programs. The final
rule clarifies that 40 CFR part 75 sources
must report 40 CFR part 98 GHG
emissions data under the exact same
unit, stack, or pipe ID numbers that are
used for electronic reporting in the part
75 programs (e.g., 1, 2, CT5, CS001,
MS1A, CP001, etc.). Even though most
40 CFR part 75 sources report CO2 mass
emissions data to EPA year-round, these
data alone are not sufficient to satisfy
the Part 98 reporting requirements for
the following reasons. The emissions
reports required under 40 CFR part 98
are facility-wide reports that require
GHG emissions from all stationary
combustion units at the facility, whether
or not the units are subject to a 40 CFR
part 75 program. Many electricity
generating facilities have both ARP
units and non-ARP units on site.
Further, the CO2 emissions data
reported under 40 CFR part 75 are in
units of short tons; Part 98 requires
reporting in metric tons. Finally, 40 CFR
part 98 also requires CH4 and N2O
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emissions to be reported, neither of
which are reported under any 40 CFR
part 75 program.
Third, the required verification data
have been clarified and, in some cases,
differ substantively from the proposed
rule. No additional verification
information is required for sources that
monitor and report emissions and heat
input data using 40 CFR part 75. This
includes sources that elect to use the
new alternative calculation
methodologies for units monitoring heat
input year round according to 40 CFR
part 75 programs. For sources using
Tiers 1, 2, 3, and 4, the final rule
streamlines some of the reporting.
Sources using Tier 3 are required to
report only monthly averages of fuel
carbon content and molecular weight
rather than the proposed requirement to
submit the results of each individual
determination. Sources that use Tier 4
are required to report quarterly
cumulative CO2 mass emissions, rather
than daily CO2 emissions, as proposed.
Also, to address concerns raised by
some of the commenters, certain data
elements need only be retained on file
and provided to EPA upon request.
These data elements include the
methods used for fuel sampling and
analysis, the methods used to calibrate
fuel flow meters, the dates and results
of fuel flow meter calibrations, and the
dates and results of CEMS certification
tests and on-going QA tests of the
CEMS.
D. Electricity Generation
1. Summary of the Final Rule
Source Category Definition. This
source category consists of EGUs that
are subject to the ARP and any other
EGUs that are required to monitor and
report to EPA CO2 mass emissions yearround according to 40 CFR part 75. All
other EGUs are part of the general
stationary fuel combustion source
category and report under 40 CFR part
98 subpart C, if the facility meets the
reporting rule applicability criteria. This
source category excludes portable
equipment, emergency generators, and
emergency equipment.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Report annual CO2,
N2O, and CH4 mass emissions from each
EGU.
GHG Emissions Calculation and
Monitoring. For EGUs subject to the
ARP and other EGUs that are required
to monitor and report to EPA CO2 mass
emissions year-round according to 40
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CFR part 75, the reporter must continue
to monitor CO2 emissions according to
40 CFR part 75. The cumulative CO2
mass emissions reported in the fourth
quarter electronic data reports must be
converted from short tons to metric
tons, for 40 CFR part 98 reporting
purposes. The N2O and CH4 emissions
must be calculated using fuel-specific
default emission factors and heat input
measurements in accordance with 40
CFR 98.33(c) in subpart C (General
Stationary Fuel Combustion Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit unitlevel data and other information that are
used to verify the reported GHG
emissions. The additional data and
information to be reported for this
source category are specified in 40 CFR
98.46.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. The specific records that
must be retained for this source category
are identified in 40 CFR 98.47.
2. Summary of Major Changes Since
Proposal
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The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart D: Electricity
Generation.’’
• The source category has been more
precisely defined and includes only
EGUs subject to the ARP and any other
EGUs that are required to monitor and
report to EPA CO2 mass emissions yearround according to 40 CFR part 75.
• The proposed emergency generator
exclusion language no longer requires
that emergency generators be identified
as such in State or local air permits.
• A CO2 calculation methology was
provided for units that are not in the
ARP, but report CO2 mass emissions
year-round using 40 CFR part 75
methodologies.
3. Summary of Comments and
Responses
Definition of Source Category
Comment: Several commenters were
concerned that covering non-ARP EGUs
in both subparts C and D of proposed 40
CFR part 98 was confusing and
repetitive. Several commenters stated
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that the definition of an EGU is too
inclusive and recommended that EPA
revise it. The commenters were
concerned that any unit, regardless of
electrical output, could be identified as
an EGU and place a facility in the
electricity generation source category.
One commenter suggested that a 25
megawatts (MW) threshold should be
added to the EGU definition in 40 CFR
98.6 and to 40 CFR part 98, subpart D.
A multitude of commenters objected to
the language in proposed 40 CFR 98.40
requiring emergency generators to be
designated as such in a State or local air
permit, in order for the generators to be
exempted from GHG emissions
reporting. Many of these same
commenters recommended changes to
the definition of ‘‘emergency generator’’
in 40 CFR 98.6, suggesting that the term
‘‘generator’’ should be replaced with the
term ‘‘reciprocating internal combustion
engine (RICE)’’, to be consistent with 40
CFR 63.6675, subpart ZZZZ. Others
recommended that EPA should also
exempt emergency equipment such as
fire pumps, fans, etc. from GHG
emissions reporting.
Response: The electricity generation
source category definition in subpart D
(40 CFR 98.40) has been modified based
on the comments received. The final
rule limits the source category to EGUs
that are subject to ARP and to other
EGUs that monitor and report to EPA
CO2 mass emissions year-round
according to 40 CFR part 75. The final
subpart D does not cover any other
EGUs. The GHG emissions from other
EGUs are covered under subpart C
(General Stationary Fuel Combustion).
The definition of an ‘‘emergency
generator’’ in 40 CFR 98.6, the final rule
has been changed to clarify that it
includes both RICE and turbines. EPA
has also added a definition of
‘‘emergency equipment’’ to 40 CFR 98.6,
and exempts such equipment from GHG
emissions reporting under both 40 CFR
part 98, subparts C and D.
The proposed requirements in 40 CFR
part 98, subparts C and D for emergency
generators to be identified as such in
State and local air permits in order to be
exempt from GHG emissions reporting
has been revised. There is considerable
variation from State to State regarding
the regulation of emergency generators,
including whether or not permits are
required. Some States specifically
exempt emergency generators from
permitting requirements. Other States
use a permit by rule approach for
emergency units. In view of this, the
Agency has revised the wording of the
exclusion for emergency generators to
allow for situations where they are not
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specifically identified in a facility’s
permit.
Method for Calculating GHG Emissions
Comment: Several commenters
suggested that for units that are not in
the ARP but are required by other
regulatory programs to report part 75
emissions and heat input data, EPA
should expand the four-tiered
calculation method for CO2 mass
emissions in 40 CFR 98.33(a) to allow
the use of CO2 emissions calculation
methods based on Appendices D and G
of part 75.
Response: The electricity generation
source category definition has been
narrowed to only include EGUs that are
subject to ARP and to other EGUs that
monitor and report to EPA CO2 mass
emissions year-round according to 40
CFR part 75 (e.g., RGGI units). The final
subpart D provides a CO2 calculation
methodology for such EGUs that are not
in the ARP, but report to EPA CO2 mass
emissions year-round using part 75
methodologies. For the purposes of part
98, the CO2 emissions from these units
are calculated and reported using the
same methods as part 75.
Other units that are not in the ARP
but report data under part 75, subpart C
are now covered by 40 CFR part 98,
subpart C instead of subpart D, and
subpart C has been revised to allow the
use of part 75 calculation
methodologies. The response to the
comment on these units is contained in
Section III.C of this preamble (General
Stationary Fuel Combustion Sources).
E. Adipic Acid Production
1. Summary of the Final Rule
Source Category Definition. The
adipic acid production source category
consists of all processes that use
oxidation to produce adipic acid.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Report N2O process
emissions from adipic acid production.
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable. For example,
report CO2, N2O, and CH4 emissions
from each stationary combustion unit on
site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
GHG Emissions Calculation and
Monitoring. Unless an alternative
method of determining N2O emissions is
requested, calculate N2O process
emissions from adipic acid production
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by multiplying a facility-specific
emission factor by the annual adipic
acid production level. Determine the
facility-specific emission factor by an
annual performance test to measure N2O
emissions from the waste gas stream of
each oxidation process and the
production rate recorded during the test.
When N2O abatement devices (such as
nonselective catalytic reduction) are
used, adjust the N2O process emissions
for the amount of N2O removed using
the destruction efficiency for the control
device and the fraction of annual
production for which the control device
is operating. The destruction efficiency
can be specified by the abatement
device manufacturer or can be
determined using process knowledge or
another performance test.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart E.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
E.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found in this
section or ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart E: Adipic
Acid Production.’’
• The re-testing trigger was changed.
Performance testing to determine the
N2O emissions factor is required
annually, whenever the ratio of
cyclohexanone to cyclohexanol is
changed, and when new abatement
equipment is installed.
• Equation E–2 was edited to correct
a calculation error and to allow multiple
types of abatement technologies.
• 40 CFR 98.56 was reorganized and
updated to improve the data reporting
requirements as needed for the
emissions verification process. Some
data elements were moved from 40 CFR
98.57 to 40 CFR 98.56, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
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CFR 98.53 were added to 40 CFR 98.56
for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Several comments on adipic acid
production were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart E: Adipic
Acid Production.’’
GHGs To Report
Comment: Multiple commenters
asked that the language in 40 CFR
98.52(b) be clarified to include
emissions under 40 CFR part 98, subpart
E only from units that are 100 percent
dedicated to adipic acid production to
avoid double counting of combustion
emissions.
Response: We reviewed this issue but
decided not to make any changes to 40
CFR part 98, subpart E. We do not
foresee a potential for double counting
of combustion emissions at the facility
because all combustion unit emissions
at adipic acid facilities are to be
reported under 40 CFR part 98, subpart
C. 40 CFR part 98, subpart E provides
methods for reporting only the process
N2O emissions. Also see Section III.C of
this preamble for responses to
comments related to 40 CFR part 98,
subpart C (General Stationary
Combustion).
Selection of Proposed GHG Emissions
Calculations and Monitoring Methods
Comment: One commenter stated that
emissions of N2O do not correlate with
the production of adipic acid at their
facility. A portion of the process off gas,
which contains N2O, is sold to an offsite
facility via dedicated piping. The
amount sold depends on customer
needs and the amount is metered. The
commenter asked that the language in
the final rule address this issue.
Response: We agree that N2O emitted
from the production of adipic acid that
is sold or transferred offsite is not
covered in the proposed rule. The final
rule has been changed to require this
amount of N2O to be reported. Allowing
for this additional reporting requirement
ensures that the reported N2O emissions
attributed to the adipic acid facility are
accurate. Reporting of the N2O sold or
transferred offsite will help EPA
improve methodologies for reporting of
GHG emissions.
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56295
Method for Calculating GHG Emissions
Comment: Multiple commenters
asked that the requirement to repeat the
annual performance test be removed. In
the proposal, re-testing was triggered
whenever the adipic acid production
rate changed by more than 10 percent.
Commenters asserted that production
depends on demand for adipic acid and
often varies by 15 percent.
Response: Upon review, we decided
to eliminate re-testing. We believe that
annual determination of the N2O
emissions factor is sufficient to
accurately calculate N2O emissions as
long as the production equipment
remains consistent over the year-long
period (i.e. no new abatement
technology).
Comment: Multiple commenters
asked that alternative methods be
allowed for calculating N2O emissions
from adipic acid production.
Specifically the commenters asked that
EPA allow the use of N2O and flow
CEMS to directly measure N2O
emissions and use the performance test
to evaluate the CEMS accuracy. The
commenters also asked that EPA allow
the use of existing process flow meters
and process N2O analyzers to determine
the amount of N2O sent to control
devices and use the performance test to
measure control device destruction
efficiency.
Response: We agree that there are
other means of determining site-specific
N2O emissions. The final rule has been
changed to allow alternative test
methods. Any alternative must be
approved by the Administrator before
being used to comply with this rule. An
implementation plan that details how
the alternative method will be
implemented must be included in the
request for the alternative method. Until
the method is approved facilities must
use the alternatives proposed in the rule
for a performance test. As one
commenter noted, at minimum the
performance test will help to QA/QC
alternative methods currently used to
monitor N2O emissions (such as N2O
CEMS).
EPA understands the need to further
evaluate and establish alternative
comparable methods for sources to use
in accurately calculating N2O emissions
from adipic production and will address
in future rulemakings or amendments to
rulemaking.
The final rule does allow the use of
existing process flow meters and
process knowledge in the determination
of the destruction factor of N2O
abatement technologies. This parameter
is often based on site-specific
knowledge and operations. We believe
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that using existing methods can also
reduce the potential cost impacts of this
rulemaking and that it is in the best
interest of the facilities that process
parameters be accurately measured.
Comment: One commenter asked that
Equation E–2 be edited to follow the
summation format used in the IPCC Tier
2 methodology. The current format does
not allow for multiple abatement
technologies (including no abatement).
Response: We agree with the
commenter. The equation in the
proposed rule contained an error and
did not allow for multiple abatement
technologies. The final rule contains a
corrected version of the equation.
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F. Aluminum Production
1. Summary of the Final Rule
Source Category Definition. The
aluminum production source category
consists of facilities that manufacture
primary aluminum using the Hall´
Heroult manufacturing process. The
primary aluminum manufacturing
process consists of the following
operations:
• Electrolysis in prebake and
S<derberg cells.
• Anode baking for prebake cells.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For aluminum
production, report:
• Perfluoromethane (CF4) emissions
and perfluoroethane (C2F6) emissions
from anode effects in all prebake and
S<derberg electrolysis cells combined.
• CO2 emissions from anode
consumption during electrolysis in all
prebake and S<derberg cells.
• All CO2 emissions from anode
baking.
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable. For example,
report CO2, N2O, and CH4 emissions
from each stationary combustion unit on
site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
GHG Emissions Calculation and
Monitoring. Reporters must calculate
process emissions using the following
methods:
• CF4 from anode effects: Calculate
annual CF4 emissions based on the
frequency and duration of anode effects
in the aluminum electrolytic reduction
process for each prebake and S<derberg
electrolysis cell using the following
parameters:
—Anode effect minutes (AEM) per cellday calculated monthly.
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—Aluminum metal production
calculated monthly.
—A slope coefficient relating CF4
emissions to anode effect minutes per
cell-day and aluminum production.
The slope coefficient is specific to
each smelter and must be measured in
accordance with the protocol
specified in the rule at least once
every 10 years.
—Facilities are allowed to use historic
smelter-specific slope coefficients for
the first three years of reporting under
the rule. Historic measurements
include all those made under EPA’s
Voluntary Aluminum Industry
Partnership or at facilities owned or
operated by companies participating
in the Voluntary Aluminum Industry
Partnership. Facilities without
historic measurements are required to
complete measurements by the end of
first year of reporting.
—Facilities which operate at less than
0.2 anode effect minutes per cell day
or, when overvoltage is recorded,
operate with less than 1.4mV
overvoltage, can use either smelterspecific measured slope coefficients
or the technology-specific (Tier 2)
default coefficients from Volume III,
Chapter 4, Section 4.4 Metal Industry
Emissions of the 2006 IPCC
Guidelines for National Greenhouse
Gas Inventories as specified in the
rule.
• C2F6 from anode effects: Calculate
annual C2F6 emissions from anode
effects from each prebake and S<derberg
electrolysis cell using the calculated CF4
emissions and the mass ratio of C2F6 to
CF4 emissions, as determined during the
same test during which the slope
coefficient is determined.
• Process CO2 emissions—general
approaches. Most reporters can elect to
calculate and report process CO2
emissions from anode consumption
during electrolysis and from anode
baking by either (1) installing and
operating CEMS and following the Tier
4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation
procedures specified below.
• However, if process CO2 emissions
from anode consumption during
electrolysis or anode baking are emitted
through the same stack as a combustion
unit or process equipment that uses a
CEMS and follows Tier 4 methodology
to report CO2 emissions, then the CEMS
must be used to measure and report
combined CO2 emissions from that
stack, instead of using the calculation
procedures specified below.
• CO2 emissions from anode
consumption in prebake cells: Calculate
annual CO2 emissions at the facility
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level using a mass balance equation
based on measurements of the following
parameters:
—Net prebaked anode consumption rate
per metric ton of aluminum metal
produced.
—Ash and sulfur contents of the anodes.
—Total mass of aluminum metal
produced per year for all prebake
cells.
• CO2 emissions from S<derberg cells:
Calculate CO2 emissions from paste
consumption in S<derberg cells using a
mass balance equation at the facility
level based on the following parameters:
—Paste consumption rate per metric ton
of aluminum metal produced and the
total mass of aluminum metal
produced per year for all S<derberg
cells.
—Emissions of cyclohexane-soluble
matter per metric ton of aluminum
produced.
—Binder content of the anode paste.
—Sulfur, ash, and hydrogen contents of
the coal tar pitch used as the binder
in the anode paste.
—Sulfur and ash contents of the
calcined coke used in the anode paste.
—Carbon in the skimmed dust from the
cell, per metric ton of aluminum
produced.
• CO2 emissions from anode baking
of prebake cells: Calculate CO2
emissions at the facility level separately
for pitch volatiles combustion and for
bake furnace packing material.
• To calculate CO2 emissions from
the pitch volatiles, use a mass balance
equation based on the following
parameters:
—Initial weight of the green anodes.
—Mass of hydrogen in the green anodes.
—Mass of the baked anodes.
—Mass of waste tar collected.
• To calculate CO2 emissions from
bake furnace packing material, use a
mass balance equation based on the
following parameters:
—Packing coke consumption rate per
metric ton of baked anode production.
—Sulfur and ash contents of the packing
coke.
• The variables used to calculate CO2
emissions from anode and paste
consumption (e.g., sulfur, ash, and
hydrogen contents) can be determined
for each facility, or the source can use
default values from the 2006 IPCC
Guidelines for National Greenhouse Gas
Inventories as specified in 40 CFR
98.64.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
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additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart F.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
F.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart F:
Aluminum Production.’’
• A new subsection was added in 40
CFR 98.63 providing a new equation
(Eq. F–1) to sum monthly PFC emission
values into annual PFC emission value.
• The equation for CO2 emissions
from S<derberg cells (paste
consumption) was corrected.
• Language was updated to request
reporting of all CO2 emissions from onsite anode baking.
• Language was updated to request
reporting of smelter-specific slope
coefficients (plural).
• A new equation was added in 40
CFR 98.63 (Eq. F–3) to calculate CF4
emissions from overvoltage; and
updated language in subsequent
sections to accommodate the
overvoltage method.
• Language was added to permit
facilities that operate with low anode
effect minutes or low overvoltages to
use IPCC Tier 2 default slope factors.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Three comments on aluminum
production were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart F:
Aluminum Production.’’
Comment: Several commenters
suggested that smelters should be
permitted to use International
Aluminum Institute default slope
coefficients which are based on global
technology-specific averages to calculate
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PFC emissions, especially at high
performance facilities.
Response: The use of smelter-specific
slope coefficients as required in the rule
leads to significantly more precise PFC
emission calculations than the use of
default slope coefficients (95 percent
confidence interval of ±15 compared to
±50 percent). For a typical U.S. smelter
emitting 175,000 metric tons of CO2-eq
in PFCs, these errors result in absolute
uncertainties of ±88,000 MTCO2e and
±26,000 MTCO2e, respectively. The
reduction in uncertainty associated with
moving from default to smelter-specific
slope coefficients, 62,000 MTCO2e, is as
large as the emissions from many of the
sources that would be subject to the
rule. However, for ‘‘high performance’’
facilities, which are defined by the 2006
IPCC Guidelines as those at or below 0.2
anode effect minutes per cell day or less
than 1.4 mV overvoltage, the IPCC
analysis indicates that impact of moving
from a Tier 2 to a Tier 3 slope
coefficient would not result in a
significant improvement in PFC
emissions. Therefore, EPA agrees that
high performance facilities should be
allowed to use technology specific (Tier
2) default values from Volume III,
Chapter 4, Section 4.4 Metal Industry
Emissions of the 2006 IPCC Guidelines
for National Greenhouse Gas
Inventories. These values are identical
to the ‘‘Aluminum Sector Greenhouse
Gas Protocol (Addendum to the WRI/
WBCSD Greenhouse Gas Protocol),’’
October 2006 default coefficients.
Comment: Several commenters argued
the requirement to re-measure smelterspecific slope coefficients every three
years is expensive and unnecessary.
Response: While the cost to require
smelter-specific slope coefficients is
significantly greater than the cost to use
default slope coefficients, the benefit of
reduced uncertainty is considerable, as
noted above. The costs that would be
incurred by smelters measuring slope
factors are discussed in the Regulatory
Impact Analysis (RIA) for the proposed
rulemaking (EPA–HQ–OAR–2008–
0508–002).
Of the currently operating U.S.
smelters, all but one has measured a
smelter specific coefficient at least once;
and at least three used the 2003 EPA/IAI
protocol for measuring smelter-specific
slope coefficients.
The USEPA/IAI Protocol for
Measurement of Tetrafluoromethane
and Hexafluoroethane from Primary
Aluminum Production establishes
guidelines to ensure that measurements
of smelter-specific slope-coefficients are
consistent and accurate (e.g.,
representative of typical smelter
operating conditions and emission
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rates). The Protocol currently
recommends that smelter operators remeasure their slope coefficients at least
every three years, and more frequently
if they adopt changes to process control
algorithms or observe changes to typical
anode effect duration. Specifically, the
Protocol recommends that operators
repeat measurements of slope
coefficients for CF4 and C2F6 if one or
more of the following apply: (1) Thirtysix months have passed since the last
measurements (i.e., triennial
measurements are recommended); (2) a
change occurs in the control algorithm
that affects the mix of types of anode
effects or the nature of the anode effect
termination routine; and, (3) changes
occur in the distribution of duration of
anode effects (e.g. when the percentage
of manual kills changes or if, over time,
the number of anode effects decreases
and results in a fewer number of longer
anode effects).
Changes to process control algorithms
or to the typical duration of anode
effects can change the relationship
between anode effect minutes,
production, and emissions, that is, they
can change slope coefficients. In
addition, more subtle changes can also
change slope coefficients over time.
According to industry experts, the rate
of these more subtle changes has not
been sufficiently studied to specify a
frequency for re-measurement nor have
there been a sufficient number of
facilities that have been measured
repeatedly to document the benefit of
the additional incremental cost of
measurement once every three years.
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. These include the adoption
of slotted anodes and improvements to
process control algorithms. Although
some U.S. smelters have recently
updated their measurements of smelterspecific coefficients, others may not
have.
In view of these recent process
changes, EPA is requiring smelters that
have not already measured their slope
factors under the ‘‘2008 USEPA/IAI
Protocol for Measurement of
Tetrafluoromethane and
Hexafluoroethane from Primary
Aluminum Production,’’ to do so in
time for the 2013 reporting year. EPA
believes that this will ensure that slope
factors are appropriately updated while
providing sufficient lead-time for
smelters to perform the measurements
without encountering excessive costs or
logistical barriers. However, after this
initial update, EPA agrees that every
three years is burdensome, therefore,
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further updates are required only every
ten years unless there are major
technological or process changes at a
facility such as changes to the control
algorithm that affect the mix of types of
anode effects or the nature of the anode
effect termination routine; or changes
occur in the distribution of duration of
anode effects (e.g. when the percentage
of manual kills changes or if, over time,
the number of anode effects decreases
and results in a fewer number of longer
anode effects).
Comment: Several commenters
suggested that the rule should include
the overvoltage measurement method,
which is specific to use with Pechiney
technology, in case one or more U.S.
smelters decide to adopt this technology
in the future.
Response: The Overvoltage 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. While it is EPA’s
understanding that no U.S. smelters
have used the Pechiney technology for
at least a decade, if one or more U.S.
smelters decide to adopt this
internationally accepted technology in
the future they would be expected to
use the overvoltage method which
follow the established guidelines in the
‘‘USEPA/IAI Protocol for Measurement
of Tetrafluoromethane and
Hexafluoroethane from Primary
Aluminum Production.’’
G. Ammonia Manufacturing
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1. Summary of the Final Rule
Source Category Definition. The
ammonia manufacturing source category
consists of process units in which
ammonia is manufactured from a fossilbased feedstock via steam reforming of
the hydrocarbon. It also includes
ammonia manufacturing processes in
which ammonia is manufactured
through the gasification of solid and
liquid raw material.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For ammonia
manufacturing, report the following
emissions:
• CO2 process emissions from steam
reforming of a hydrocarbon or the
gasification of solid and liquid raw
material, reported for each ammonia
manufacturing process unit following
the requirements of this part.
• CO2, CH4, and N2O emissions from
each stationary combustion unit. Report
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these emissions under 40 CFR 98,
subpart C (General Stationary Fuel
Combustion Sources) by following the
requirements of 40 CFR part 98, subpart
C.
• For CO2 collected and transferred
off site, report these emissions under 40
CFR part 98, subpart PP (Suppliers of
CO2) following the requirements of 40
CFR part 98, subpart PP.
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. Reporters must use one of
two methods to calculate CO2 process
emissions, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions from
each ammonia manufacturing process
unit by either (1) installing and
operating CEMS and following the Tier
4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation
procedures contained in the rule and
summarized below.
• However, if process CO2 emissions
from an ammonia manufacturing
process unit are emitted through the
same stack as CO2 emissions from a
combustion unit or process equipment
that uses a CEMS and follows Tier 4
methodology to report CO2 emissions,
then the CEMS must be used to measure
and report combined emissions from
that stack, instead of using the
calculation procedures described below.
• To calculate process CO2 emissions,
use the equations provided in 40 CFR
part 98, subpart G for solid, liquid, and
gaseous feedstock and the following
measurements:
—Continuous measurement of gaseous
or liquid feedstock consumed using a
flowmeter, or monthly aggregate of
solid feedstock consumed.
—Carbon content of the feedstock
(required to be measured monthly
using supplier data or analysis using
the appropriate test methods). If
supplier data are used, facilities must
QA/QC the supplier analysis on an
annual basis using the appropriate
test methods.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart G.
Recordkeeping. In addition to the
records required by the General
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Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
G.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart G: Ammonia
Manufacturing.’’
• Monitoring and QA/QC
requirements were revised to allow for
obtaining carbon content of feedstock
used in ammonia manufacturing from
the feedstock supplier. Facilities that
obtain monthly carbon content
information from their supplier are
required to QA/QC supplier information
through annual sampling and analysis
of the feedstock.
• Missing data procedures were
added under 40 CFR 98.75 for
parameters that facilities must measure
such as feedstock consumption, the
quantity of the waste recycle stream,
and the monthly carbon content of both
the feedstock consumption and waste
recycle stream quantity.
• Reporting requirements were added
for the quantity of urea produced and
the emissions associated with waste
recycle streams commonly found at
ammonia manufacturing facilities.
• 40 CFR 98.76 was reorganized and
updated to improve the emissions data
verification process. Some data
elements were moved from 40 CFR
98.77 to 40 CFR 98.76, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.73 were added to 40 CFR 98.76
for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Several comments on ammonia
manufacturing were received covering
numerous topics. Several of these
comments were directed at the
requirements for 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources), and responses to
those comments are provided in Section
III.C of this preamble. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
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Public Comments, Subpart G: Ammonia
Manufacturing.’’
Method for Calculating GHG Emissions
Comment: Several commenters asked
EPA to clarify that ammonia production
units must use Tier 4 calculation only
if all of the conditions under proposed
40 CFR 98.33(b)(5)(ii)(A) through (F)
apply to the unit and only where the
ammonia manufacturing unit already
has installed a stack gas volumetric flow
rate monitor and a CO2 concentration
monitor.
Response: We agree with the
comment and have modified the text
under 40 CFR 98.73(a) and (b) to state
that if a facility operates and maintains
CEMS that meet the requirements of 40
CFR 98.33(b)(4)(ii) or (iii), then process
or combined process and combustion
CO2 emissions shall be calculated and
reported under this subpart by following
the Tier 4 Calculation Methodology
specified in 40 CFR 98.33(a)(4) and all
associated requirements for Tier 4 in 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources). If
CEMS are not used to determine CO2
emissions from ammonia processing
units, then facilities must calculate and
report process CO2 emissions under this
subpart by using equations provided in
40 CFR 98.73(b)(1) through (b)(4). CO2
combustion emissions from ammonia
processing units must be reported under
40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
For additional clarification on the
requirements on use of CEMS see 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources),
and Section III.C of this preamble.
Comment: One commenter noted that
most ammonia facilities utilize natural
gas combustion combined with
approximately five percent recycle flow
of gas containing methane from the
process. The carbon content of the
recycle stream is already accounted for
when measuring the feedstock flow rate
and carbon content to the process. EPA
should allow ammonia manufacturers to
exclude this recycle stream in
calculating combustion emissions, as
the carbon in the recycle stream would
be double counted.
Response: We agreed with
commenters that it is important to
account for use of the waste process
stream in the case that it is recycled
since carbon in the recycle stream is not
actually emitted. In response to this
comment we have added reporting
requirements for quantifying emissions
associated with the recycle stream. This
will help EPA improve methodologies
for calculating emissions from ammonia
manufacturing in the future.
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Monitoring and QA/QC Requirements
Comment: Several commenters stated
that monthly carbon content sampling
and analysis requirement is overly
burdensome. Some commenters asked
that EPA allow the use of a default value
for carbon content while one commenter
suggested use of carbon content data
generated by the feedstock supplier.
Response: We agreed with
commenters that flexibility should be
added to the rule to allow for use of
supplier data. This information is
readily available from the feedstock
supplier in most cases. The most
common feedstock for ammonia
production is pipeline quality natural
gas. Supplier data on carbon contents of
feedstock will have sufficient or
comparable accuracy for the purposes of
calculating CO2 emissions. We modified
the monitoring and QA/QC procedures
in the rule to allow use of carbon
content data obtained from the
feedstock supplier(s). Facilities that
obtain monthly carbon content
information from their supplier are
required to QA/QC supplier information
through annual sampling and analysis
of the feedstocks consumed.
Procedures for Missing Data
Comment: Two commenters suggested
that the proposed procedures for
calculating emissions in the event of
missing feedstock data would yield
significant overstatements of GHG
emissions. As proposed, if feedstock
supply rate data are missing for a
specific day or days (e.g., if a meter
malfunctions during unit operation), the
reporting entity must use the lesser of
the maximum supply rate that the
production unit is capable of processing
or the maximum supply rate that the
meter can measure. If this substitution
is applied to the feedstock for reformers
used in ammonia production, either of
these proposed approaches would likely
result in significant over reporting of
carbon emissions. The commenter
proposed two alternatives that a
reporting facility could use: Either
(1) substitute an estimated value for
feedstock supply rate, based on the
arithmetic average of the previous thirty
days of available feedstock supply rate
data; or (2) utilize missing data
estimating procedures similar to the
procedure under 40 CFR 98.35(b)(2),
based upon all available process data.
These approaches would result in much
more accurate estimates of emissions
derived from the true historical
operation of a specific ammonia
manufacturing source.
Response: We agreed with
commenters that the proposed missing
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data procedures would overestimate
emissions when applied. While some of
feedstock should be readily available
and collected as a part of normal
business practices, circumstances could
arise where data could be missing. We
added procedures consistent with the
commenter’s second recommendation,
referencing the missing data procedures
in 98.35(b)(2). Ammonia facilities with
missing data on feedstock supply rate
must provide the best available estimate
from all available process data.
Facilities must document and keep
records of missing data procedures
applied. We find that these revised
procedures will provide accurate
information for the purposes of this
rulemaking.
Data To Be Reported
Comment: One commenter noted that
the CO2 produced through ammonia
manufacturing can be utilized and that
much of it is in the manufacture of urea.
The commenter stated that EPA makes
unsubstantiated assumptions that all
CO2 in urea will be released into the
atmosphere. The commenter asked EPA
not to tie emissions from applied urea,
or emissions that result from urea once
the product has been sold, to the
producing industry.
Response: We added reporting
requirements for annual urea
production under 40 CFR 98.76.
Information on urea production will
help us improve our understanding of
the quantity of CO2 consumed from
ammonia production that is used in the
manufacture of urea. We know from the
US GHG inventory and subsequent
conversations with ammonia producers
that on average it takes 0.733 tons of
CO2 to produce one ton of urea. We
have also requested that producers
report, if known, the uses of the urea
sold. Collecting information on urea
production and its uses will help EPA
to improve methodologies for
calculating emissions from ammonia
manufacturing, urea production, and
urea consumption in the future.
H. Cement Production
1. Summary of the Final Rule
Source Category Definition. The
cement production source category
consists of each kiln and each inline
kiln/raw mill at any Portland cement
manufacturing facility, including alkali
bypasses and kilns and inline kilns/raw
mills that burn hazardous waste.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
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GHGs to Report. For cement
production, report the following
emissions:
• CO2 process emissions from
calcination, reported for each kiln.
• CO2 combustion emissions from
each kiln.
• N2O and CH4 emissions from fuel
combustion at each kiln under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources) using the
methodologies in subpart C.
• CO2, N2O, and CH4 emissions from
each stationary combustion unit other
than kilns under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources).
• In addition, report GHG emissions
for any other source categories for
which calculation methods are provided
in other subparts of the rule, as
applicable.
GHG Emissions Calculation and
Monitoring. For CO2 emissions from
kilns, reporters must select one of two
methods, as appropriate:
• For kilns with certain types of
CEMS in place, reporters must use the
CEMS and follow the Tier 4
methodology (in 40 CFR part 98, subpart
C) to measure and report under the
Cement Production subpart (40 CFR part
98, subpart H) combined calcination
and fuel combustion CO2 emissions.
• For other kilns, the reporter can
elect to either (1) install or operate a
CEMS and follow the Tier 4
methodology to measure and report
combined calcination and fuel
combustion CO2 emissions or (2)
calculate process CO2 emissions as the
sum of clinker emissions and emissions
from raw materials. If using approach
(2):
—Calculate clinker emissions monthly
from each kiln using monthly clinker
production (required to be measured);
a kiln-specific, monthly clinker
emission factor calculated from the
monthly CaO and MgO content of the
clinker (required to be measured);
quarterly cement kiln dust not
recycled to the kiln (required to be
measured); and a quarterly kilnspecific factor of calcined material in
the cement kiln dust not recycled to
the kiln (measured or default values
can be used).
—Calculate raw material emissions
annually from the annual
consumption of raw materials and the
organic carbon content in the raw
material (measured annually for each
type of raw material, or a default
value of 0.2 percent may be used).
—Report process CO2 emissions from
each kiln under 40 CFR part 98,
subpart H (Cement Production), and
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report combustion CO2 emissions
from each kiln under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
Subpart H (Cement Production).
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
H (Cement Production).
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart H: Cement
Production.’’
• The CO2 calculation equations in 40
CFR 98.83 were revised to account for
non-carbonate sources of calcium and
magnesium in the kiln feed and
uncalcined carbonates in the product.
• Methods for monitoring CaO and
MgO in clinker and CKD were changed
from XRF to ASTM c114–07, Standard
Test Methods for Chemical Analysis of
Hydraulic Cement.
• 40 CFR 98.84 was revised to clarify
required monitoring frequency and to
allow for alternative monitoring
methods for raw materials and CKD.
• Missing data procedures were
added to 40 CFR 98.85 for parameters
reporters must measure, clinker, CKD
not recycled to the kiln, raw material
consumption, carbonate contents of
clinker CKD, non-calcined content of
clinker and CKD, and organic carbon
content of raw materials.
• Requirements in 40 CFR 98.81
through 40 CFR 98.87 were revised to
clarify which requirements apply to
reporters who elect to report CO2
emissions using CEMS.
• 40 CFR 98.86 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.87 to 40 CFR 98.86, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
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CFR 98.83 were added to 40 CFR 98.86
for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. We
received several comments on cement
production covering a number of topics.
Many of these comments were directed
at the requirements for 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources), and responses to
those comments are provided in Section
III.C of this preamble dealing with that
source category. Also see Section II.N of
this preamble for the response to
comments on the emissions verification
approach.
Responses to significant comments
received related to process emissions
from cement production can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart H: Cement
Production.’’
Selection of Threshold
Comment: One commenter suggested
that EPA could reduce the burden
presented by the Proposed Rule by
reducing the number of facilities
required to report (i.e., raise the
reporting thresholds). The commenter
further noted that by requiring GHG
reporting for all cement plants,
regardless of the magnitude of the
plant’s emissions, EPA removes an
incentive for those plants to reduce
GHG emissions to get below a threshold
in order to avoid the burden of
monitoring and reporting.
Response: In considering the
comment, we acknowledge the potential
benefit of a reporting threshold
providing cement plants with incentive
to reduce their GHG emissions. The
‘‘once in, always in’’ provision has been
removed. The final rule now contains
provisions to cease reporting if annual
reports demonstrate emissions less than
specified levels for multiple years.
These provisions apply to all reporting
facilities. See Section II.H of this
preamble for the response on provisions
to cease reporting. See Section II.D of
this preamble for the response on
selection of source categories to report.
In developing the Proposed Rule, 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. All of these
emission thresholds covered more than
99.9 percent of CO2e emissions from
cement facilities. Only one plant out of
107 in the dataset would be excluded by
the highest considered thresholds of
100,000 metric tons CO2e. Therefore, we
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determined that it was appropriate to
include all cement production facilities
in the reporting requirements.
Method for Calculating GHG Emissions
Comment: Two commenters stated
that the cement industry already has an
established, proven protocol for
calculating and reporting GHG
emissions, and requested that EPA use
the existing Cement CO2 Protocol as the
basis for the Proposed Rule.
Commenters further stated that the
Cement CO2 Protocol already provides
many of the benefits that EPA ascribes
to the Proposed Rule, including
uniformity of reported data from one
facility to another; availability of
verifiable data to provide to the public,
investors, and others; and other
suggested benefits.
Both commenters stated that EPA
needs to revise its clinker-based
calculation to account for any noncarbonated CaO or MgO in the raw
materials.
Response: In developing the proposed
Rule, we considered many domestic and
international GHG monitoring
guidelines and protocols, including the
Cement Sustainability Initiative
Protocol referenced in the cement
industry’s comments. We combined
elements of the Cement CO2 Protocol
with elements of other protocols
including the 2006 IPCC Guidelines,
U.S. Inventory, DOE 1605(b), CARB
mandatory GHG emissions reporting
program, EPA’s Climate Leaders
program, and the EU Emissions Trading
System to develop two proposed
methods for quantifying GHG emissions
from cement manufacturing. These
proposed methods include the use of
CEMS to directly measure emissions
and the use of calculation methods to
determine emissions.
While finalizing today’s rule, we
revisited the Cement CO2 Protocol and
compared its requirements to our
requirements. We feel that the rule
closely mirrors the GHG calculation
methods and requirements of the
Cement CO2 Protocol with some minor
differences. For example, our rule
requires cement plants to use plantspecific emission factors to calculate
CO2 emissions and does not allow the
use of default emission factors. As
stated in the proposal, 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
readily available to develop site-specific
emission factors. Default approaches
would not provide site-specific
calculation of emissions that reflect
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differences in inputs, operating
conditions, fuel combustion efficiency,
variability in fuels, and other
differences among facilities. Further, it
is our understanding that facilities
analyze data relevant for site-specific
determinations such as the carbonate
contents of their raw materials to the
kiln and products on a frequent basis,
either on a daily basis or every time
there is a change in the raw material
mix. Using data from direct
measurements will provide a more
accurate representation of site specific
emissions rates.
We also note that the Cement CO2
Protocol does not specify measurement
methods. Our rule specifies methods for
measuring CaO, MgO, and clinker
weight. We selected these methods to be
consistent with measurement
techniques that are common within the
cement industry. Prescribing
standardized measurement procedures
ensures the uniformity and consistency
in the results and quality of data
reported that the commenters agree is
important for comparability of
emissions.
We also used the Cement CO2
Protocol as a model for revising our
equations in 40 CFR 98.83 to account for
non-carbonate sources of calcium and
magnesium that may be present in the
kiln feed.
Monitoring and QA/QC Requirements
Comment: One commenter expressed
concern that 40 CFR 98.84(e) and (f)
seem to require continuous, direct
weight measurement of CKD discarded
and raw materials used, by category of
material. The commenter stated that
most cement plants do not have that
capability, and that the proposed rule
does not clearly state whether
installation of additional measurement
equipment will be required if not
already installed.
One industry representative further
recommended that EPA add truck
weight scales as an acceptable option for
raw material weight measurement to
address certain limited cases in which
this method may be more appropriate to
use. In addition, the commenter
recommended that EPA allow CKD
samples to be taken either as CKD exits
the kiln or from bulk storage.
Response: We revised the text in 40
CFR 98.84(e) and (f) to more clearly
state that CKD quantities are required to
be measured on a quarterly basis and
raw material quantities are required to
be measured on a monthly basis.
Furthermore, the Proposed Rule was
never intended to require installation of
new monitoring equipment for this
purpose. We agree with the commenter
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that continuous, direct weight
measurement of these materials and
installation of additional measurement
equipment would be unnecessary. The
proposed rule clearly stated that the
quantity of CKD produced and raw
materials consumed must be determined
using the same plant instruments that
the cement plant currently uses for
accounting purposes. Moreover, because
the quantities of raw materials and CKD
do not greatly impact the CO2
calculation, we added further
clarification to this section to allow
cement plants to use potentially less
accurate, but commonly used, methods
of measurement, such as truck weigh
scales, to determine quantities of CKD
and raw materials. We also added
clarification to 40 CFR 98.84 to allow
facilities to collect CKD samples either
as CKD exits the kiln or from bulk
storage.
Data Reporting Requirements
Comment: Two commenters asserted
that EPA needs to provide clarifying
language within 40 CFR part 98, subpart
H (Cement Production) to define which
requirements apply to facilities using
CEMS to monitor CO2 emissions. One
commenter noted that the Proposed
Rule, as written, appears to require
cement plants using CEMS to collect
maintain, and report process data
related to calculating CO2 process
emissions for kilns pursuant to
proposed 40 CFR 98.84 through 98.87.
This commenter claimed that requiring
plants to collect and report such process
data are redundant if the facility is
continuously monitoring CO2 emissions.
Another commenter recommended that
EPA state within 40 CFR part 98,
subpart H (Cement Production) that all
of the requirements detailed in the
subpart do not apply to cement kilns
using Tier 4 (CEMS) method.
Response: We agree with the
comment that reporters who are using
CEMS to monitor CO2 do not need to
collect, report, and maintain all of the
process data required in proposed 40
CFR 98.84 through 98.87. However, we
determined that some of the process
data are necessary for emissions
verification purposes, and therefore,
plants using CEMS are not completely
excluded from the requirements in 40
CFR part 98, subpart H (Cement
Production). We added clarifying
language throughout the Subpart to
clearly state which requirements will
apply to facilities that use CEMS to
measure CO2 emissions. Specifically, we
created separate lists of reporting
requirements and recordkeeping
requirements for cement plants using
CEMS.
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J. Ethanol Production
I. Electronics Manufacturing
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Comment: One commenter noted that
the data reporting requirements for
cement plants, set forth in proposed 40
CFR 98.86, are expressed in different
terms that those used for the specified
procedures for calculating emissions.
For example, the commenter stated that
it is unclear what emission sources go
into the ‘‘site-specific emission factor
(metric tons CO2/metric ton clinker
produced)’’ required to be reported
under proposed 40 CFR 98.86(h), and
how that factor would be calculated.
Response: We agree with the
commenter that there were
inconsistencies between 40 CFR 98.83
and 98.86. We updated reporting
requirements in 40 CFR 98.86 to be
consistent with the terms used in the
emission calculation procedures in 40
CFR 98.83 and provide clarification in
40 CFR 98.83 for terms if needed. As a
result, some calculations that are
performed on a kiln-specific basis, such
as CO2 emission factors, will be required
to be reported on a kiln-specific basis in
40 CFR 98.86. Also see the Section II.N
of this preamble for the response to
comments on the emissions verification
approach.
K. Ferroalloy Production
At this time EPA is not going final
with the electronics manufacturing
subpart. As we consider next steps, we
will be reviewing the public comments
and other relevant information.
The Agency received a number of
lengthy, detailed comments regarding
the electronics manufacturing subpart.
Commenters generally opposed the
proposed reporting requirements and
stated the proposal required excessive
detail. For example, commenters
asserted that they currently do not
collect the data required to report using
an IPCC Tier 3 approach and that to
collect such data would entail
significant burden and capital costs. In
most cases, commenters provided
alternative approaches to each of the
reporting requirements proposed by
EPA.
Commenters also requested
clarification from EPA on a number of
the proposed reporting provisions.
Based on careful review of comments
received on the proposal preamble, rule,
and technical support documents
(TSDs) under proposed 40 CFR part 98,
subpart I, EPA will perform additional
analysis and evaluate a range of data
collection procedures and
methodologies. EPA’s goal is to
optimize methods of data collection to
ensure data accuracy while considering
industry burden.
1. Summary of the Final Rule
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At this time, EPA is not finalizing the
Ethanol Production Subpart. The
sources of GHG emissions at ethanol
production facilities that were to be
reported under the proposed rule were
stationary fuel combustion, onsite
landfills, and onsite wastewater
treatment. EPA has decided not to
finalize the portion of 40 CFR part 98,
subpart HH (Landfills) that addresses
industrial landfills nor 40 CFR part 98,
subpart II (Wastewater Treatment).
Stationary fuel combustion sources at
ethanol production facilities are subject
to the requirements of 40 CFR part 98,
subpart C if general stationary fuel
combustion emissions exceed the
25,000 metric tons CO2e threshold.
As EPA considers next steps, we will
be reviewing the public comments and
other relevant information. Based on
careful review of comments received on
the proposal preamble, rule and TSDs
under proposed 40 CFR part 98,
subparts J, HH, and II, EPA will perform
additional analysis and consider
alternatives to data collection
procedures and methodologies
contained in those subparts.
Source Category Definition. The
ferroalloy production source category
consists of facilities that use
pyrometallurgical techniques to produce
any of the following metals:
ferrochromium, ferromanganese,
ferromolybdenum, ferronickel,
ferrosilicon, ferrotitanium,
ferrotungsten, ferrovanadium,
silicomanganese, or silicon metal.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For ferroalloy
production, report the following
emissions.
• Annual process CO2 emissions from
each EAF used for production of any
ferroalloy listed in the source category
definition.
• Annual process CH4 emissions for
those EAFs used for the production of
silicon metal, ferrosilicon 65 percent,
ferrosilicon 75 percent, or ferrosilicon
90 percent.
• CO2, N2O, and CH4 emissions from
each stationary combustion unit on site
under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
• In addition, report emissions from
any other source categories for which
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calculation methodologies are specified
in the rule, as applicable.
GHG Emissions Calculation and
Monitoring. To calculate process CO2
emissions from EAFs, reporters can use
one of two methods, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions from
each EAF by either (1) installing and
operating a CEMS and following the
Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) using the carbon mass
balance calculation procedure specified
in the rule and summarized below.
• However, if CO2 process emissions
from an EAF are emitted through the
same stack as CO2 emissions from a
combustion unit or process equipment
that uses a CEMS and follows Tier 4
methodology to report CO2 emissions,
then the CEMS must be used to measure
and report combined emissions from
that stack, instead of using the carbon
mass balance calculation procedure
described below.
• If using the carbon mass balance
procedure, perform a once per year
calculation using equations in the rule
and:
—Recorded monthly production data,
and
—The average carbon content for each
EAF input and output material
determined by either using material
supplier information or by annual
analysis of representative samples of
the material.
• For those EAF’s for which the
reporter must report annual CH4
emissions, annual ferroalloy production
data are used with an applicable
emissions factor provided in the rule.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart K.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98,
subpart K.
2. Summary of Major Changes Since
Proposal
The major changes to the rule since
proposal for ferroalloy production
facilities were revisions to the carbon
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mass balance calculation procedure for
calculating process CO2 emissions from
EAFs. These changes reduce the
reporting burden and are consistent
with revisions made to other similar
industries. The rationale for these and
any other significant changes can be
found below or in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
K: Ferroalloy Production.’’
• Frequency of performing the carbon
mass balance calculations was revised
to be required on an annual basis
instead of the proposed monthly basis.
• Frequency of material carbon
content sampling and analysis of each
EAF input and output material used for
the material balance was revised to be
performed by annual analysis of
representative samples of the material
instead of the proposed monthly basis.
• Materials contributing less than one
percent of the total carbon into or out
of the EAF do not need to be included
carbon mass balance calculations.
• 40 CFR 98.116 and 98.117 were
reorganized and updated to improve the
emissions verification process. Some
data elements were moved from 40 CFR
98.117 to 40 CFR 98.116, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.173 were added to 40 CFR
98.116 for clarity. See Section II.N of
this preamble for the response to
comments on the emissions verification
approach.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Other comments on ferroalloy
production were received covering
various topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart K: Ferroalloy
Production.’’
Comment: One comment was received
on the proposed rule specific to
ferroalloy production facilities. The
commenter requested that EPA allow
ferroalloy production facilities to use
alternative methods for determining
EAF process CO2 emissions other than
those proposed, and specifically a
protocol for silicon metal production
facilities developed for use by the
Chicago Climate Exchange. This
smelting protocol was developed a
protocol for calculating the CO2
emissions from based on the World
Resources Institute (WRI) aluminum
smelting protocol.
Response: We reviewed the WRI
aluminum smelting protocol, which was
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publicly available and we tried to obtain
a copy of the specific protocol that the
commenter mentions to fully evaluate
whether it is an appropriate alternative.
However, we never received it in the
long run. The commenter did not
provide additional or more specific
recommendations beyond the reference
to improve or revise the proposed
methodology. At this time, given
insufficient information, we have
decided not to include additional
alternative methods in the final rule for
ferroalloy production facilities. As we
stated at proposal, the selected
methodology was based on review of
several 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.
However, we have revised the
frequency of sampling and analysis of
carbon contents for carbon containing
input and output materials monthly to
annual consistent with revisions made
in response to comments for similar
production processes (e.g. emissions
from metal production). These revisions
reduce the reporting burden for
ferroalloy production facilities. We
understand that the carbon content of
material inputs and outputs does not
vary widely at a given facility for the
significant process inputs that contain
carbon, and we continue to account for
variations due to changes in production
rate, which is likely a more significant
source of variability. The response to
the comment can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart K: Ferroalloy
Production.’’
L. Fluorinated GHG Production
At this time EPA is not going final
with the subpart for emissions from
fluorinated GHG production. As we
consider next steps, we will be
reviewing the public comments and
other relevant information.
The Agency received a number of
lengthy, detailed comments regarding
the fluorinated GHG production
subpart. Commenters generally opposed
the proposed reporting requirements.
Several commenters stated that facilities
could not meet the proposed accuracy,
precision, and frequency requirements
using existing equipment and practices.
These commenters stated that they
would need to expend significant funds
(millions of dollars in some cases) and
time to install Coriolis flowmeters in
multiple streams and to implement
daily sampling protocols to analyze the
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56303
contents of these streams. Some
commenters stated that even after such
equipment was installed, the proposed
mass-balance approach was likely to be
inaccurate, particularly for batch
processes. In most cases, commenters
provided alternative approaches, such
as emission-factor based approaches, to
the proposed mass-balance approach.
Based on careful review of comments
received on the proposal preamble, rule,
and TSDs under proposed 40 CFR part
98, subpart L, EPA will perform
additional analysis and evaluate a range
of data collection procedures and
methodologies. EPA’s goal is to
optimize methods of data collection to
ensure data accuracy while considering
industry burden.
M. Food Processing
At this time, EPA is not going final
with the Food Processing Subpart. The
sources of GHG emissions at food
processing facilities that were to be
reported under the proposed rule were
stationary fuel combustion, onsite
landfills, and onsite wastewater
treatment. EPA has decided not to
finalize the portion of 40 CFR part 98,
subpart HH (Landfills) that addresses
industrial landfills nor 40 CFR part 98,
subpart II (Wastewater Treatment). Note,
however, that Stationary fuel
combustion sources at food processing
facilities are subject to the requirements
of 40 CFR part 98, subpart C if general
stationary fuel combustion emissions
exceed the 25,000 metric ton CO2e
threshold. As EPA considers next steps,
we will be reviewing the public
comments and other relevant
information.
Based on careful review of comments
received on the proposal preamble, rule
and TSDs under proposed 40 CFR part
98, subparts M, HH, and II, EPA will
perform additional analysis and
consider alternatives to data collection
procedures and methodologies
contained in those subparts.
N. Glass Production
1. Summary of the Final Rule
Source Category Definition. The glass
production source category consists of
facilities that manufacture glass
(including flat, container, pressed, or
blown glass) or wool fiberglass using
one or more continuous glass melting
furnaces. Experimental furnaces and
research and development process units
are excluded.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
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GHGs to Report. For glass production
facilities, report the following
emissions:
• CO2 process emissions from each
continuous glass melting furnace.
• CO2 combustion emissions from
each continuous glass melting furnace,
• CH4 and N2O emissions from fuel
combustion at each continuous glass
melting furnace under 40 CFR part 98,
subpart C (General Stationary
Combustion Sources) using the
methodologies in subpart C.
• CO2, CH4, and N2O emissions and
from each onsite stationary fuel
combustion unit other than continuous
glass melting furnaces under 40 CFR
part 98, subpart C (General Stationary
Combustion Sources).
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. For CO2 process emissions
from glass melting furnaces, reporters
must use one of two methods, as
appropriate:
• For glass melting furnaces with
certain types of CEMS in place,
reporters must use the CEMS and follow
the Tier 4 methodology (in 40 CFR part
98, subpart C) to measure and report
under the glass production subpart (40
CFR part 98, subpart N) combined
process and combustion CO2 emissions.
• For other glass melting furnaces, the
reporter can elect to either (1) install
and operate a CEMS and follow the Tier
4 methodology to measure and report
combined process and combustion CO2
emissions or (2) calculate process CO2
emissions for each furnace using an
emission factor and process data. If
using approach (2), multiply a default
emission factor appropriate for the
carbonate raw material by:
—The annual mass of carbonate-based
raw material charged to the furnace
(required to be measured); and
—The mass-fraction of carbonate in the
raw material (based on data supplied
by the raw material supplier and
verified by an annual measurement).
—Under approach (2), report process
CO2 emissions from each glass
melting furnace under 40 CFR part 98,
subpart N (Glass Production), and
report combustion CO2 emissions
from each glass furnace under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
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additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart N.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
N.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart N: Glass
Production.’’
• The definition of the term ‘‘glass
produced’’ was added to the definitions
in 40 CFR part 98, subpart A.
• 40 CFR 98.146 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.147 to 40 CFR 98.146, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.143 were added to 40 CFR
98.146 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Several comments on glass production
were received covering numerous
topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart N: Glass
Production.’’
Definition of Source Category
Comment: One commenter stated that
EPA should exempt from the rule all
fiber glass and rock and slag wool
insulation facilities within the glass
production source category because
glass production facilities subject to the
proposed rule are a miniscule portion of
the total national emissions of CO2e,
and amount to less than 0.1 percent of
total GHG emissions in the U.S. and the
subset of fiber glass and rock and slag
wool insulation facilities is an even
smaller portion. The commenter stated
that there is virtually no benefit to
having the glass production source
category subject to the proposed rule,
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and any benefit is outweighed by the
burden imposed on these facilities. The
commenter also pointed out the
importance of the fiber glass and rock
and slag wool insulation industry’s
products in meeting the nation’s energy
needs and reducing GHG emissions.
Exempting the industry from the
proposed rule’s reporting requirements
will help the industry focus more of its
scarce resources on producing
insulation.
Response: We recognize that the glass
manufacturing industry is comprised of
a wide range of facilities, many of which
are small in size and have relatively low
levels of emissions. However, the data
we have collected on the industry
indicate that there are several large glass
manufacturing plants with significant
GHG emissions. These plants include
some that produce glass fiber, flat glass,
and container glass, as well as other
types of pressed and blown glass
products. As a result, we do not agree
with the commenter that fiber glass and
other types of insulation facilities
should be exempt from reporting.
However, we tried to reduce the burden
on the glass manufacturing industry by
incorporating into the proposed rule a
25,000 metric ton CO2e threshold,
which should preclude small facilities
from having to report GHGs. This
threshold remains in the final rule.
Thus, any small fiber glass and rock and
slag wool insulation facilities with low
GHG emissions will fall under the
threshold and will be exempt from
reporting. To further minimize the
burden on the industry, we have tried
to limit recordkeeping and reporting
requirements to the types of data that
glass production facilities already
collect as part of normal business
operations.
Commenters may also be interested in
reviewing Section II.H of this preamble
for the response on provisions to cease
reporting. The final rule contains
provisions to cease reporting if annual
reports demonstrate emissions less than
specified levels for multiple years.
Selection of Threshold
Comment: One commenter remarked
that EPA should raise the threshold for
reporting for fiberglass and rock and
slag wool insulation entities. Doing so
would reduce the number of entities
reporting with only a minimal impact
on the amount of emissions covered.
The commenter stated that EPA’s
analysis did not address reasonable
alternative thresholds between 25,000
and 100,000 metric tons.
Response: When evaluating potential
thresholds for reporting GHG emissions,
we considered several thresholds
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between 1,000 and 100,000 metric tons
CO2e. We selected the 25,000 metric
tons CO2e threshold for reporting GHG
emissions in order to achieve a balance
between quantifying the majority of the
emissions and minimizing the number
of facilities impacted. For example, at a
1,000 metric tons CO2e threshold, 98
percent of emissions would be covered,
with about 58 percent of facilities being
required to report. Compared to the
100,000 metric tons CO2e threshold, the
proposed 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 facilities in the
industry to report. This threshold offers
significant coverage of the GHG
emissions while impacting a relatively
small portion of the industry. Although
a threshold of 50,000 metric tons CO2e
would greatly reduce the number of
facilities reporting, it would capture less
than 20 percent of total emissions for
the industry. We believe the proposed
threshold of 25,000 metric tons CO2e
represents the best option for ensuring
that the majority of emissions are
reported without imposing an
unreasonable burden on the industry.
Section II.E of this preamble contains
a general discussion of the selection of
the 25,000 metric tons CO2e threshold.
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Method for Calculating GHG Emissions
Comment: One commenter fully
supports EPA’s proposed rule for
measuring, calculating, monitoring, and
reporting emissions from the glass
melting process. They agree that 40 CFR
part 98, subpart N represents a good
balance between site reporting burden,
cost, and data accuracy and consistency.
Specifically, the commenter supports
using raw-material emissions factors
and usage rates, as proposed, to
calculate emissions from glass
production in lieu of requiring installing
CEMs on sources that another regulation
does not currently require to be
installed.
Response: We acknowledge this
support for the proposal and appreciate
these comments. We have retained the
proposed calculation methodology in
the final rule.
Data Reporting Requirements
Comment: One commenter stated that,
at various places in the preamble and
proposed rule, EPA uses the phrase
‘‘glass produced,’’ but has not defined
this phrase in the rule. The commenter
noted that the phrase could be
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interpreted to mean either glass melted
or glass product produced. The
commenter assumed that the phrase
refers to the amount of glass melted, but
requested clarification.
Response: We agree that the term
glass produced is subject to
interpretation. We have added a
definition of the term to 40 CFR part 98,
subpart A of the final rule. ‘‘Glass
produced’’ means the weight of glass
exiting a glass melting furnace.
Comment: One commenter remarked
that some of the information that would
have to be reported under the proposed
rule, such as annual quantity of glass
produced, is considered to be company
confidential and could be used by
competitors to back-calculate product
formulas. The commenter requested that
EPA remove these reporting
requirements from the rule and instead,
require that the data be retained by the
facility and made available for review
by EPA. Should EPA require the
reporting of all of this information in the
final rule, the commenter requests that
EPA explicitly state in the final rule and
confirm in the preamble to the final rule
that all information provided under 40
CFR part 98, subpart N, other than the
annual process emissions of CO2, is
considered confidential information and
would not be considered ‘‘emission
data’’ under this reporting rule. The
commenter requests that a new
paragraph (e) be added to 40 CFR 98.146
that reads: ‘‘No information required to
be reported by this section, other than
the information required by 40 CFR
98.146(a), is considered to be emission
data under 40 CFR 2.301(a)(2)(i) and
(ii).’’
Response: We acknowledge the
commenter’s concerns. However, the
quantity of glass produced is an
important variable for EPA to verify
whether reported emissions are within a
reasonable range and therefore is a
required reporting parameter under 40
CFR part 98, subpart N.
We have reviewed CBI comments
received across the rule (both general
and subpart-specific comments) and our
response is discussed in Section II.R of
this preamble and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’
O. HCFC–22 Production and HFC–23
Destruction
1. Summary of the Final Rule
Source Category Definition. This
source category consists of:
• Processes that produce HCFC–22
(chlorodifluoromethane or CHClF2)
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using chloroform and hydrogen
fluoride.
• HFC–23 destruction processes
located at HCFC–22 production
facilities.
• HFC–23 destruction processes that
destroy more than 2.14 metric tons of
HFC–23 per year and that are not
located at HCFC–22 production
facilities.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For facilities that
produce HCFC–22 or that destroy HFC–
23, report the following emissions:
• HFC–23 emissions from all HCFC–
22 production processes at the facility.
• HFC–23 emissions from each
destruction process.
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable. For example,
report CO2, N2O, and CH4 emissions
from each stationary combustion unit on
site by following the requirements of 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
GHG Emissions Calculation and
Monitoring. Reporters must calculate
HFC–23 emissions as follows:
• For HCFC–22 production processes
that do not use a thermal oxidizer or
that have a thermal oxidizer that is not
connected to the production equipment,
calculate annual HFC–23 emissions at
the facility level using a mass balance
equation and the following information:
annual HFC–23 generated, the annual
HFC–23 sent off site for sale, the annual
HFC–23 sent off site for destruction, the
annual increase in the HFC–23
inventory, and the annual HFC–23
destroyed on site (calculated by
multiplying the mass of HFC–23 fed to
the destruction device by the
destruction efficiency).
• For HCFC–22 production processes
with a thermal oxidizer that is
connected to the production equipment,
calculate annual HFC–23 emissions at
the facility level by summing the
following emissions:
—Annual HFC–23 emissions from
equipment leaks (calculated using
default emission factors and the
measured number of leaks in valves,
pump seals, compressor seals,
pressure relief valves, connectors, and
open-ended lines).
—Annual HFC–23 emissions from
process vents (calculated for each
vent using the HFC–23 emission rate
from the most recent emission test
and the ratio of the actual production
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rate and the production rate during
the emission test).
—Annual HFC–23 from the thermal
oxidizer (calculated by subtracting the
amount of HFC–23 destroyed by the
destruction device from the measured
mass of HFC–23 fed to the destruction
device).
• For other HFC–23 destruction
processes, calculate HFC–23 emissions
based on the mass of HFC–23 fed to the
destruction device and the destruction
efficiency.
• For the destruction efficiency,
conduct a performance test or use the
destruction efficiency determined
during a previous performance test. To
confirm the destruction efficiency,
measure the fluorinated GHG
concentration at the outlet to the
destruction device annually.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart O.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
O.
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2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart O: HCFC–22
Production and HFC–23 Destruction.’’
• The minimum required frequency
of mass flow and concentration
measurements has been decreased from
daily to weekly.
• The required frequency of
emissions tests at process vents has
been decreased to once every five years.
A test is also required after a significant
change is made to the process.
• The required annual measurements
at the outlet of the thermal oxidizer now
omit measurements of mass flow. Three
samples are required to be taken; the
average of these is compared to the
concentration at the outlet of the
oxidizer that was measured during the
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initial performance test that established
the destruction efficiency.
• A term has been added to the massbalance equation for HCFC–22
production facilities that do not have a
thermal oxidizer that is directly
connected to the HCFC–22 production
equipment. This term accounts for
increases in the inventory of stored
HFC–23 that can occur during the year.
• EPA has added an additional
method for estimating missing mass
flow data in the event that a secondary
mass measurement for that stream is not
available.
• The option for reporters to develop
their own methods for estimating
missing data if they believe that the
prescribed method will over- or underestimate the data has been removed.
• Some reporting requirements have
been added to be consistent with the
changes to the calculations and
monitoring sections and to permit
verification of emissions calculations.
EPA decreased the minimum
frequency of gas flow and concentration
measurements from daily to weekly
because EPA’s research indicates that
HFC–23 concentrations are not likely to
vary significantly over a one week
period. This change also makes the
required measurement frequency more
consistent with current industry
practice.
As noted above, EPA removed the
option for reporters to develop their
own methods for estimating missing
data if they believe that the prescribed
method will over- or underestimate the
data. EPA removed this option for two
reasons. First, the proposed provision
lacked clear guidance on when
alternative methods should be used
(e.g., on the size of an underestimate
that would justify use of an alternative
method) and on how they should be
developed. Second, the proposed
provision was redundant with the new
provision that permits reporters to
estimate missing data using a related
parameter and the historical
relationship between the related
parameter and the missing parameter.
This new option provides reporters with
flexibility in substituting for missing
data in the event that a secondary mass
measurement is not available, but sets
out general guidance on how to select
the substitute data.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
number of comments on HCFC–22
production and HFC–23 destruction
were received covering numerous
topics. Responses to significant
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comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart O: HCFC–22
Production and HFC–23 Destruction.’’
Monitoring and QA/QC Requirements
Comment: EPA received a comment
that the requirement to annually
conduct emissions tests at process vents
is overly burdensome and unnecessary
because it is unlikely that the emissions
rate would deviate from an initial
process vent test unless there were a
significant change in the process. This
commenter argued that testing should
be required at least every five years or
after a significant change in the process.
Response: In response to this
comment, EPA has reduced the required
frequency of emissions tests at process
vents to once every five years, or after
a significant change to the process. EPA
has also clarified that the requirement
applies only to HCFC–22 production
facilities that use a thermal oxidizer
connected to the HCFC–22 production
equipment. These are the only facilities
that use process vent emission estimates
in their calculation of facility-wide
HFC–23 emissions.
EPA is decreasing the frequency of
emissions tests at process vents for two
reasons. First, EPA agrees with the
commenter that, in the absence of a
significant process change, the process
vent emission rate is not likely to vary
much (in percentage terms) from year to
year. Second, although small variations
in the emission rate could still lead to
significant absolute errors for facilities
with large process vent emissions, the
facilities that are required to test their
process vent emissions are likely to
have small process vent emissions
(because they use thermal oxidizers
connected to the production
equipment). (Facilities that do not use
thermal oxidizers connected to the
equipment would be expected to have
larger process vent emissions, but they
are required to use a mass-balance
approach to calculate emissions rather
than summing emissions across process
vents, equipment leaks, and thermal
oxidizers.) Together, these
considerations lead to the conclusion
that testing process vent emissions
every five years should sufficiently
minimize errors in the overall HFC–23
emission calculations of the facilities
affected by the testing requirement.
Comment: EPA should add a term to
Equation O–4 (the mass-balance
equation for HCFC–22 production
facilities that do not have a thermal
oxidizer that is directly connected to the
HCFC–22 production equipment) to
account for increases in the inventory of
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stored HFC–23 that can occur during the
year.
Response: EPA added a term to
Equation O–4 for increases in the
inventory of stored HFC–23. EPA agrees
that the equation should account for
changes in the inventory of HFC–23 that
is stored on site. It is important to track
all reservoirs of HFC–23 at the facility;
mass-balance approaches used to track
emissions from other sources (e.g., from
electrical equipment) frequently include
terms to account for the increase in
inventory.
Definition of Source Category
Comment: EPA received a comment
that the measurement of HFC–23
emissions from HCFC–22 production
should be moved to Subpart L, which
covers the reporting of fluorinated GHG
production.
Response: EPA proposed provisions
for facilities producing fluorinated gases
in three separate subparts: 40 CFR part
98, Subpart L, Subpart O, and Subpart
OO. Although there are many
similarities across the chemicals and
processes covered by the three subparts,
the subparts were deliberately tailored
to different sources and types of
emissions. Subpart L was intended to
address emissions of fluorinated GHGs
from fluorinated GHG production. 40
CFR part 98, subpart O was intended to
address HFC–23 generation and
emissions from HCFC–22 production.
40 CFR part 98, subpart OO was
intended to address flows affecting the
U.S. industrial gas supply, including
production, transformation, and
destruction.
EPA determined that 40 CFR part 98,
subpart O was necessary because
HCFC–22 production and HFC–23
destruction facilities differ from other
fluorinated gas production facilities in
two key respects. First, the primary
fluorinated GHG that they generate
(HFC–23) is made as a byproduct to the
production of a substance that is not
defined as a fluorinated GHG (HCFC–
22). Second, due to the very high GWP
of HFC–23, each HCFC–22 facility
generates very large quantities of CO2equivalent. For the second reason, EPA
has worked with HCFC–22 producers
for over ten years to understand and
reduce HFC–23 emissions. The
requirements for HCFC–22 producers
are therefore based on a close
knowledge of their production processes
and methods for accounting for
emissions. These methods are also
comprehensive (e.g., accounting for
emissions from equipment leaks and
losses during transport of HFC–23 that
is shipped off-site for destruction).
These requirements may not be
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appropriate for other fluorinated gas
producers, and, at the same time, the
requirements for fluorinated gas
producers may not be appropriate for
HCFC–22 producers.
P. Hydrogen Production
1. Summary of the Final Rule
Source Category Definition. The
merchant hydrogen production source
consists of process units that produce
hydrogen by reforming, gasification, or
other transformation of feedstock and
transfer the hydrogen produced off site.
Hydrogen production facilities located
at petroleum refineries or other large
facilities are included in this source
category only if they are not owned by
or under the direct control of the
refinery owner. Otherwise, they are
considered to be a captive hydrogen
production source that reports
emissions under the subpart applicable
to the larger facility, e.g., 40 CFR part
98, subpart Y (Petroleum Refineries).
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For hydrogen
production, report the following
emissions:
• CO2 process emissions from
hydrogen production.
• CO2, N2O, and CH4 emissions from
each stationary combustion unit on site
by following the requirements of 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources).
• CO2 collected and transferred off
site under 40 CFR part 98, subpart PP
(Suppliers of Carbon Dioxide).
• In addition, report GHG emissions
for other source categories for which
calculation methods are provided in the
rule, as applicable.
GHG Emissions Calculation and
Monitoring.
• To calculate and report process CO2
emissions from hydrogen production,
most reporters can elect to either (1)
install and operate CEMS and follow the
Tier 4 methodology (in 40 CFR part 98,
subpart C) or (2) calculate process CO2
emissions using equations in the 40 CFR
part 98, subpart P and the following
data:
—Measurements of monthly feedstocks
and fuel consumed.
—Carbon content of the feedstock
measured monthly.
—Molecular weight of the feedstock
(gaseous fuels only).
• However, if process CO2 emissions
from hydrogen production are vented
through the same stack as a combustion
unit or process equipment that uses a
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CEMS to follow Tier 4 methodology to
report CO2 emissions, then the CEMS
must be used to measure and report
combined CO2 emissions from that stack
instead of the calculation procedure
described in approach 2 above.
Monitoring and QA/QC Requirements.
The methods for the initial calibration
and annual recalibration of flow meters
are defined in a prescriptive list of
industry standard test methods
incorporated by reference in the Tier 3
method in 40 CFR part 98, subpart C,
while the methods for determining
carbon content of fuels and feedstocks
are defined in a prescriptive list of an
assortment of industry standard test
methods incorporated by reference.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart P.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
P.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart P: Hydrogen
Prodution.’’
• 40 CFR 98.160 was reworded to
clarify the definition of reporting entity.
• 40 CFR 98.162 was revised to allow
reporting of combined process and
combustion CO2, CH4, and N2O
emissions.
• In 40 CFR 98.163(b), ‘‘feedstock’’
was changed to ‘‘fuel and feedstock’’.
• 40 CFR 98.164 was restructured to
clarify between CEMS measurements
and QA/QC and feedstock method
measurements and QA/QC.
• 40 CFR 98.164 was reworded to
allow the characterization of feedstocks
to be conducted by either the consumer
or the supplier, to allow standard
gaseous hydrocarbon fuels of commerce
to be characterized annually, and to
allow liquid and solid hydrocarbon
fuels of commerce to be characterized
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upon delivery if delivered by bulk
transport.
• The recalibration requirements in
40 CFR 98.164 were changed to reduce
economic impact.
• The list of standards incorporated
by reference in 40 CFR 98.164 was
broadened.
• The missing data procedures in
40 CFR 98.165 were revised to be
consistent with 40 CFR 98.35(b).
• 40 CFR 98.166 and 98.167 were
restructured to distinguish between
CEMS recordkeeping and feedstock
method recordkeeping.
• 40 CFR 98.166 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.167 to 40 CFR 98.166, and some data
elements that a reporter must already
use to calculate GHGs as specified in
40 CFR 98.163 were added to 40 CFR
98.166 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on hydrogen
production were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart P: Hydrogen
Production.’’
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Definition of Source Category
Comment: Multiple commenters
pointed out the lack of clarity regarding
the definition of the reporting entity,
and suggested defining the entity
holding the air permit for an affected
facility as the reporting entity. For
example, ‘‘If the owner/operator of the
facility is the holder of the air permit for
an affected facility, then the operator
should be responsible for reporting GHG
emissions. If not, then EPA should
clarify the responsibility for reporting.’’
Response: EPA reviewed this complex
issue. First, a facility is defined in 40
CFR 98.6: ‘‘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.’’ Therefore, any hydrogen
production process unit that is not part
of a larger facility covered by another
subpart of this rule is a merchant
hydrogen production facility which
reports emissions under 40 CFR part 98,
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subpart P. On the other hand, a
hydrogen production process unit that
is part of a larger facility covered by
another subpart of this rule is a captive
hydrogen production facility that does
not report emissions under 40 CFR part
98, subpart P. Their emissions,
including those emissions from the
captive hydrogen production facility,
are reported under the subpart
applicable to the larger facility. Second,
in answer to the question, ‘‘Do I need to
report?’’, 40 CFR 98.2 states that the rule
applies to a facility that contains any
source category listed in 40 CFR
98.2(a)(2) (which includes hydrogen
production) and that emits 25,000
metric tons CO2e or more per year in
combined emissions from stationary
fuel combustion units, miscellaneous
uses of carbonates, and all source
categories listed in 40 CFR 98.2(a)(2).
EPA has concluded that the rule
explains this clearly in 40 CFR 98.2 and
98.6, and that it is not necessary to
change the rule. To add clarity,
however, EPA has revised 40 CFR
98.160(c) as follows: ‘‘This source
category includes merchant hydrogen
production facilities located within a
petroleum refinery if they are not owned
by, or under the direct control of, the
refinery owner and operator.’’
GHGs To Report
Comment: Multiple commenters
requested clarification on the CO2
emission reporting obligation as
combined ‘‘process’’ and ‘‘combustion’’
CO2 emissions, regardless of the
calculation method employed. If
separate, discrete reporting of such
emissions is actually required,
commenters asked EPA to provide
explicit protection for this information
which they stated was very critical CBI.
Response: In response to these
multiple commenters, EPA has clarified
the rule in 40 CFR 98.162 to provide
operators the option of providing
combined process and combustion CO2
emissions for each hydrogen production
process unit whether or not it meets the
conditions in 40 CFR 98.33(b)(4)(ii) and
(iii) for CEMs. Under 40 CFR 98.166,
facilities must report additional
parameters for emissions verification.
See Sections II.I and II.N of this
preamble for responses to the comments
received on the general content of the
annual GHG report and the emissions
verification approach, respectively. EPA
reviewed CBI comments received across
the rule (both general and subpartspecific comments) and our response is
discussed in Section II.R of this
preamble and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
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Response to Public Comments, Legal
Issues.’’
Method for Calculating GHG Emissions
Comment: Multiple commenters
pointed out the need for a calculation
method to account for feedstock carbon
that does not exit the hydrogen
production facility as CO2, but rather in
the form of other products or coproducts that contain carbon (such as
synthesis gas, CO, CH4). Many argued in
favor of correcting equations P–1, P–2
and P–3 to account for feedstock carbon
that does not exit the hydrogen
production facility as CO2, but rather as
products (such as synthesis gas, CO,
CH4) that are manufactured which
contain carbon.
Response: EPA generally concurs with
the need to account for ‘‘carbon other
than CO2’’ that exits the facility. EPA
considered several options for reporting
such carbon and chose to have facilities
report CO2 and ‘‘carbon other than CO2’’
as separate data reporting elements in
40 CFR 98.166 rather than including
this carbon in equations P–1, P–2, and
P–3. As a result, EPA has added data
reporting elements under 40 CFR 98.166
for (1) quarterly quantity of CO2
collected and transferred off site in
either gas, liquid, or solid forms (metric
tons), following the requirements of 40
CFR part 98, subpart PP of this part, and
(2) annual quantity of carbon other than
CO2 collected and transferred off site in
either gas, liquid, or solid forms (metric
tons).
Monitoring and QA/QC Requirements
Comment: Multiple commenters
recommended that EPA should allow
the characterization of feedstocks
(sampling and analysis) to be conducted
by either the feedstock consumer (the
regulated source) or the feedstock
supplier. They state that the
characterization of standard fuels of
commerce used as hydrogen production
feedstocks, such as natural gas, should
not be required since default values will
yield a sufficiently accurate emission
estimate. Commenters recommend that
characterization of such standard fuels
of commerce used as feedstocks be
optional, at the source’s discretion.
Response: EPA concurs with this
comment, since feedstock suppliers
regularly monitor the carbon content of
their fuels and also, the carbon content
of standard fuels of commerce are quite
consistent month to month. EPA has
revised this section to allow the
characterization of feedstocks to be
conducted by either the consumer or the
supplier, to allow standard gaseous
hydrocarbon fuels of commerce to be
characterized annually, and allow liquid
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and solid hydrocarbon fuels of
commerce to be characterized upon
delivery if delivered by bulk transport
(e.g., by truck or rail). Other nonstandard gaseous fuels and feedstocks
must still be subjected to weekly
sampling and analysis to determine the
carbon content and molecular weight.
Comment: Commenters recommended
that EPA limit the requirement for
sampling non-gaseous fuels to new
deliveries rather than monthly in order
to pinpoint the onset of fuel parameter
variations.
Response: EPA concurs that the
carbon content of a liquid or solid
hydrocarbon fuel delivered in bulk will
remain constant as the stock on hand
from the delivery is consumed, and
therefore periodic testing during the
interim is not needed. EPA has revised
this section to allow the characterization
of feedstocks to be conducted by either
the consumer or the supplier, to allow
standard gaseous hydrocarbon fuels of
commerce to be characterized annually,
and allow liquid and solid hydrocarbon
fuels of commerce to be characterized
upon delivery if delivered by bulk
transport (e.g., by truck or rail). On the
other hand, other non-standard gaseous
fuels and feedstocks must still be
subjected to weekly sampling and
analysis to determine the carbon content
and molecular weight since their carbon
content can vary significantly from
week to week.
Comment: Multiple commenters
recommended that EPA should include
provisions for an extension of the
required meter/monitor calibration
deadline (as well as the initial
calibration, if appropriate) when the
calibration would require removing the
process line from service. They
recommend that the calibration
requirement be extended to the next
scheduled maintenance shutdown for
the impacted unit/process.
Response: EPA concurs that requiring
the facility to remove the process line
from service represents an undue
hardship and has therefore revised 40
CFR part 98, subpart P to refer to the
less stringent monitoring and QA/QC
requirements for the Tier 3 methodology
included in 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
Comment: One commenter suggested
adding ISO 5167–1 through ISO 5167–
4 (Measurement of Fluid Flow by Means
of Pressure Differential Devices) to list
of standards incorporated by reference.
Response: EPA agrees ISO 5167–1
through ISO 5167–4 are suitable
calibration standards and would be
good additions to the list of standards.
However, given that the issues covered
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by these standards (Venturi and orifice
plate differential pressure flow meters)
are covered by two American Society of
Mechanical Engineers (ASME)
standards, one ASHRAE standard, and
one AGA report which are already
included in 40 CFR 98.164, EPA has not
explicitly added these references to the
list of standards incorporated by
reference.
Procedures for Missing Data
Comment: Multiple commenters
recommended that the data substitution
method for missing feedstock supply
rate data should be changed to be
consistent with 40 CFR 98.35(b)(2),
allowing use of the ‘‘best available
estimate’’, and that the data substitution
method for missing feedstock carbon
content data should be changed to be
consistent with 40 CFR 98.35(b)(1),
allowing use of the average before/after
values.
Response: EPA concurs that the
required level of accuracy for hydrogen
production is similar to that required for
stationary combustion, and that the less
stringent ‘‘best available estimate’’
approach is appropriate for hydrogen
production. Therefore, EPA has changed
40 CFR 98.165 to follow the data
substitution method for missing fuel
carbon content data prescribed in 40
CFR 98.35 and the data substitution
method for missing fuel usage data
prescribed in 40 CFR 98.35.
Data Reporting Requirements
Comment: Multiple commenters
stated that annual feedstock
consumption, annual hydrogen
production, and feedstock carbon
content are confidential business
information (CBI) and should not be
reported. The commenters asked that
this information be maintained by the
facility and be made available to the
Agency upon request. One commenter
further stated that if data must be
reported, the reporting rules must
provide explicit protection for this very
critical confidential business
information.
Response: Feedstock consumption
and feedstock carbon content are
parameters used to calculate emissions.
Since annual CO2 emissions are
calculated from the sum of the products
of monthly feedstock consumption
multiplied by the monthly average
carbon content of the feedstock, all of
these parameters are required for
emissions data verification purposes.
Annual hydrogen production is an
additional parameter which is necessary
for EPA to effectively verify emissions,
since the ratio of carbon emissions to
hydrogen production is relatively
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consistent for each hydrogen production
facility. See Section II.N of this
preamble for information on emissions
verification. EPA reviewed CBI
comments received across the rule (both
general and subpart-specific comments)
and our response is discussed in Section
II.R of this preamble and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’
Q. Iron and Steel Production
1. Summary of the Final Rule
Source Category Definition. The iron
and steel production source category
consists of facilities with any of the
following processes:
• Taconite iron ore processing.
• Integrated iron and steel
manufacturing.
• Cokemaking not co-located with an
integrated iron and steel manufacturing
process.
• EAF steelmaking not co-located
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.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Report the following
emissions annually:
• CO2, CH4, and N2O emissions from
fuel combustion at each stationary
combustion unit according to the
requirements in 40 CFR part 98, subpart
C (General Stationary Fuel Combustion
Sources). Stationary combustion units
include, but are not limited to,
byproduct recovery coke oven battery
combustion stacks, blast furnace stoves,
boilers, process heaters, reheat furnaces,
annealing furnaces, flame suppression,
ladle reheaters, and any other
miscellaneous combustion sources
(except flares).
• CO2 emissions from flares according
to the requirements in 40 CFR part 98,
subpart Y (Petroleum Refineries) and
CH4 and N2O emissions from flares
using the default emission factors for
coke oven gas and blast furnace gas.
• CO2 process emissions from each
taconite indurating furnace, basic
oxygen furnace, nonrecovery coke oven
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battery combustion stack, coke pushing
process, sinter process, EAF, argonoxygen decarburization vessel, and
direct reduction furnace.
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. For CO2 process emissions
at each taconite indurating furnace,
basic oxygen furnace, nonrecovery coke
oven battery, sinter process, EAF, argonoxygen decarburization vessel, and
direct reduction furnace, reporters must
calculate emissions using one of the
following methods, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions by
either: (1) Installing and operating a
CEMS and following the Tier 4
methodology (in 40 CFR part 98, subpart
C) or (2) using one of the following two
calculation procedures:
—Use a carbon balance method
described in 40 CFR part 98, subpart
Q to calculate the annual mass
emissions rate of CO2 for each
process, based on the annual mass of
inputs and outputs and an annual
analysis of the respective weight
fraction of carbon in each process
input or output that contains carbon.
Use separate procedures and
equations for taconite indurating
furnaces, basic oxygen process
furnaces, nonrecovery coke oven
batteries, sinter processes, EAFs,
argon-oxygen decarburization vessels,
and direct reduction furnaces, or
—Use a site-specific emission factor
determined from a performance test
that measures CO2 emissions from all
exhaust stacks and also measures
either the feed rate of materials into
the process or the production rate
during the test for taconite indurating
furnaces, basic oxygen process
furnaces, nonrecovery coke oven
batteries, sinter processes, EAFs,
argon-oxygen decarburization vessels,
and direct reduction furnaces.
• However, if process CO2 emissions
from a taconite indurating furnace, basic
oxygen furnace, nonrecovery coke oven
battery, sinter process, EAF, argonoxygen decarburization vessel, and
direct reduction furnace are emitted
through the same stack as CO2
emissions from a combustion unit or
process equipment that uses a CEMS
and follows the Tier 4 methodology to
report CO2 emissions, then the CEMS
must be used to measure and report
combined CO2 emissions from that
stack. In such cases, the reporter cannot
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use the other process CO2 calculation
approaches outlined above.
• For coke oven pushing, facilities
must use a CO2 emission factor
provided in the rule.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart Q.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
Q.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart Q: Iron and
Steel Production.’’
The major changes made since
proposal include:
• The carbon mass balance method
was revised to require an annual
analysis of all process inputs and
outputs for carbon content rather than
weekly sampling and monthly analysis.
• The site-specific emission factor
method was revised to: (1) Require
testing based on representative
performance rather than at 90 percent of
capacity, (2) sampling for a minimum of
three hours or production cycles rather
than nine, (3) conducting separate tests
for each different process condition that
is a part of normal operation if the
change in CO2 emissions at the different
conditions is more than 20 percent, and
(4) adding a provision to clarify testing
requirements when the EAF and argonoxygen decarburization vessel are
ducted to the same control device and
stack.
• To improve the emissions
verification process, 40 CFR 98.176 was
reorganized and updated. Some data
elements were moved from 40 CFR
98.177 to 40 CFR 98.176, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.173 were added to 40 CFR
98.176 for clarity.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses
related to the requirements for iron and
steel processes. A large number of
comments on iron and steel production
were received covering numerous
topics. Many of these comments were
directed at the requirements for 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources), and
responses to those comments are
provided in Section III.C of this
preamble. Also see the Section II.N of
this preamble for the response to
comments on the emissions verification
approach. Responses to other significant
comments received related to process
emissions from iron and steel
production can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
Q: Iron and Steel Production.’’
Method for Calculating GHG Emissions
Comment: Several industry
representatives and their three trade
associations requested that EPA allow
the use of a simplified facility-wide
carbon balance approach developed by
the American Iron and Steel Institute
(AISI) to calculate CO2 emissions from
iron and steel production facilities.
According to the commenters, the AISI
methodology has recently been adapted
to facility-wide reporting and is
emerging as the preferred reporting
protocol internationally. The
commenters described the approach as
based on determining the mass of
carbon in the most significant carboncontaining inputs entering the plant and
in the most significant carboncontaining outputs that leave as
products or byproducts (excluding, for
example, iron ore, scrap, steel). The
difference between the mass of carbon
entering the facility and leaving the
facility is assumed to be converted to
CO2. The annual mass rates of
significant inputs and outputs are
determined from company records, and
their carbon contents are based on
typical or default values. The
commenters noted that the AISI
approach provides a single estimate of
the combined total CO2 emissions from
all processes and combustion sources at
the facility. The commenters claimed
that the approach would provide a more
accurate and complete accounting of
facility-wide emissions at a much lower
cost than that of the proposed EPA
process-specific methods.
Response: As we explained at
proposal (74 FR 16517), we considered
the many domestic and international
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monitoring guidelines and protocols for
process and combustion sources at iron
and steel production facilities,
including the AISI facility-wide
approach. The vast majority of these
guidelines and protocols are processspecific rather than facility-wide
approaches (e.g., 2006 IPCC Guidelines,
U.S. Inventory, the World Business
Council for Sustainable Development
(WBCSD)/WRI GHG protocol, DOE
1605(b), TCR, European Union
Emissions Trading System, and
Environment Canada’s mandatory
reporting guidelines). In addition, the
‘‘higher tier’’ (more accurate) sitespecific methods use process-specific
approaches. We explained at proposal
(74 FR 16517) that we did not choose to
propose these approaches based on the
use of default values in general (such as
the AISI approach) because the use of
default values and lack of direct
measurements results in a very high
level of uncertainty (greater than ±25
percent), and default approaches would
not provide site-specific estimates of
emissions that reflect differences in
feedstocks, operating conditions, fuel
combustion efficiency, variability in
fuels, and other differences among
facilities.
We also stated at proposal that we
decided not to finalize the proposal
using 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,
such default approaches are inherently
inaccurate for site-specific
determinations, and 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 further note here that the AISI
approach is not adequate for our
reporting needs because it provides only
a single emissions number aggregated
from the numerous individual processes
and combustion units at the iron and
steel facility. In contrast, the approaches
we are promulgating today for
determining CO2 emissions provide
information at the process level and
distinguish between combustion
emissions and process emissions.
Information at the process level is
needed for many reasons, such as
verification of the reported emissions
from comparison with known ranges
expected from various types of
processes for a given production rate
and emissions verification based on data
for different plants for similar processes.
Process-level reporting also provides
information that will be useful in
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identifying processes that have reduced
emissions over time and processes at
specific plants that have the most
potential for future reductions in
emissions. In addition, the process-level
reporting may provide information that
can be used to improve methodologies
for specific processes under future
programs and to identify processes that
may use a technology that could be the
basis for an emission standard at a later
time.
We developed estimates of costs for
the proposed options for determining
CO2 emissions and concluded that the
costs were reasonable. However, as
explained below, we have revised the
proposed options in response to
comments, and these revisions
significantly reduce the burden and
costs of the carbon mass balance and
site-specific emission factor methods
while maintaining a similar level of
accuracy.
Comment: Several commenters
claimed that the proposed carbon mass
balance method is unnecessarily
burdensome because it requires weekly
sampling, monthly analyses, and
determining the monthly mass
quantities of all process inputs and
outputs. The commenters suggested that
EPA allow the use of default values for
carbon content, neglect streams that
have very little or no carbon, drop the
requirement for analysis by an
‘‘independent certified laboratory,’’ and
allow the use of analyses from
suppliers. One commenter
recommended sampling and analysis for
carbon content no more frequently than
annually. The commenters stated that
lime, dolomite and slag contain no
appreciable carbon and do not need to
be tracked, and that it is not necessary
to account for the carbon in scrap that
is charged to the furnace or in the steel
product because they offset each other.
One commenter noted that
‘‘independent certified laboratory’’ is
not defined or explained, and another
claimed that it is an unnecessary
complication and expense because these
carbon analyses are typically done in an
in-house laboratory.
One commenter stated that the carbon
mass balance equations were
incomplete because they did not
account for carbon removed by
pollution control devices. Another
commenter recommended that EPA use
default carbon contents for different
grades of steel scrap and noted that
because companies already track the
chemical content of each grade of scrap,
highly accurate carbon calculations
could be made with minimal additional
burden.
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Response: We received several useful
suggestions for improving the carbon
mass balance method without
significantly decreasing the accuracy in
the estimates. After a close review of the
sampling and analysis requirements and
comparing them to the requirements
applied to other source categories in
other subparts of this reporting rule, we
concluded that the weekly sampling and
monthly analysis of carbon content
could be reduced in frequency to an
annual analysis of all inputs and
outputs at each facility. We also revised
the rule to allow the use of carbon
content analyses from the material
supplier, which is consistent with what
is required in other subparts using the
carbon balance method. Carbon content
does not vary widely at a given facility
for the significant process inputs and
outputs that contain carbon, and we
continue to account for variations due to
changes in production rate, which is
likely a more significant source of
variability. We continue to choose not to
use default values for the reasons given
in the previous comment response, and
we have determined that an annual
analysis of carbon content to provide
plant-specific values is not burdensome
because facilities already perform many
such analyses. We agree that the
analysis does not have to be performed
by an independent certified laboratory,
especially since we specify the
analytical procedures that must be used
by any laboratory, and we note that inhouse laboratories may have more
applicable experience in analyses of
their particular process inputs and
outputs.
We agree with the suggestion to
evaluate carbon content by the grade or
type of ferrous material charged to the
furnace, and we incorporated a
provision to calculate an average carbon
content of ferrous materials charged
based on the average weight percent of
each type that is used. In addition, we
have corrected the equations as
suggested to account for carbon in the
residue collected by emission control
equipment. Finally, we agree that inputs
and outputs that contain no carbon or
an insignificant amount (i.e.,
contributing to less than one percent of
the carbon in or out) do not need to be
tracked in the carbon balance method.
Comment: Several commenters
claimed that the site-specific emission
factor method is not a viable option as
proposed and should be streamlined to:
(1) Eliminate annual re-testing, (2)
reduce the test length from nine hours
(or from nine production cycles for
batch processes), (3) clarify that a
separate test is not required for each
grade of steel, and (4) remove the
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requirement to operate at 90 percent of
capacity. One commenter stated that the
most frequent re-testing currently
required in operating permits is once
every 2.5 years rather than annually.
Another commenter noted that nine
production cycles for certain small
specialty steel producers would require
27 hours of testing for each grade of
steel because each production cycle is
three hours. Commenters stated that
testing at 90 percent of production is
problematic and is beyond their control
because it is dictated by upstream and
downstream production levels as well
as economic conditions. In addition,
capacity is difficult to determine
because steelmaking furnaces do not
have a nameplate capacity since it is
determined by the iron production rate,
how fast downstream processes (such as
the caster) operate, process inputs, and
product specifications that may require
different operating cycle times.
One commenter questioned the value
of the requirement to re-test if the
carbon content of feed materials changes
by more than 10 percent because this
type of change could occur on a daily
or weekly basis when the grade of steel
being produced changes. Another
commenter noted that EPA did not
define what constituted a significant
change in fuel type or mix and
recommended that the provision be
changed to 20 percent to allow for
environmentally beneficial process
improvements. Two commenters stated
that the 10 percent threshold for retesting is infeasible for steelmaking and
sinter processes because of routine
changes in the type of steel produced
and the types of materials recycled to
the sinter plant. The commenters
requested that they be permitted to
develop separate emission factors based
on various modes that represent
different operating scenarios or product
categories. The commenters also
recommended that EPA eliminate the 10
percent change threshold for re-testing
and require that testing be conducted
under conditions that are representative
of normal operation. One commenter
noted that the rule did not address how
a site-specific emission factor would be
developed when emissions from the
EAF and argon-oxygen decarburization
vessel are combined and routed to a
single emission control device and
stack.
Response: We further reviewed the
testing requirement in other rules and
those in operating permits and found
that typical requirements (such as test
requirements for particulate matter)
include 3 one-hour runs or production
cycles for representative testing of
process emissions. Consequently, we are
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revising the testing requirements to
three hours or three production cycles.
We also agree with the commenters who
noted that different routine operating
modes may result in different levels of
CO2 emissions, and it is necessary to
develop separate emission factors for
these different operating conditions.
Consequently, we have dropped the 10
percent re-testing threshold and instead
require that separate emission factors be
developed for each of different routine
operating conditions that result in a
change in CO2 emissions by 20 percent
or more.
We disagree that annual re-testing is
excessive because testing for CO2
emissions is much simpler and less
costly than sampling for hazardous
pollutants or for particulate matter, and
annual sampling is consistent with our
requirement for annual reporting. We
agree that it is not necessary or always
possible to test while operating at 90
percent of capacity for the reasons
identified by the commenters. Instead,
we are requiring that the test be
performed based on representative
performance, i.e., under normal
operating conditions. We have revised
the rule to clarify and provide options
for testing when emissions from the
EAF and argon-oxygen decarburization
vessel are combined.
Comment: Several commenters asked
EPA to clarify that CH4 and N2O
emissions do not have to be reported for
iron and steel production processes, and
other commenters requested that CH4
and N2O emissions reporting not be
required for the combustion of coke
oven gas and blast furnace gas.
Commenters noted that default emission
factors for CO2, CH4, and N2O were not
provided in the tables in 40 CFR part 98,
subpart C, and in the absence of such
emission factors, asked if they would be
required to test for these minor
emissions.
Response: We have clarified that 40
CFR part 98, subpart Q does not require
reporting of CH4 and N2O emissions
from the iron and steel production
processes because we expect these
emissions (if any) to be very low, and
we have no protocols for calculating
them. However, emission factors are
available in the 2006 IPCC guidelines
for combustion sources, including the
combustion of coke oven gas and blast
furnace gas. We have added the IPCC
default emission factors for CO2 and
N2O for these process gases to the tables
in 40 CFR part 98, subpart C, and we
developed new emission factors for CH4
based on the typical CH4 content of coke
oven gas (28 percent) and blast furnace
gas (0.2 percent).
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R. Lead Production
1. Summary of the Final Rule
Source Category Definition. 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 (smelting).
A secondary lead smelter is a facility at
which lead-bearing scrap materials
(including but not limited to lead-acid
batteries) are recycled by smelting into
elemental lead or lead alloys.
Reporters must submit annual GHG
reports for primary lead smelters and
secondary lead smelters that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For lead production,
report the following emissions:
• CO2 process emissions from each
smelting furnace used for lead
production.
• CO2 combustion emissions from
each smelting furnace used for lead
production.
• N2O and CH4 emissions from each
smelting furnace under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources) using the
methodologies in subpart C.
• CO2, N2O, and CH4 emissions from
each on-site stationary combustion unit
other than smelting furnaces under 40
CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. To calculate annual process
CO2 emissions from an affected smelting
furnace, the reporter must use the
following methods, as applicable to the
affected smelting furnace.
• For each affected smelting furnace
with certain types of CEMS in place, the
reporter must use the CEMS and follow
the Tier 4 methodology (in 40 CFR part
98, subpart C) to measure and report
under the Lead Production subpart (40
CFR part 98, subpart R) combined
process and combustion CO2 emissions.
• For other affected smelting
furnaces, the reporter can elect to either
(1) install and operate a CEMS and
follow the Tier 4 methodology to
measure and report combined process
and combustion CO2 emissions or (2)
calculate annual process CO2 emissions
using a carbon mass balance procedure
specified in 40 CFR part 98, subpart R.
If using approach (2):
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—Calculate emissions once per year
using recorded monthly production
data and the average carbon content
for each smelting furnace input
material determined by either using
material supplier information or by
annual analysis of representative
samples of the material.
—Report process CO2 emissions from
each smelting furnace under 40 CFR
part 98, subpart H (Cement
Production), and report combustion
CO2 emissions from each kiln under
40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart R.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
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2. Summary of Major Changes Since
Proposal
The major changes to the rule since
proposal for lead production facilities
were revisions to the carbon mass
balance calculation procedure used by
reporters for calculating process CO2
emissions from affected smelting
furnaces. The rationale for these and
any other significant changes can be
found below or in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
R: Lead Production.’’
• The frequency of performing the
carbon mass balance calculations was
revised to be required on an annual
basis instead of the proposed monthly
basis.
• The frequency of material carbon
content sampling and analysis of each
smelting furnace input material used for
the carbon mass balance was revised to
be performed by annual analysis of
representative samples of the material
instead of the proposed monthly basis.
• A de minimis carbon content level
was added to exclude the need to
account for carbon-containing materials
contributing less than one percent of the
total carbon into the smelting furnace in
the carbon mass balance calculations.
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• Data reporting procedures (40 CFR
98.186) were reorganized and updated
to consolidate and clarify the emissions
verification process. Some data
elements for the carbon mass balance
calculation were moved from 40 CFR
98.187 to 40 CFR 98.186, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.183 were added to 40 CFR
98.186 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses
specific to the lead production source
category. Comments were received from
one commenter regarding several topics.
Responses to significant comments
received are presented in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
R: Lead Production.’’
Selection of Threshold
Comment: The commenter stated that
Lead Production is not a source of
significant GHG emissions and that EPA
cannot assert that the Lead Production
sector is a significant part of the
stationary source combustion sector.
The commenter notes that based on
EPA’s estimates in the TSDs for the
proposal, estimated emissions from the
Lead Production sector are 0.02 percent
of the total estimated nationwide
emissions from stationary fossil fuel
combustion. Moreover, they argue that
the combustion-related emissions from
lead production are overstated by
incorrect assumptions in the TSD. The
commenter states that given Lead
Production’s relative contribution, it is
not a significant source of emissions and
should be eliminated from further
consideration. The commenter further
states that Lead Production is the only
category evaluated where raising the
threshold to the 100,000 ton level would
results in zero facilities being covered.
Accordingly, when the analysis shows
that all facilities in a particular source
category are not covered at the 100,000
ton threshold level, no insignificant
GHG emitters in the category should be
required to report under the Proposed
Rule. The commenter noted that using
the 100,000 threshold would not
significantly reduce the coverage of
emissions of EPA’s rule, as the majority
of sources identified would still have
well over 90 percent of emissions from
that source category covered under the
100,000 threshold. EPA provides no
justification for imposing substantially
more costs on industry for limited
estimated benefits and small likelihood
for regulation under the CAA. For these
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reasons, the Lead Production sector
should be eliminated as a source
category, and EPA should raise the
threshold to 100,000 for non-source
category facilities.
Response: We acknowledge this
comment and concerns; however, the
final rule retains the applicability
requirement for this source category. We
used information available to us for
estimating GHG emissions from this
industry which involved several
assumptions related to the emission
factors in the IPCC Guidance and other
sources. As noted by the commenter,
many of the underlying assumptions
were based on an international
perspective as opposed to the primary
and secondary lead production industry
in the U.S. The final rule contains a
threshold of 25,000 metric tons CO2e
and only lead production facilities with
emissions that equal or exceed 25,000
metric tons CO2e will have to report
emissions. In addition, the final rule
now contains provisions allowing a
reporter to cease reporting if the annual
reports for a given facility demonstrate
emissions less than specified levels for
multiple years. These provisions apply
to all reporting facilities, including
those with lead production processes.
See Section II.H of this preamble for the
response on provisions to cease
reporting.
We have further simplified the
reporting requirement to further reduce
burden for lead and similar industries
by requiring annual as opposed to
monthly sampling of carbon inputs. The
purpose of this rule is to collect
information on emissions sources for
future policy development. Requiring
reporting for these sources will provide
EPA with valuable data to better
characterize them and provide a more
credible position if EPA elects to
exclude these sources from future GHG
policy analyses. Additionally, while
some of these sources are currently
believed to be small compared to the
larger sources, they are not necessarily
insignificant. The inclusion of reporting
data for these sources is critical to
support analysis of future policy
decisions for lead production facilities.
When evaluating potential thresholds
for reporting GHG emissions, we
considered several thresholds between
1,000 and 100,000 metric tons CO2e. We
selected the 25,000 metric tons CO2e
threshold for reporting GHG emissions
in order to achieve a balance between
quantifying the majority of the
emissions, while minimizing the
number of facilities impacted. For
example, at a 1,000 metric tons CO2e
threshold, 99 percent of emissions
would be covered, with about 63
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percent of facilities being required to
report. The 100,000 metric tons CO2e
threshold captures no emissions or
facilities while the proposed 25,000
metric tons CO2e threshold achieves
reporting of 92 percent of the GHG
emissions while requiring less than 50
percent of the facilities to report. We
consider this a significant coverage of
the emissions, while impacting a
relatively small portion of the industry.
We believe the proposed threshold of
25,000 metric tons CO2e represents the
best option for ensuring that the
majority of emissions are reported
without imposing an unreasonable
burden on the industry. See also Section
II.E of this preamble and ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments,
Selection of Reporting Thresholds,
Greenhouse Gases, and De Minimis
Provisions.’’
Method for Calculating GHG Emissions
Comment: The commenter made
several comments regarding the
proposed procedures used to calculate
process CO2 emissions from smelting
furnaces at secondary lead smelters.
First, use of default emission factors
should be allowed as a calculation
method alternative because the smelting
furnaces operated at used lead battery
recycling facilities consistently process
furnace feed materials with low carbon
content variability. For affected sources
using the carbon mass balance
procedure, the frequency required for
monitoring carbon content of the
smelting furnace input materials should
be reduced to reflect consistency and
low carbon content variability of these
materials.
Response: We decided not to finalize
the proposal using methodologies for
calculating CO2 emissions from lead
production that relied on published
default emission factors or default
values for carbon content of materials
because the differences among
individual lead production facilities
could not be discerned using these
factors. Consequently, the available
default factors for lead production
facilities are inherently less accurate for
calculating smelting furnace process
CO2 emissions than using procedures
that include use of site-specific material
carbon data. Default approaches do not
provide site-specific estimates of
emissions that reflect differences in use
of and variability in feedstocks,
variability in fuels, operating
conditions, fuel combustion efficiency,
and other differences among facilities.
For some carbon-containing input
materials, such as lead scrap,
representative published defaults do not
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exist. Therefore, the use of default
values is more appropriate for sector
wide or national total estimates from
aggregated production data for multiple
facilities rather than for providing an
accurate representation of CO2
emissions from a specific facility.
For the final rule, we did reduce the
monitoring frequency for determining
carbon contents of the smelting furnace
input materials used for the carbon mass
balance to be determined on annual
rather than monthly basis. Facilities can
determine carbon contents either by
using material supplier information or
by annual analysis of representative
samples of the input materials. We agree
that the carbon content for the
significant input materials typically
does not vary widely at a given lead
production facility. Annual carbon
content determinations will still provide
representative carbon content data for
the smelting furnace process CO2
emissions calculations while
minimizing the monitoring burden on
reporters. We continue to account for
process variations due to changes in
production rate, which is likely a more
significant source of variability in the
CO2 emissions from an affected smelting
furnace during the year, by maintaining
the requirement to measure and record
monthly carbon containing input
materials.
S. Lime Manufacturing
1. Summary of the Final Rule
Source Category Definition. Lime
manufacturing plants (LMPs) engage in
the manufacture of a lime product (e.g.,
calcium oxide, high-calcium quicklime,
calcium hydroxide, hydrated lime,
dolomitic quicklime, dolomitic hydrate,
or other products) by calcination of
limestone, dolomite, shells or other
cacareous substances. This source
category includes all LMPs unless the
LMP is located at a kraft pulp mill, soda
pulp mill, sulfite pulp mill, or only
processes sludge containing calcium
carbonate from water softening
processes.
Lime kilns at pulp and paper
manufacturing facilities need to report
emissions under 40 CFR part 98, subpart
AA (Pulp and Paper Manufacturing).
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble and meet
the definition of lime manufacturing
plants in 40 CFR 63.7081(a)(1).
GHGs to Report. For lime
manufacturing, report the following
emissions:
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• Total CO2 process emissions from
all lime kilns combined.
• CO2 combustion emissions from
lime kilns.
• N2O and CH4 emissions from fuel
combustion at each kiln under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources) using the
methodologies in subpart C.
• CO2, N2O, and CH4 emissions from
each stationary combustion unit other
than kilns under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources).
• CO2 collected and transferred off
site under 40 CFR part 98, subpart PP
(Suppliers of CO2).
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. For CO2 emissions from
kilns, facilities must use one of two
methods, as appropriate:
• If all lime kilns at a facility have
certain types of CEMS in place, the
reporter must use the CEMS and follow
the Tier 4 methodology (in 40 CFR part
98, subpart C) to measure and report
under the Lime Manufacturing subpart
(40 CFR part 98, subpart S) combined
process and combustion CO2 emissions.
• If CEMS meeting the specifications
above are not in place for all kilns at the
facility, the reporter can elect to either
(1) install and operate a CEMS and
follow the Tier 4 methodology to
measure and report combined process
and combustion CO2 emissions from all
lime kilns or (2) calculate CO2 process
emissions for each lime type using an
emission factor for each lime type, the
mass of lime produced, an emission
factor for byproduct/waste (such as lime
kiln dust and scrubber sludge), and the
mass of byproduct/waste. If using
approach (2):
—Each emission factor must be
determined monthly for each lime
type from monthly measurements of
the calcium oxide and magnesium
oxide content of the lime and
stoichiometric ratios of CO2 to each
oxide in the lime.
—The emission factor for each lime
byproduct/waste sold (such as lime
kiln dust) must be determined
monthly.
—The emissions from lime byproducts/
wastes that are not sold (such as lime
kiln dust and scrubber sludge) must
be determined annually.
—The mass of each lime type produced
and lime byproduct/waste sold (such
as lime kiln dust) must be recorded on
a monthly basis.
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—The mass of each lime byproduct/
waste not sold (such as lime kiln dust
and scrubber sludge) must be
recorded annually.
—Report process CO2 emissions from all
kilns combined under 40 CFR part 98,
subpart S (Lime Manufacturing), and
report combustion CO2 emissions
from each kiln under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart S.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
S.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart S: Lime
Manufacturing.’’
• The definition of lime
manufacturing was revised to be similar
to the definition in the Lime NESHAP
at § 63.7081(a) and (a)(1).
• Reporting requirements were
revised from a ‘‘per kiln’’ basis to ‘‘all
kilns combined’’.
• The emissions calculations were
revised to determine monthly emissions
factors for each lime type and
byproduct/waste type rather than for
each kiln.
• Emission calculations for
byproducts/wastes were added.
• The requirement to measure the
calcium oxide and magnesium oxide
content of byproducts/wastes on a
monthly basis was changed to an annual
basis for byproducts/wastes that are not
sold.
• The correction factor for
byproducts/wastes was removed from
the rule.
• Additional direct measurement
devices/methods are being allowed to
include those currently in use by the
industry.
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• 40 CFR 98.196 was reorganized and
updated. Some data elements were
moved from 40 CFR 98.197 to 40 CFR
98.196, and some data elements that a
reporter must already use to calculate
GHGs as specified in 40 CFR 98.193
were added to 40 CFR 98.196 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on lime
manufacturing were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart S: Lime
Manufacturing.’’
Definition of Source Category
Comment: Multiple commenters
requested more clarification in defining
which sources and equipment are
covered by the proposed rule. The rule
defines the source category as a facility
that contains ‘‘a rotary lime kiln to
produce a lime product.’’ In addition,
proposed 40 CFR 98.192(b) required
sources to report emissions from ‘‘each
lime kiln and any other stationary
combustion unit.’’
Response: We have reviewed the rule
language and decided the source
category definition should provide more
clarity. The source category is meant to
include all kiln types used in the lime
manufacturing industry; therefore,
language in the final rule has been
changed to be similar to the definition
from the Lime NESHAP in 40 CFR
63.7081(a) and (a)(1). This Lime
NESHAP effectively characterizes lime
plants as those engaging in the
manufacture of a lime product by
calcination. The final rule requires all
stationary combustion units to report
under 40 CFR part 98, subpart C of the
final rule.
Final rule language under 40 CFR
98.192 requires facilities to report CO2,
CH4, and N2O emissions from kilns used
in the lime manufacturing process and
all other combustion units at the lime
manufacturing facility other than kilns.
The language has also been clarified in
40 CFR 98.193. Facilities using CEMS
for all lime kilns report combined
process and combustion emissions from
kilns under 40 CFR part 98, subpart S,
according to the Tier 4 methodology in
40 CFR part 98 subpart C (General
Stationary Fuel Combustion Sources).
Facilities must follow the requirements
of subpart C for estimating and reporting
combustion related emissions for all
other combustion units and report these
emissions under subpart C. See Section
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56315
III.C of this preamble for an overview of
the requirements for stationary
combustion units.
Selection of Proposed GHG Emissions
Calculation and Monitoring Methods
Comment: Multiple commenters
requested the language in 40 CFR part
98, subpart S be changed to allow
emissions to be reported by ‘‘all kilns
combined’’ instead of the proposed
rule’s request to report emission for
each kiln. Multiple commenters further
recommended that the process
emissions calculations be changed to
calculate emissions by the lime type
produced as opposed to the current rule
calculations which use a kiln specific
emission factor. Two commenters stated
that lime products are commonly
aggregated at the plant making it
difficult to estimate the amount of
product produced at an individual kiln.
These commenters stated that current
lime plant configuration do not allow
accurate kiln specific calculations.
Response: We have reviewed the
common lime plant configuration and
the currently proposed rule language
and have decided that it is not necessary
to require kiln-specific emissions
reporting. We have observed that some
kilns would have to retrofit weigh belt
scales in the production line between
kilns and storage silos, since they do not
currently exist. Calculating emissions by
kiln could increase the reporting burden
for these facilities. According to one
commenter, when kiln-specific
emissions have been reported in the
past, the data are usually derived by
distributing the aggregated emissions
among the kilns. Accurate
measurements at the kiln level are rarely
achieved. If this is true for most lime
manufacturing facilities, the data does
not necessarily provide a better estimate
of emissions.
For the purposes of this rulemaking,
reporting for all kilns combined will
simplify and minimize the reporting
burden without significant loss in
accuracy because: (1) Kilns may
produce more than one type of lime in
a given reporting period, (2) emission
factors are based on lime type, and (3)
lime plants collect products in
combined bagging areas (separated by
lime type). The final rule language has
been changed to require reporting by
lime type from all kilns combined rather
than all lime types for each kiln. This
final rule language is consistent with the
National Lime Association (NLA)
Protocol, which was used as the basis
for the methodology in the proposed
rule. Information collected under this
rule will help to inform future
methodologies and determine whether
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kiln level reporting could be more
appropriate for future reporting.
Comment: The proposed rule used a
default correction factor in calculating
lime product and byproduct/waste
emissions. Multiple commenters
suggested using the National Lime
Association Protocol to determine lime
product and by-product/waste process
emissions. According to the
commenters, this method is more
precise due to the use of measured
oxide values and stoichiometric ratios
rather than correction factors.
Response: We have reviewed the
proposed rule and NLA Protocol
calculation methods and noted that the
use of actual oxide measurements in
calculating emissions from lime plants
does not cause an additional burden to
the reporter since this is a currently
used practice. We also agree that the use
of actual measurements is more
accurate. Therefore, we have decided to
remove the use of a correction factor in
the final rule equations; emissions will
be calculated from actual oxide
measurements of each type of lime and
calcined byproducts/wastes.
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Monitoring and QA/QC Requirements
Comment: Multiple commenters
asked that the language pertaining to
allowable measurement devices for lime
products and byproducts/wastes sold,
be changed to include measurement
devices commonly used in the lime
industry. The current rule language
requires weigh hoppers and belt weigh
feeders as the measurement devices; the
aforementioned commenters have
identified bag, truck and rail scales as
reliable (annually calibrated) direct
measurement methods commonly used
in the lime industry. In addition,
commenters have requested lime
byproducts/wastes not sold be
calculated by a facility generation rate.
Response: After reviewing the rule
language and common industry
practices, we have decided to include
other direct measurement devices used
for accounting purposes, including but
not limited to, weigh feeders, calibrated
bag, rail or truck scales, and barge
measurements. These methods are
consistent with the original intent of the
rule and add further clarification on
measurement methods applicable to
determine quantities of both lime
produced and byproducts/waste
generated.
In addition, reporters are required to
perform an annual cross check by
measuring lime products at the
beginning and end of the year. For
calcined byproducts/wastes not sold, a
material balance approach that
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indirectly measures the generation rate
should be used.
Comment: Multiple commenters
asked that the language in 40 CFR part
98, subpart S pertaining to testing the
chemical composition of each type of
lime (including the byproducts and
waste) be changed to allow testing by
onsite lab facilities. Currently the rule
specifies an ‘‘off-site laboratory
analysis’’ but according to the
commenter, commercial lime plants
normally have onsite lab facilities.
Response: We agree that the analysis
does not have to be performed by an
independent certified laboratory,
especially since we specify the
analytical procedures that must be used
by any laboratory, and we note that inhouse laboratories may have more
applicable experience in determining
chemical composition. Reporters can
determine whether to perform the test
onsite or send the samples to offsite
laboratory facilities. Therefore the
language in the final rule has been
changed.
Data Reporting Requirements
Comment: Multiple commenters
requested the language in 40 CFR part
98, subpart S pertaining to reporting
information to EPA be changed so that
business sensitive information is kept in
company records. Commenters agree
that the production capacity, product
quality (i.e., oxide content), emission
factors and operating hours and days for
each kiln, are required for emissions
calculations but are concerned that
making this information public would
give information about their efficiency,
productivity and capacity of kilns and
facility.
Response: EPA reviewed CBI
comments received across the rule (both
general and subpart-specific comments)
and our response is discussed in Section
II.R of this preamble for legal issues.
Also, see Section II.N of this preamble
for the response to comments on the
emissions verification approach.
We agree that annual operating hours
and capacities are not used in the
calculation of CO2 emissions and these
parameters have been moved to
recordkeeping. This information can
help to verify anomalies in emissions
data if there were temporary shutdowns,
etc.
We disagree that emission factors and
product quality be maintained as
records rather than be reported.
Emission factors and product quality are
used in calculations to establish the site
specific rate of CO2 emissions generated
for each type of lime produced.
Therefore these data are required in
order to verify the CO2 emissions that
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are being reported. This internal
verification system ensures that the
GHG emissions reported are accurate.
T. Magnesium Production
At this time EPA is not going final
with the magnesium production subpart
(40 CFR part 98, subpart T). For the
immediate future, EPA believes that
emissions of GHGs from magnesium
production are sufficiently covered by
the reporting requirements under 40
CFR part 98, subpart OO for Industrial
Gas Supply. This information on U.S.
production, imports, and exports of SF6
will provide at least a general, order-ofmagnitude check on consumption of SF6
by magnesium production and other
uses of SF6. EPA will finalize the
proposed reporting requirements for the
magnesium production industry at a
later date.
U. Miscellaneous Uses of Carbonate
1. Summary of the Final Rule
Source Category Definition. The
Miscellaneous Uses of Carbonate source
category consists of any facility that
uses carbonates listed in Table U–1 of
40 CFR part 98, subpart U in
manufacturing processes that emit
carbon dioxide. The Table includes the
following carbonates: Limestone,
dolomite, ankerite, magnesite, siderite,
rhodochrosite, or sodium carbonate.
Facilities are considered to emit CO2 if
they consume at least 2,000 tons per
year of the carbonates listed above and
that are heated to a temperature
sufficient to allow calcination to occur.
This source category does not include
facilities processing carbonates or
carbonate containing minerals
consumed for producing cement, glass,
ferroalloys, iron and steel, lead, lime,
phosphoric acid, pulp and paper, soda
ash, sodium bicarbonate, sodium
hydroxide or zinc as CO2 emissions
from these processes are covered
elsewhere in this rule.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For miscellaneous
uses of carbonates, report the following
emissions:
• Annual CO2 process emissions for
all miscellaneous uses of carbonates as
specified in this subpart.
• CO2, N2O, and CH4 emissions from
carbonates used in sorbent technology
and each stationary combustion unit on
site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
In addition, report GHG emissions for
other source categories at the facility for
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which calculation methods are provided
in the rule, as applicable.
GHG Emissions Calculation and
Monitoring. Calculate process CO2
emissions using annual carbonate
consumption. All reporters must
calculate the annual mass of carbonates
used in processes which are heated to
temperatures that allow calcination. If
the annual amount of carbonates
consumed is greater than 2,000 tons,
CO2 emissions must be calculated using
either calcination fractions or the actual
mass of input/output carbonates.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart U.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of analyses and calculations required for
this source category.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart U:
Miscellaneous Uses of Carbonates.’’
• The source category definition was
revised to exclude non-emissive uses of
carbonates.
• A de minimis reporting threshold
was added to exclude facilities with
minor emissions based on annual
carbonate consumption.
• The GHG calculation methodology
was changed to allow reporters to
determine emissions from the mass of
carbonate input/output or calcination
fractions.
• To improve the emissions
verification process, 40 CFR 98.216 was
reorganized and updated. Some data
elements were moved from 40 CFR
98.217 to 40 CFR 98.216, and some data
elements that a reporter must already
use to calculate GHG as specified in 40
CFR 98.213 were added to 40 CFR
98.216 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on
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miscellaneous uses of carbonates were
received covering numerous topics.
Most comments requested clarification
on the definition of the source category
and its applicability to affected sources.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
U: Miscellaneous Uses of Carbonates.’’
Definition of Source Category
Comment: Multiple commenters
requested that the source category be
revised to exclude non-emissive uses of
carbonates. Commenters stated that the
source category is poorly defined,
making it difficult to accurately assess
its applicability to an industrial facility.
Commenters noted a number of nonemissive uses as examples, such as the
production of sodium bicarbonate and
sodium hydroxide, during which
sodium carbonates are used, but no
carbon dioxide is released; onsite
mixing of processed cement with
aggregate, limestone used in poultry grit
and as an asphalt filler; or adding
sodium carbonate to a water softener
system.
Response: The rule language has been
modified to exclude non-emissive uses
of carbonates. Non-emissive uses do not
result in CO2 emissions, such as adding
sodium carbonate to a water softener
system. Acid-induced releases of CO2
from the use of carbonates are addressed
in other subparts, where they are
significant, such as Phosphoric Acid
Production.
Selection of Threshold
Comment: Multiple commenters
requested that a de minimus reporting
threshold be added to exclude facilities
with minor emissions. One commenter
noted that some facilities use limestone
and other carbonate as refractory in
furnaces, and it is unclear whether or
not this use of carbonates triggers 40
CFR part 98, subpart U, and at what
level it is triggered.
One commenter noted that at a
pharmaceutical manufacturing facility
there would also be a significant listing
of small operations and activities which
use carbonate compounds in trace
quantities, including the creation of
reagent solutions, and wastewater
treatment operations employing
carbonate compounds for buffering,
chemical precipitation, or solids
stabilization. This commenter
recommended that EPA implement a
threshold of 2,000 tons per year of
carbonates per facility, which would
correlate to CO2 emissions of about
1,000 tons per year.
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One commenter requested that EPA
incorporate a de minimis threshold to
only include equipment where
carbonate is present at greater than 10
percent by weight and heated to a
temperature that allows for
decomposition. This commenter
suggested an alternative threshold,
where EPA would require facilities to
calculate CO2 emissions from each type
of carbonate used in quantities
exceeding 2,000 tons per year.
Response: The rule language has been
modified to specify that GHG emissions
from miscellaneous carbonate use are
required to be reported only from
processes that consume at least 2,000
tons per year and, further, where the
carbonates are heated to a temperature
sufficient to allow the calcination
reaction to occur. This modification to
the definition of the source category
allows facilities with minimal carbonate
consumption and low amounts of GHG
emissions to be excluded from reporting
emissions.
Method for Calculating GHG Emissions
Comment: Multiple commenters
requested that EPA allow emission
calculations to be based on carbonate
fraction of the product instead of
calcination fractions.
Response: The rule has been changed
to allow emission calculations by either
the mass of carbonate input/output or
calcination fraction. These methods
should provide comparable estimates of
emissions.
The calcination fraction method
calculates the amount of CO2 emissions
based on the amount of each carbonate
that is calcined during the process. The
mass and calcination fraction of each
carbonate are measured and used with
a default CO2 emission factor to
determine CO2 emissions.
The carbonate fraction method
calculates the amount of CO2 emissions
as a mass balance between the input and
output amount of each type of
carbonate. The masses are measured and
used with a default CO2 emission factor
to determine CO2 emissions.
The mass of carbonate input/output is
determined by use of the same plant
instruments used for accounting
purposes or by direct measurement.
Calcination fractions can be measured
by the appropriate industry consensus
standards that require laboratory
analysis of each carbonate type.
Alternatively, a default value of one can
be used as the calcination fraction.
Data Reporting Requirements and
Records That Must Be Retained
Comment: One commenter requested
that recordkeeping and reporting
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requirements be exempted for
carbonates kept on-site for emergency
purposes (not manufacturing or
equipment), such as for neutralizing a
chemical spill. This commenter
explained that when used, these
emergency reserves of carbonate
material typically generate insignificant
amounts of CO2 and should therefore be
excluded from reporting requirements.
Response: The final rule does not
cover carbonates that are used in
quantities of less than 2,000 tons per
year and that are not heated to the point
of calcination. Also, this subpart does
not include requirements for calculating
and reporting CO2 emissions from acid
neutralization. Therefore, the use of
carbonates in the manner described is
not covered by the final rule.
Comment: One commenter noted that
the required records are duplicated in
proposed 40 CFR 98.217(a) and
98.217(c), and requested that EPA revise
this so as not to place unnecessary costs
on facilities.
Response: EPA agrees that asking
facilities to maintain records on
procedures used to ensure the accuracy
of monthly carbonate consumption will
be duplicative with maintaining records
of all carbonate purchases and
deliveries. This is especially true if
purchase records are used to determine
monthly carbonate consumption. We
removed this duplicative recordkeeping
requirement from the rule.
To improve the emissions verification
process, 40 CFR 98.216 was reorganized
and updated. Some data elements were
moved from 40 CFR 98.217 to 40 CFR
98.216, and some data elements that a
reporter must already use to calculate
GHG as specified in 40 CFR 98.213 were
added to 40 CFR 98.216 for clarity. All
affected sources must follow the general
recordkeeping provisions under 40 CFR
part 98.3(g) in subpart A.
Commenters may also want to review
Section II.M for the response on the
general recordkeeping requirements and
Section II.N of this preamble for the
response on the emissions verification
approach.
GHGs to Report. For nitric acid
production facilities, report N2O process
emissions from each nitric acid train.
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable. For example,
report CO2, N2O, and CH4 emissions
from each stationary combustion unit on
site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
GHG Emissions Calculation and
Monitoring. Reporters must calculate
N2O process emissions for each nitric
acid train. Calculate the emissions by
multiplying the site-specific emission
factor for each train by the measured
annual nitric acid production for that
train. Determine the site-specific
emission factor for each train through an
annual performance test to measure N2O
from the absorber tail gas vent and the
production rate for that train.
When N2O abatement devices (such as
nonselective catalytic reduction) are
used, adjust the N2O process emissions
for the amount of N2O removed using a
destruction efficiency factor. The
destruction factor is the destruction
efficiency and can be specified by the
abatement device manufacturer or can
be determined using process knowledge
or another performance test.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart V.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98,
subpart V.
V. Nitric Acid Production
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart V: Nitric
Acid Production.’’
• The re-testing trigger was changed.
Performance testing to determine the
N2O emissions factor is required
annually and whenever new abatement
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1. Summary of the Final Rule
Source Category Definition. The nitric
acid production source category consists
of facilities that use one or more trains
to produce weak nitric acid (30 to 70
percent in strength) through the
catalytic oxidation of ammonia.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
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technology is installed. The
performance test should be conducted
under normal operating parameters.
• Equation V–2 was edited to correct
a calculation error and to allow multiple
types of abatement technologies.
• Reorganized and updated 40 CFR
98.226 to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.227 to 40 CFR 98.226, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.223 were added to 40 CFR
98.226 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on nitric acid
production were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart V: Nitric
Acid Production.’’
GHGs To Report
Comment: Multiple commenters
asked that the language in 40 CFR
98.222(b) be clarified to include
emissions under 40 CFR part 98, subpart
V only from units that are 100 percent
dedicated to nitric acid production to
avoid double counting of combustion
emissions.
Response: We appreciate the
comments but have decided not to make
any changes to 40 CFR part 98, subpart
V. According to the applicability criteria
in subpart C, all combustion unit
emissions from nitric acid facilities
(regardless of whether or not the
combustion units are associated with
nitric acid production operations) are to
be reported under subpart C. There will
be no potential for double counting of
combustion emissions at the facility
because Subpart V provides methods for
reporting only the process emissions.
Also see the preamble for responses on
comments related to Subpart C (General
Stationary Combustion).
Method for Calculating GHG Emissions
Comment: Multiple commenters
asked that the requirement to repeat the
annual performance test be removed. In
the proposal, re-testing was triggered
whenever the nitric acid production rate
changed by more than 10 percent.
Commenters asserted that production
depends on demand for nitric acid and
often varies by up to 20 percent.
Response: We appreciate the
comments and have decided to
eliminate re-testing. We believe that
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annual determination of the N2O
emissions factor is sufficient to
accurately calculate N2O emissions as
long as the train equipment remains
consistent over the year-long period
(i.e., no installation of abatement
technology).
Comment: Multiple commenters
asked that alternative methods be
allowed for calculating N2O emissions
from nitric acid production. Specifically
the commenters asked that EPA allow
the use of N2O and flow CEMS to
directly measure N2O emissions and use
the performance test to evaluate the
CEMS accuracy. They also requested
that EPA allow use of existing process
flow meters, process N2O analyzers to
determine the amount of N2O sent to
control devices and conduct a
performance test measuring control
device destruction efficiency for each
control device and then calculate N2O
emissions.
Commenters also asked that finalizing
a methodology for N2O stack testing for
nitric acid units be delayed until EPA
can coordinate with the commenters in
formulating a more accurate means of
measurement from these sources.
Response: We agree that there are
other accurate means of determining
N2O emissions, such as N2O CEMS. The
final rule has been changed to allow
alternative test methods, in addition to
the proposed methods. Any alternative
must be approved by the Administrator
before being used to comply with this
rule. An implementation plan that
details how the alternative method will
be implemented must be included in the
request for the alternative method.
Currently there is no EPA method for
using N2O CEMS. EPA understands the
need to further evaluate and establish
alternative comparable or potentially
more accurate methods for sources to
use in calculating N2O emissions from
nitric acid production and will address
this in future rulemakings or
amendments to rulemaking. Until the
method is approved, facilities must use
the alternatives proposed in the rule for
a performance test. At minimum the
performance test will help to QA/QC
alternative methods currently used to
monitor N2O emissions (including N2O
CEMS).
The final rule allows the use of
existing process flow meters and
process knowledge in the determination
of the destruction efficiency of N2O
abatement technologies. This parameter
is often based on site-specific
knowledge of operations in combination
with manufacturer specifications. We
believe that using existing methods
reduces the potential cost impacts of
this rulemaking and that it is in the best
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interest of the facilities that required
parameters be accurately measured.
Comment: Multiple commenters
asked that Equation V–2 be edited to
follow the summation format used in
the IPCC Tier 2 methodology. The
current format does not allow for
multiple abatement technologies
(including no abatement).
Response: We agree with this
comment. The equation in the proposed
rule contained an error and did not
allow for multiple abatement
technologies. The final rule contains a
corrected version of the equation.
Data Reporting Requirements
Comment: Multiple commenters
argued that the annual production rates,
capacity and operating hours are
considered CBI and should not be
reported. The commenters asked that
this information be maintained by the
facility and made available to the
Agency upon request.
Response: We reviewed CBI
comments received across the rule (both
general and subpart-specific comments)
and our response is discussed in Section
II.R of this preamble and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’ See also Section II.N of this
preamble for the response on the
emissions verification approach.
We agree that annual operating hours
are not used in the calculation of N2O
emissions and this parameter has been
moved to recordkeeping. However, this
parameter is still important for
emissions verification. This information
can help to verify anomalies in
emissions data if there were temporary
shutdowns, etc.
We disagree that production be
maintained as records rather than be
reported. Nitric acid production is a
parameter in the method for
determining annual N2O emissions so
we need production rate in order to
verify the N2O emissions that are being
reported. The internal verification
system ensures that the GHG emissions
reported are as accurate as possible.
We disagree that capacities be
considered confidential information.
During the data gathering process, we
located multiple publicly available
sources that included production
capacities for nitric acid production
facilities. Capacity information can help
EPA determine a reasonable range
within which reported emissions should
be. We agree that capacities are not used
in the calculation of N2O emissions;
however, this is still an important
parameter for verifying emissions.
Therefore, this parameter has been
moved to recordkeeping.
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W. Oil and Natural Gas Systems
At this time, EPA is not going final
with the fugitive and vented methane
emissions from the oil and gas sector
under 40 CFR part 98, subpart W. As
EPA considers next steps, we will be
reviewing the public comments and
other relevant information.
EPA received a number of lengthy,
detailed comments regarding 40 CFR
part 98, subpart W. Commenters
generally opposed the proposed
reporting requirements and thought they
would entail significant burden and
cost. For example, many commenters
asserted that use of direct measurement
to collect data required under 40 CFR
part 98, subpart W would entail
significant burden and that the proposal
lacked standards for leak detection and
measurement equipment. In many cases,
commenters provided alternative
approaches to the reporting
requirements proposed by EPA such as
the use of emission factors and/or
reducing the number of sources and
sites requiring direct measurement e.g.,
through statistical sampling. In addition
to comments on burden, commenters
requested clarification from EPA on a
number of proposed reporting
provisions.
As EPA received extensive comments
on this subpart, EPA plans to take
additional time to perform additional
analysis and consider alternatives to
data collection procedures and
methodologies. These alternatives will
provide similar coverage of vented and
fugitive methane and other GHG
emissions in the oil and gas sector,
while concurrently taking into account
industry burden. As stated in Section
V.W of the preamble to the proposed
rule (74 FR 166606, April 10, 2009),
EPA will also consider the inclusion of
GHG reporting from other sectors of the
oil and gas industry.
Where applicable, EPA will also
consider the applicability of engineering
estimates, emissions modeling software
and emissions factors rather than
relying so extensively on the use of
direct measurement. EPA will consider
optimal methods of data collection in
order to maximize data accuracy, while
considering industry burden.
X. Petrochemical Production
1. Summary of the Final Rule
Source Category Definition. The
petrochemical production source
category consists of all processes that
produce acrylonitrile, carbon black,
ethylene, ethylene dichloride, ethylene
oxide, or methanol, with certain
exceptions. Exceptions include
processes that produce a petrochemical
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as a byproduct, processes that produce
methanol from synthesis gas when the
annual mass production of hydrogen or
ammonia exceeds the annual mass of
methanol produced, direct chlorination
processes operated independently of
oxychlorination processes to produce
ethylene dichloride, processes that
produce bone black, and processes that
produce a petrochemical from bio-based
feedstock.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For petrochemical
production facilities, report CO2, CH4,
and N2O process emissions from each
petrochemical production unit. Process
emissions include CO2 generated by
reaction in the process. Process
emissions also include CO2, CH4, and
N2O emissions generated by combustion
of off-gas from the process in stationary
combustion units and flares. For some
of the GHG emission calculation and
monitoring options, 40 CFR part 98,
subpart X references procedures in 40
CFR part 98, subpart C for calculating
emissions from stationary combustion
sources, and it references procedures in
40 CFR part 98, subpart Y for
calculating emissions from flares.
In addition, report GHG emissions for
other source categories at the facilities
for which calculation methods are
provided in the rule, as applicable. For
example, report CO2, N2O, and CH4
emissions from each stationary
combustion unit on site that does not
burn process off-gas under 40 CFR part
98, subpart C (General Stationary Fuel
Combustion Sources). The quantity of
CO2 captured must also be reported by
following the requirements of 40 CFR
part 98, subpart PP.
GHG Emissions Calculation and
Monitoring. CO2 process emissions from
petrochemical production must be
determined by one of three methods.
Process emissions include emissions
from CO2 generated by chemical
reactions in the process and from the
combustion of process off-gas and liquid
wastes.
One emission calculation option is to
route all process vent emissions to one
or more stacks and use CEMS to
measure the CO2 emitted from each
stack (except flare stacks). For each
stack that includes emissions from
combustion of process off-gas, reporters
must calculate CH4 and N2O emissions
by the procedures specified in 40 CFR
part 98, subpart C. For each flare, the
final rule requires CO2, CH4, and N2O
emissions to be calculated using the
procedures in 40 CFR 98.253(b)
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(Petroleum Refineries). If CO2 CEMS are
used on all subject stacks, even if the
CEMS were installed for reasons other
than compliance with this rule, then the
rule requires the use of this reporting
option.
A second emission calculation option
is to use a mass balance. Under this
option, the quantity of each carboncontaining feedstock added to the
process and the quantity of each carboncontaining product produced by the
process must be measured for each
calendar month, or it may be calculated
based on measured changes in the
liquid level in storage tanks. The carbon
content of each feedstock and product
also must be determined at least once
per month. The carbon content may be
measured directly, or it may be
calculated based on measurements of
the composition and known compound
molecular weights. Under this option,
the procedures for products also apply
to byproducts and liquid organic wastes
that are not combusted onsite. To
prevent double-counting of combustion
emissions, this option specifies that the
procedures for stationary combustion
sources in 40 CFR part 98, subpart C
apply only to the supplemental fuel
(e.g., natural gas) burned in combustion
units that supply energy needs for
petrochemical processes. The final rule
specifies numerous measurement
method options and related calibration
requirements in 40 CFR 98.244. To
potentially minimize the sampling and
analysis burden, the final rule, like the
proposed rule, includes an option that
allows reporters to assume a feedstock
or product is always 100 percent pure
if they determine that the specified
compound is always present at greater
than 99.5 percent.
A third emission calculation option is
available only for ethylene processes.
Because nearly all process emissions
from this process are from combustion
of process off-gas, the final rule allows
calculation of emissions from all
stationary combustion units that burn
process off-gas (with or without
supplemental fuel) in accordance with
the Tier 3 or Tier 4 procedures in 40
CFR part 98, subpart C. In addition, this
option requires CO2, CH4, and N2O
emissions from each flare to be
calculated using the procedures in 40
CFR 98.253(b) (Petroleum Refineries).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR 98.246.
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Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR 98.247.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart X:
Petrochemical Production.’’
• The definition of the source
category was changed to exclude
ethylene dichloride production by the
direct chlorination process alone from
the petrochemical production source
category because the only GHG
emissions from this process are from the
combustion of supplemental fuel and
the combustion of hydrocarbon
emissions in air pollution control
devices. Ethylene dichloride produced
by both direct chlorination and
oxychlorination in the ‘‘balanced
process’’ is still part of the source
category.
• For the mass balance option, the
measurement and emission calculation
frequency was changed from weekly to
monthly.
• For ethylene processes, an
alternative was added to the mass
balance option that allows reporters to
calculate emissions from stationary
combustion sources that burn ethylene
process off-gas (with or without
supplemental fuel) using the Tier 3 or
Tier 4 procedures in 40 CFR part 98,
subpart C. This includes all such
combustion units, including units that
supply energy to processes other than
the ethylene process. This option does
not affect requirements for stationary
combustion sources related to ethylene
processes that burn no process off-gas;
emissions from these combustion units
still must be calculated using the
methods in any applicable Tier in 40
CFR part 98, subpart C.
• The reporting requirements in 40
CFR 98.246 were reorganized and
updated to facilitate the emissions
verification process, simplify and clarify
requirements, and address requirements
for the new monitoring option for
ethylene processes.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Many comments on petrochemical
production were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart X:
Petrochemical Production.’’
Definition of Source Category.
Comment: Several commenters stated
that ethylene production should be
removed from the petrochemical
production source category because
essentially all GHG emissions from such
processes are from combustion sources,
which would be subject to reporting
under 40 CFR part 98, subpart C
regardless of whether the process is
included in the petrochemical
production source category. According
to two commenters, using a mass
balance approach is irrelevant and
confusing because ethylene processes
have no normal process vents. One
commenter noted that methane is
produced in ethylene processes, but the
vast majority is returned as fuel within
the plant or another plant at the same
site and thus would produce CO2
emissions only when combusted.
Another commenter noted that off-gas
from ethylene processes that are colocated with a petroleum refinery or
other chemical plants is sent to the fuel
gas system where it is mixed with other
process gases from non-ethylene units
in a fuel gas blend drum and then
distributed to combustion units
throughout the refinery and/or chemical
plant. According to two commenters,
the mass balance approach is onerous
due to the number of product streams
that would have to be measured, and the
results of a mass balance most likely
would be less accurate than a fuel
combustion methodology. These two
commenters also noted that calculating
GHG emissions based on fuel
combustion is the methodology used
currently by most ethylene units. One
commenter suggested that as an
alternative to excluding ethylene units
from the petrochemical production
source category, EPA could add an
emission calculation methodology to 40
CFR part 98, subpart X that would allow
facilities to calculate combustion
emissions based on fuel consumption.
Response: As one commenter noted,
methane (and other light ends) are
generally burned in combustion units to
supply energy needs for the ethylene
process itself and possibly other
processes. Emissions from combustion
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of these process off-gases are process
emissions that are intended to be
reported under 40 CFR part 98, subpart
X. At facilities where the ethylene
process off-gases are not mixed with offgas from other processes, we do not
believe that the mass balance approach
is illogical; the flows and carbon
contents of feedstocks and products can
be determined for an ethylene process,
and the resulting values can be used in
the mass balance equations, just as they
can for any other petrochemical process.
Furthermore, we do not know if the
views of the commenters reflect the
views of all ethylene manufacturers.
Therefore, we have retained ethylene in
the petrochemical production source
category, and we have retained the mass
balance option in the final rule.
Although we still think a mass
balance approach is appropriate and
valid for ethylene processes, we have
also evaluated combustion-based
methodology options for the final rule.
Given that the cracking and separation
operations generate negligible CO2, we
agree with the commenters that the only
significant source of emissions in
ethylene production is from combustion
operations. One concern we have with
using the Tier 1 and Tier 2
methodologies in 40 CFR part 98,
subpart C is that they rely on default
emission factors and company records
(rather than measurements) of fuel flow.
Given the variety of feedstocks and the
corresponding variety in process off-gas,
we do not believe default emission
factors or fuel flow based on company
records are appropriate. Therefore, we
rejected the Tier 1 and Tier 2
methodologies. On the other hand, Tier
3 requires measurement of the total fuel
flow and relatively frequent
measurement of the carbon content of
the fuel. Using CEMS to measure CO2
emissions (i.e., the Tier 4 methodology
in 40 CFR part 98, subpart C) is also a
good way to measure CO2 emissions
from any combustion unit. Therefore,
we determined that use of the Tier 3 or
Tier 4 methodology is acceptable for
calculating emissions from combustion
units that burn ethylene process off-gas
(with or without mixing with
supplemental fuel), and these options
are included in the final rule. In
addition, because the methodology used
for calculating emissions from one
combustion unit has no bearing on the
emissions from any other combustion
unit, the final rule states that a facility
is not required to use the same Tier for
each stationary combustion unit.
Comment: One commenter requested
that EPA remove ethylene dichloride
(EDC) from the petrochemical source
category because EDC is not
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manufactured using a fossil fuel-based
feedstock (e.g., crude oil, naphtha,
natural gas condensate, methane, or
other fossil fuel-based chemicals), no
GHGs are used in the manufacturing
process, and only a trace amount of CO2
is generated in the process. Another
commenter requested clarification that
EDC produced as an intermediate in the
production of vinyl chloride monomer
is not part of the petrochemical source
category because the entire process is
considered to be an ‘‘integrated
process’’, and the primary product of
the process is not EDC. The commenter
noted that the term ‘‘primary product’’
is also used in the Hazardous Organic
NESHAP (HON) (40 CFR part 63,
subpart F), but it has a different
definition. To avoid confusion created
by multiple definitions for the same
term, the commenter urged EPA to
consider alternatives to the concept of
primary product for determining
applicability of an integrated process.
Response: EDC is produced by two
processes. In one process, the direct
chlorination process, ethylene is reacted
with chlorine to create EDC. As the
commenters noted, reactions in this
process produce negligible CO2
emissions and no other GHG emissions.
The only GHG emissions associated
with this process are from the
combustion of process off-gas and
supplemental fuel. We have determined
that monitoring and reporting of these
emissions will be required under 40
CFR part 98, subpart C. Therefore, we
have removed this process from the
petrochemical source category.
In the second EDC process, the
oxychlorination process, ethylene is
reacted with hydrochloric acid to create
EDC and water. Some of the ethylene,
however, oxidizes to CO2 and water in
a competing side reaction. All facilities
in the United States (U.S.) that operate
this process operate it as part of an
integrated process that includes vinyl
chloride monomer production and a
direct chlorination process. This
integrated process is called a ‘‘balanced
process’’. Although available estimates
suggest the amount of CO2 emitted is
small relative to emissions from
combustion, we do not have data to
support such estimates. Furthermore,
even if small relative to other sources,
the total amount is not necessarily
insignificant. We continue to believe
information about these emissions is
needed in order to support future policy
decisions regarding petrochemical
processes. Therefore, we have not
removed EDC production by the
balanced process from the
petrochemical production source
category.
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In the proposed rule, an ‘‘integrated
process’’ was defined as ‘‘a process that
produces a petrochemical as well as one
or more other chemicals that are part of
other source categories’’ subject to
reporting under 40 CFR part 98. This
concept does not apply to production of
EDC as an intermediate that is used in
the onsite production of vinyl chloride
monomer because vinyl chloride
monomer production is not a source
category that is subject to reporting
under 40 CFR part 98. We used general
language in the proposed rule that
would apply to various integrated
process scenarios, but the only scenario
we know of that meets these conditions
is methanol production from synthesis
gas that is sometimes also used to
produce hydrogen and/or ammonia
(both of which are subject to reporting
under other subparts in 40 CFR part 98).
Because this is the only situation where
the ‘‘integrated process’’ concept would
apply, we decided to replace it in the
final rule with language in 40 CFR
98.240 that explicitly states the
applicability determination procedures
for a process that produces methanol,
hydrogen, and/or ammonia from
synthesis gas. Thus, the term ‘‘primary
product’’ has also been removed from
the final rule, which eliminates the
potential conflict with the definition in
the HON.
Method for Calculating GHG Emissions
Comment: Two commenters stated
that the proposed CEMS requirements
are overly restrictive. According to these
commenters, a facility should have the
option to install a CEMS on one or more
sources without being required to have
a CEMS on all sources associated with
a petrochemical production process. For
example, the commenters suggested that
a facility should have the flexibility to
use a CEMS on a large emission point
while being allowed to use the
combustion equations and/or the mass
balance approach for smaller emission
points in the process (e.g., start-up
heaters and steam jet exhausts from
distillation columns operating under
vacuum).
Response: If some emissions were
from stacks monitored with CEMS and
all other emissions were from
combustion units without CEMS, it
would be possible to use a combination
of CEMS and the combustion equation
methodology to calculate the total GHG
emissions from a petrochemical process.
However, this scenario is unlikely,
which means other methodology would
be needed to estimate emissions from
other emission points (e.g., the steam jet
exhausts cited by the commenters). It is
not clear to us how the mass balance
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methodology would be used to estimate
these other emissions because the mass
balance relies on knowledge of the total
carbon input to the process and the total
amount of carbon in all products (and
organic liquid wastes); the difference is
assumed to be the total CO2 emissions.
Theoretically, other methodology could
be developed to calculate emissions
from specific other emission points, but
the commenter has not suggested other
techniques. Therefore, the final rule
does not include an option to mix CEMS
with other methodology for a given
process unit.
Comment: According to several
commenters, weekly measurements of
feedstocks and products are
burdensome or unwarranted. Two
commenters suggested changing the
frequency to monthly because monthly
accounting would align better with
existing industry accounting
procedures, reduce the burden, and
provide 12 high-quality estimates per
year. One commenter suggested
monthly mass balance calculations for
carbon black facilities because the
emissions from a carbon black
manufacturing facility do not vary
significantly from week to week.
Another commenter requested a
provision to allow the reporter to
determine a sampling frequency that is
consistent with the variability of the
stream.
Response: We are sensitive to the
burden imposed by the rule and want to
minimize it when possible. Based on the
results of an uncertainty analysis (see
memorandum entitled ‘‘Monte Carlo
Simulation of Uncertainty in Monitoring
Frequency for Mass Balance Option for
Petrochemical Production Facilities’’ in
the docket) we believe longer
monitoring periods will not
significantly compromise the
monitoring results for the mass balance
option. Therefore, the mass balance
option in the final rule requires monthly
monitoring instead of the proposed
weekly monitoring.
Data Reporting Requirements
Comment: Two commenters stated
that the proposed reporting
requirements are excessive, particularly
information such as each carbon content
measurement and information on the
calibration of each flow meter.
According to the commenters,
submitting this information will not
improve the overall quality of the GHG
emission calculation, and it is not
necessary because the facilities are
required to certify that the submitted
information is true, accurate, and
complete. Therefore, the commenters
recommended that facilities be required
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to retain records of such information
rather than submit it in reports.
Response: A primary reason that
additional information beyond annual
emissions must be reported is so that
EPA can verify the results. To facilitate
the emissions verification process, 40
CFR 98.246 was reorganized and
updated. For example, the final rule
requires reporting of all input data used
in the emission calculation equations,
not just the carbon content values and
the annual quantities, because this
information is needed so the
calculations can be reproduced and
confirmed as part of the emissions
verification process. Note, however, that
any increase in the burden to report
flow measurements has been offset by
the reduction in monitoring frequency
from weekly to monthly. The reporting
requirements in the final rule for the
mass balance option also have been
simplified and clarified by replacing the
requirement to submit all information
related to uncertainty estimates with a
requirement to submit only the dates
and summarized results of measurement
device calibrations. The estimated
accuracy of measurement devices and
the technical basis for such
measurements must also be documented
as part of the monitoring plan that is
maintained onsite. The reporting section
also was updated to include reporting
requirements for the new monitoring
option for ethylene processes.
Y. Petroleum Refineries
1. Summary of the Final Rule
i. Source Category Definition
Petroleum refineries are facilities that
produce gasoline, gasoline blending
stocks, naphtha, kerosene, distillate fuel
oils, residual fuel oils, lubricants, or
asphalt (bitumen) by the distillation of
petroleum or the redistillation, cracking,
or reforming of petroleum derivatives.
The definition of petroleum refineries
excludes facilities that distill only
pipeline transmix (off-spec material
created when different specification
products mix during pipeline
transportation), regardless of the
products produced.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
ii. GHGs to Report
The refinery processes and gases that
must be reported are listed in Table Y–
1 of this preamble along with the rule
subpart that specifies the calculation
methodology that must be used.
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TABLE Y–1—GHGS TO REPORT
Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98,
subpart indicated . . .
For this refinery process . . .
CO2
Stationary combustion .................................................................................................................
Flares ...........................................................................................................................................
Catalytic cracking .........................................................................................................................
Traditional fluid coking .................................................................................................................
Fluid coking with flexicoking design ............................................................................................
Delayed coking ............................................................................................................................
Catalytic reforming .......................................................................................................................
Onsite and offsite sulfur recovery ................................................................................................
Coke calcining .............................................................................................................................
Asphalt blowing ............................................................................................................................
Equipment leaks ..........................................................................................................................
Storage tanks ...............................................................................................................................
Other process vents ....................................................................................................................
Uncontrolled blowdown systems .................................................................................................
Loading operations ......................................................................................................................
Hydrogen plants (nonmerchant) ..................................................................................................
CH4
N2O
C
Y
Y
Y
C/Y
—
Y
Y
Y
Y
—
—
Y
—
—
P
C
Y
Y
Y
C/Y
Y
Y
—
Y
Y
Y
Y
Y
Y
Y
P
C
Y
Y
Y
C/Y
—
Y
—
Y
—
—
—
Y
—
—
—
Key:
C = 40 CFR part 98, subpart C (General Stationary Combustion Sources).
P = 40 CFR part 98, subpart P (Hydrogen Production).
Y = 40 CFR part 98, subpart Y (Petroleum Refineries).
— = Reporting from this process is not required.
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iii. GHG Emissions Calculation and
Monitoring
Under 40 CFR part 98, subpart Y,
petroleum refineries must calculate CO2,
CH4 and N2O emissions using the
calculation methods described below for
each refinery process.
For CO2 emissions, reporters must use
CEMS or specified calculation methods
as follows:
• For refinery units with certain types
of CEMS in place, reporters must use
the CEMS and follow the Tier 4
methodology of 40 CFR part 98, subpart
C to report combined process and
combustion CO2 emissions.
• For refinery units without CEMS in
place, reporters can elect to either (1)
install and operate a CEMS to measure
combined process and combustion CO2
emissions according to the requirements
specified in 40 CFR part 98, subpart C
or (2) calculate CO2 emissions using the
methods summarized below.
Flares. CO2 emissions from flares
must be calculated using the gas flow
rate (either measured with a continuous
flow meter or calculated using
engineering calculations) and either: (1)
At least weekly measured carbon
content of the flare gas, or (2) at least
weekly measured heat content of the
flare gas and an emission factor
provided in the rule. If the carbon
content and heat content of the gas are
not measured at least weekly,
engineering estimates of heat content
during normal flare use is allowed, but
CO2 emissions for each startup,
shutdown, and malfunction event
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exceeding 500,000 standard cubic feet
(scf) per day of flare gas must be
calculated separately using engineering
estimates of the quantity of gas
discharged and the carbon content of
the flared gas. CH4 and N2O emissions
from flares must be calculated using the
methods specified in 40 CFR part 98,
subpart Y.
Catalytic Cracking Units, Fluid
Coking Units, and Catalytic Reforming
Units. CO2 emissions must be calculated
using the volumetric flow rate of the
exhaust gas (measured or calculated)
and hourly measured carbon monoxide
(CO) and CO2 concentrations in the
exhaust stacks from the catalytic
cracking unit regenerator and fluid
coking unit burner from units exceeding
10,000 barrels per stream day. Catalytic
cracking and fluid coking units below
this threshold must use the required
flow and gas monitors if they are inplace, but may use engineering
estimates for determining CO2 emissions
if the required flow and gas monitors are
not in place. Similarly, catalytic
reforming units may use the flow and
gas monitors required for large catalytic
cracking and fluid coking units;
alternatively, reporters may use
engineering estimates based on the
quantity of coke burned off, the carbon
content of the coke (using either a
measured or a default value), and the
number of regeneration cycles. CH4 and
N2O emissions may be measured or may
be calculated using the CO2 emissions
and default emission factors. Fluid
coking units that use the flexicoking
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design may account for their GHG
emissions either by using the methods
specified for traditional fluid coking
units, or by using the methods for
stationary combustion specified in 40
CFR part 98, subpart C.
Onsite and Off Site Sulfur Recovery.
CO2 emissions must be calculated using
the volumetric flow rate of the sour gas
(measured continuously or calculated
from engineering calculations) and the
carbon content of the sour gas stream
(using a measured or a default value).
Coke Calcining Units. CO2 emissions
must be calculated from the difference
between the carbon input as green coke
and the carbon output as marketable
petroleum coke and as coke dust
collected in the dust collection system.
The CH4 and N2O emissions from coke
calcining units may be measured or
calculated using the calculated CO2
emissions and default emission factors.
Asphalt Blowing Operations. For
uncontrolled asphalt blowing operations
or asphalt blowing operations controlled
by vapor scrubbing, CH4 and CO2
emissions must be calculated using a
facility-specific emission factor based
on test data or, where test data are not
available, a default emission factor
provided in the rule. For asphalt
blowing operations controlled by a
thermal oxidizer or flare, CH4 and CO2
emissions must be calculated by
assuming 98 percent of the CH4 and
other hydrocarbons generated by the
asphalt blowing operation are converted
to CO2.
Delayed Coking Units. CH4 emissions
from the depressurization of delayed
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coking vessels must be calculated using
the method outlined below for other
process vents. The emissions released
during the opening of vessels for coke
cutting operations must be calculated
using the vessel parameters (height and
diameter), vessel pressure, the number
of times the vessel was opened, the void
fraction of the coking vessel prior to
steaming, and the mole fraction of CH4
in the gas released (using a measured or
a default value provided in the rule).
The rule provides an alternative of using
only the vessel parameter equation if no
water or steam is added to the vessel
after the vessel is vented to the
atmosphere.
Other Process Vents. GHG emissions
from other process vents that contain
CO2, CH4, or N2O exceeding
concentration thresholds specified in
the rule must be calculated using the
volumetric flow rate, the mole fraction
of the GHG in the exhaust gas, and the
number of hours during which venting
occurred.
Uncontrolled Blowdown Systems. CH4
emissions from uncontrolled blowdown
systems must be calculated using either
the method specified for process vents
or a default emission factor and the sum
of crude oil and intermediate products
received from off site and processed at
the facility.
Equipment Leaks. CH4 emissions from
equipment leaks must be calculated
using either default emission factors or
process-specific CH4 composition data
and leak data collected using the leak
detection methods specified in EPA’s
Protocol for Equipment Leak Emission
Estimates.
Storage Tanks. For storage tanks
covered by the requirements of this rule,
the methodology used to calculate the
CH4 emissions depends on the material
stored. For storage tanks used to store
unstabilized crude oil, facilities must
use either: (1) The CH4 composition of
the unstabilized crude oil (based on
direct measurement or product
knowledge) and the measured gas
generation rate; or (2) an emission
factor-based method using the quantity
of unstabilized crude oil received at the
facility, the pressure difference between
the previous storage pressure and
atmospheric pressure, the mole fraction
of CH4 in the vented gas (using either a
measured or a default value), and an
emission factor provided in the rule. For
storage tanks used to store material
other than unstabilized crude oil with a
vapor-phase CH4 concentration of 0.5
percent by volume or more, facilities
must use either tank-specific methane
composition data and applicable
correlations in AP–42, Section 7.1 (as
implemented in the TANKS Model
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(Version 4.09D) or similar models) or a
default emission factor provided in the
rule.
Loading Operations. CH4 emissions
from loading operations must be
calculated using vapor-phase methane
composition data and the method in
Section 5.2 of AP–42: ‘‘Compilation of
Air Pollution Emission Factors.’’
Facilities must calculate CH4 emissions
only for loading materials that have an
equilibrium vapor-phase CH4
concentration equal to or greater than
0.5 percent by volume. Other facilities
may assume zero CH4 emissions.
iv. Data Reporting
In addition to the information
required to be reported by the General
Provisions (40 CFR 98.3(c)) and
summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart Y.
v. Recordkeeping
In addition to the records required by
the General Provisions (40 CFR 98.3(g))
and summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
Y.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart Y: Petroleum
Refineries.’’
• The minimum monitoring
frequency for flare gas heat value or
carbon content was changed to weekly
from daily. (For background on the
selection of a weekly frequency, see
memorandum entitled: ‘‘Uncertainty in
Flare Estimates Based on Sampling
Frequency’’ in the docket.) Engineering
calculations are allowed in the final rule
for reporters that do not monitor flare
gas flow continuously or flare heating
value or carbon content at least weekly.
• The minimum monitoring
frequency for refinery fuel gas carbon
content and molecular weight was
changed to weekly from daily in 40 CFR
part 98, subpart C for reporters that do
not have continuous monitoring
equipment, and we clarified in 40 CFR
part 98, subpart Y that common (fuel)
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pipe monitoring is allowed for
petroleum refineries.
• We added a flare combustion
efficiency of 98 percent, and we revised
the equation for flare CH4 emissions to
account for uncombusted methane.
• The final rule allows engineering
calculations to determine CO2 emissions
for catalytic cracking units and fluid
coking units below 10,000 bbl/stream
day that do not have CO2/CO/O2
monitors already installed.
• The delayed coking unit
depressurization emission equations
and asphalt blowing equations were
amended to address comments received.
• We added concentration thresholds
for CO2, CH4 and N2O from process
vents below which GHG emissions are
not required to be calculated and
reported.
• The reporting requirements were
updated to facilitate the emissions
verification process.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on petroleum
refineries were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart Y: Petroleum
Refineries.’’
Definition of Source Category
Comment: Several commenters
expressed concern that EPA defined a
Petroleum Refinery so broadly that it
could be interpreted to include
chemical facilities that use petroleumbased materials as raw materials. Of
particular concern was the term ‘‘* * *
and other products * * *’’ which many
commenters interpreted to include the
manufacture of chemicals, synthetic
rubber, and a variety of plastics. One
commenter also requested clarification
that ‘‘other products’’ did not include
sulfur, ammonia, or hydrogen sulfide.
Several commenters requested
clarification that the definition of
petroleum refineries did not include
lube oil production or fuel blending
operations if the products were
produced without distilling, redistilling,
cracking, or reforming of the petroleum
derivatives.
Response: We have revised and
clarified the definition of petroleum
refinery to list a few additional refinery
products (specifically gasoline blending
stocks and naphtha) and deleted the
term ‘‘or other products.’’ We believe
that this change clarifies that companies
that use petroleum derivatives to make
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only petrochemicals, plastics, synthetic
rubber, sulfur, or any other product
other than those specifically listed are
not considered petroleum refineries. We
feel the definition also clearly excludes
lube oil manufacturing provided the
lube oil manufacturer does not distill,
redistill, crack, or reform the petroleum
derivatives at the facility.
Comment: Numerous commenters
requested that many of the emission
sources for which 40 CFR part 98,
subpart Y required reporting were small
and should not have to be reported.
Several commenters noted that EPA’s
TSD for the Petroleum Refining Sector:
Proposed Rule for Mandatory Reporting
of Greenhouse Gases, indicates that 92.9
percent of the refining sector’s GHG
emissions come from two sources,
combustion and catalytic coke
operations. The remaining 7.1 percent of
emissions come from eight distinct
categories, including: Hydrogen plants
(2.7 percent); Sulfur Plants (1.9 percent);
Flaring (1.6 percent); Wastewater
Treatment (0.43 percent); Blowdown
(0.18 percent); Asphalt Blowing (0.10
percent); Delayed Coking (0.058
percent); Equipment Leaks (0.014
percent); Storage Tanks (0.007 percent);
and Cooling Towers (0.003 percent).
The commenters argued that the burden
associated with the collection of data as
prescribed in the proposed rule is not
warranted for small sources and/or not
consistent with EPA’s stated intended
purpose of the rule which is to support
analysis of future policy decisions.
Response: The TSD estimates are
based largely on engineering estimates
without significant supporting data. For
the smaller sources, we have provided
very simple methods to calculate the
GHG emissions from these sources to
minimize the monitoring,
recordkeeping, and reporting burden
associated with these sources when no
measurement data are available.
However, requiring reporting for these
sources will provide EPA with valuable
data to better characterize them and
provide a better record upon which to
formulate decisions regarding whether
to include or exclude these sources from
future GHG policy decisions.
Additionally, while some of these
sources are currently believed to be
small compared to the larger sources
present at petroleum refineries, they are
not necessarily insignificant. The
inclusion of reporting data for these
sources is critical to support analysis of
future policy decisions for petroleum
refineries.
Comment: Several commenters
objected to the mandatory reporting of
CH4 and N2O emissions within the
Petroleum Refinery source category.
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Many commenters cited the TSD, which
indicated that N2O emissions account
for 0.09 percent of the GHG emissions
and CH4 account for only 0.87 percent
of the GHG emissions. The commenters
argued that the measurement error for
the larger sources (stationary
combustion sources and catalytic
cracking unit coke burn-off) exceeds the
contributions of these sources. As such,
the commenters stated that the burden
associated with reporting these
emissions is not warranted and/or not
consistent with EPA’s stated intended
purpose of the rule which is to support
analysis of future policy decisions.
Response: The TSD estimates for CH4
and N2O are based largely on
engineering estimates without
significant supporting data. We
specifically require reporting of these
various GHGs to obtain better data by
which to support future policy analysis.
Moreover, EPA has pending before it a
petition to reconsider the recently
revised New Source Performance
Standard (NSPS) for petroleum
refineries asking EPA to reconsider,
among other things, whether to establish
GHG standards under section 111 for
refineries. As such, we have a keen
interest in obtaining improved GHG
emissions data in order to better analyze
policy options. For instance, refineries
are a significant source of NOX
emissions, but we have no data to
determine the fraction of NOX that is
N2O. With the increased use at
refineries of NOX control devices, such
as low-NOX burners, low excess air,
selective catalytic reduction (SCR)
systems, and selective non-catalytic
reduction (SNCR) systems, it seems
plausible that N2O may be a more
significant portion of a refinery’s NOX
emissions. Thus, if a facility has
measurement data for a source, the
reporting of these data are important for
better understanding the impact of
current and future policy options.
Consequently, we have provided
additional alternatives that allow the
use of measured N2O (and CH4)
emissions or site-specific emission
factors in addition to the default factors.
Nonetheless, we have provided very
simple default methods to calculate the
emission of these GHGs when
measurement data are not available.
While emissions of CH4 and N2O may
not be large comparatively, the reporting
method for these pollutants is
straightforward and commensurate with
the anticipated emissions contribution.
Method for Calculating GHG Emissions
Comment: Several comments objected
to the requirements for flares,
particularly the requirements for SSM
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56325
events. Some commenters also stated
that daily sampling was too
burdensome. The commenters suggested
that flare emissions be dropped from the
rule or that refineries be allowed to
perform a one-time calculation. One
commenter noted that the proposed
equation did not account for flare
combustion efficiency, which was
inconsistent with other subparts, and
recommended that a flare efficiency
factor be added to the equation to
calculate the CO2 emissions from flares.
Response: EPA needs accurate data on
flare emissions to better understand this
emission source, as flare use can vary
significantly from day-to-day and yearto-year. Use of flares is too episodic and
variable to allow a one-time calculation.
However, we recognize that flares may
contribute about two percent of a
refinery’s GHG emissions. Therefore, we
sought to reduce the burden associated
with the flare monitoring and reporting
requirements. As proposed, special
calculations for SSM events were only
required if daily measurement data were
not available. In this final rule, we allow
weekly monitoring of flare use without
triggering special SSM event
calculations, which should lessen the
burden associated with calculating flare
emissions while not significantly
changing the accuracy of the data.
Additionally, we included a threshold
flaring rate of 500,000 scf/day for SSM
events. Only SSM events exceeding this
gas flare rate require special SSM
calculations in the final rule. Some
consent decree requirements and State
rules require root cause analysis and
quantification of emission events
exceeding 500,000 scf/day. We consider
events of this magnitude to be
significant and believe a separate
analysis is justified in addition to the
procedures that apply to routine
operation. We have also revised the
equations for CO2 and CH4 to account
for flare combustion efficiency.
Monitoring and QA/QC Requirements
Comment: Several commenters argued
that the monitoring and QA/QC
requirements were excessive and that
EPA significantly underestimated the
costs associated with complying with
the reporting requirements under 40
CFR part 98, subpart Y. One commenter
noted that existing facility CO2 CEMS,
HHV monitors, carbon content
monitors, and flow meters are not
necessarily for ‘‘regulatory’’ purposes
and thus may not meet the accuracy
requirements of the rule. The
commenter suggested many more
refineries would have to add or replace
monitors as a result of the rule. Many
commenters suggested EPA significantly
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underestimated the labor hours required
to collect and analyze daily samples as
well as to develop and implement a QA
plan. Various commenters supplied
labor or cost estimates for various
requirements in the rule, including costs
of implementing an LDAR program and
flare SSM calculations. Several
commenters stated that the requirement
to use a CEMS for monitoring CO2 from
the catalytic cracking unit was
expensive and burdensome, especially
for small refineries that do not have a
CEMS infrastructure.
Response: We have significantly
revised our rule requirements for
petroleum refineries and stationary
combustion sources to reduce burden to
the industry. We have provided in the
final rule (in 40 CFR part 98, subpart C)
a default emission factor for refinery
(still) gas to allow combustion sources
that combust refinery gas and meet the
applicability requirements in 40 CFR
part 98, subpart C to use Tier 2 methods.
For sources that do not meet the Tier 2
requirements, weekly monitoring for
refinery fuel gas under Tier 3 (40 CFR
part 98, subpart C) and for flare gas (40
CFR part 98, subpart Y) is allowed. We
have also re-assessed our costs based on
the comments received and increased
the labor hours estimated to collect and
analyze samples, develop QA plans, and
to perform QA/QC of existing
equipment. We did review our QA/QC
requirements and see no validity to the
argument that our QA/QC requirements
are so stringent that refineries will have
to replace existing monitors to comply
with the rule. While we note that some
cost elements suggested by commenters
are relevant and have been addressed in
the changes in the labor estimates for
sampling, analysis, and QA/QC as
described above, other cost elements
suggested by commenters are not
relevant. For example, revisions of
LDAR programs are not required under
the rule; the proposed and final rule
specifically provides a simple processbased emission factor approach for
estimating CH4 emissions from
equipment leaks. We are cognizant that
refineries with small catalytic cracking
units are most likely to elect a
compliance option under 40 CFR part
63, subpart UUU that does not require
monitoring of coke burn-off, so these
small refineries are most likely the
facilities that would have been required
to install monitoring equipment under
the proposed rule. After reviewing these
costs and impacts on the small
refineries, we have allowed engineering
calculations to determine CO2 emissions
for catalytic cracking units below 10,000
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bbl/stream day that do not have CO2/
CO/O2 monitors already installed.
Even though we have reduced the
stringency of the rule in many places,
our revised cost estimates indicate that
the average cost per refinery is
approximately 60 percent higher than
projected at proposal. We believe our
revised refinery costs accurately portray
the burden associated with the final
reporting requirements in 40 CFR part
98, subpart Y. Nonetheless, we continue
to believe that the costs are reasonable
for this rule, especially considering that
petroleum refineries are among the
larger sources of GHG emissions in the
U.S.
Z. Phosphoric Acid Production
1. Summary of the Final Rule
Source Category Definition. The
phosphoric acid production source
category consists of facilities that use a
wet-process phosphoric acid process to
produce phosphoric acid. A wet-process
phosphoric acid process line is any
system that manufactures phosphoric
acid by reacting phosphate rock and
acid and is usually identified by an
individual identification number in a
CAA operating permit.
Reporters must submit annual GHG
reports for Facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Report CO2
emissions from each wet-process
phosphoric acid process line.
In addition, report GHG emissions at
each facility for other source categories
for which calculation methods are
provided in the rule, as applicable. For
example, report CO2, N2O, and CH4
emissions from each stationary
combustion unit on site under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources).
GHG Emissions Calculation and
Monitoring. Calculate process emissions
of CO2 using one of two methods, as
appropriate:
• Most reporters can elect to either (1)
install and operating CEMS and follow
the Tier 4 methodology (in 40 CFR part
98, subpart C) or (2) calculate CO2
emissions based on monthly
measurements of the mass of phosphate
rock consumed and inorganic carbon
content of each grab sample of
phosphate rock.
• However, if process CO2 emissions
from phosphoric acid production are
emitted through the same stack as a
combustion unit or process equipment
that uses a CEMS and follows Tier 4
methodology to report CO2 emissions,
then the CEMS must be used to measure
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and report combined CO2 emissions
from that stack. In such cases, the
reporter cannot use the CO2 calculation
methodology outlined in approach (2) in
the previous bullet.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart Z.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
Z.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart Z:
Phosphoric Acid Production.’’
• The rule was revised to allow the
use of techniques from Part 60 and Part
63 for calculating the weight of
phosphorous-containing rock.
• The missing data provisions were
revised to allow the use of default
inorganic carbon content values based
on the origin of the phosphorouscontaining rock, in addition to
determining missing inorganic carbon
contents of phosphate rock consumed
using an arithmetic average of measured
values from of inorganic carbon
contents of phosphate rock of the
appropriate origin preceding and
following the missing data incident.
• 40 CFR 98.266 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.267 to 40 CFR 98.266, and some data
elements that are already used to
calculate GHG emissions as specified in
40 CFR 98.263 were added to 40 CFR
98.266 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses.
Several comments on phosphoric acid
production were received covering
numerous topics shown below.
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Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
Z: Phosphoric Acid Production.’’
Selection of Threshold
Comment: Multiple commenters
asked that phosphoric acid production
units not be included as an ‘‘all-in’’
category. According to the commenters,
the facilities are very minor sources of
GHG emissions. The commenter
conceded that most (if not all) would
still fall within the reporting threshold
requirement, but asserted that it was
unnecessary to include all phosphoric
acid production units as regulated
facilities regardless of the amount of
emissions. The commenters stated that
EPA inaccurately suggests that these
units are major emitters of GHGs which
could have significant impacts on these
minor sources.
Response: We acknowledge the
comments and concerns; however the
final rule retains the ‘‘all-in’’
applicability requirement for this source
category. The ‘‘once in, always in’’
provision has been removed. The final
rule now contains provisions to cease
reporting if annual reports demonstrate
emissions less than specified levels for
multiple years. These provisions apply
to all reporting facilities, including
those with phosphoric acid production
processes. The purpose of this rule is to
collect information on emissions
sources for future policy development.
Requiring reporting for these sources
will provide EPA with valuable data to
better characterize GHG emissions from
phosphoric acid production and provide
a more credible position if EPA elects to
exclude these sources from future GHG
policy analyses. We also believe that the
accurate assessment of the emissions
from phosphoric acid production will
address the commenters’ concerns about
potential future impacts.
Commenters may also be interested in
reviewing Section II.H of this preamble
for the response on provisions to cease
reporting.
Method for Calculating GHG Emissions
and Monitoring and QA/QC
Requirements
Comment: Multiple commenters
asked that production measurements in
this rule be consistent with the existing
MACT and NSPS regulations for the
phosphate industry. In these
regulations, production measurement is
determined by the mass of phosphate
feed (as P2O5). Two commenters stated
that the change would provide
consistency, and ensure a reporting
structure that fits with the actual
practices of the industry.
Response: We agree with the
commenters that consistency among
EPA regulations is important. Therefore,
the final rule allows for techniques from
part 60 and part 63 to calculate the
weight of phosphorous-containing rock.
This request is consistent with the
intent of the proposed rule. Under
existing regulations in part 60 and part
63, phosphoric acid manufacturing
facilities already measure the mass of
phosphorous bearing feed on a ton/hour
basis. This feed rate can be used to
determine monthly phosphate rock
consumption. Process CO2 emissions
from phosphoric acid production are
calculated from the total phosphate rock
consumption multiplied by the
inorganic carbon content of that rock.
Further, part 60 and part 63 establish
the appropriate monitoring and QA/QC
procedures for determining this feed
rate.
Procedures for Estimating Missing Data
Comment: Multiple commenters
asked that the final rule allow options
for missing data. The commenters asked
that the use of default carbon content
values based on the origin of the rock be
allowed if analytical data are
unavailable. In addition, commenters
requested that procedures be added for
measurement of the mass of phosphate
rock consumed, suggesting procedures
similar to those in 40 CFR part 98,
subpart C, the lesser of the maximum
capacity of the system, the maximum
rate the meter can measure, or best
56327
available estimate based on available
process data.
Response: We agree with the
commenters on this point. The final rule
has been changed to allow the use of a
default factor (by origin of the
phosphate rock) for each missing value
of the inorganic carbon content of
phosphate rock. Use of a default carbon
value in place of the missing data will
provide a reasonable estimate of the
total emissions from the facility and will
avoid assuming the maximum possible
facility emissions when no data are
available. These default values have
been added to the final rule in Table Z–
1 of 40 CFR part 98, subpart Z.
Missing data procedures have also
been added as suggested for missing
monthly estimates of the mass of
phosphate rock consumed consistent
with the later recommendation. Again
use of the best available data based on
all available process data will avoid
assuming the maximum possible facility
emissions when no data are available.
Facilities must document and keep
records of the procedures used for all
such estimates.
AA. Pulp and Paper Manufacturing
1. Summary of the Final Rule
Source Category Definition. This
source category consists of facilities that
produce market pulp (i.e., stand-alone
pulp facilities), manufacture pulp and
paper (i.e., integrated mills), produce
paper products from purchased pulp,
produce secondary fiber from recycled
paper, convert paper into paperboard
products (e.g., containers), or operate
coating and laminating processes.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Table AA–1 of this
preamble lists the GHG emission
sources at pulp and paper
manufacturing facilities for which GHG
emissions must be reported along with
the rule subpart that specifies the
calculation methodology.
TABLE AA–1—GHGS TO REPORT
Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ...
For pulp and paper mills ...
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CO2
Chemical recovery furnace at kraft and soda facilities .....................................
Chemical recovery combustion units at sulfite facilities ....................................
Chemical recovery combustion units at stand alone semi-chemical facilities ..
Lime kilns of kraft and soda facilities ................................................................
Makeup chemicals used in pulp mills ...............................................................
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C
C
C
AA/C
AA
Sfmt 4700
Biogenic
CO2
AA
AA
AA
AA
CH4
C
C
C
AA/C
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N2O
C
C
C
AA/C
Biogenic
CH4
Biogenic
N2O
AA
AA
AA
AA
AA
AA
AA
AA
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TABLE AA–1—GHGS TO REPORT—Continued
Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ...
For pulp and paper mills ...
Biogenic
CO2
CO2
Stationary combustion units ..............................................................................
C
C
CH4
C
N2O
C
Biogenic
CH4
Biogenic
N2O
C
C
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Key:
C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing).
AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and subpart C to determine default High Heating Values.
GHG Emissions Calculation and
Monitoring. Under 40 CFR part 98,
subpart AA, reporters must calculate
emissions from pulp and paper
manufacturing facilities as follows:
• Chemical recovery furnaces:
Calculate biogenic CO2 emissions from
combustion of biomass in spent pulping
liquor using:
—Measured quantities of spent liquor
solids fired, site-specific high heating
value (HHV), and default or sitespecific emission factors for each
chemical recovery furnace located at
kraft or soda facilities.
—Measured quantities of spent liquor
solids fired and the carbon content of
the spent liquor solids for each
chemical recovery unit at sulfite or
stand-alone semichemical facilities.
• Calculate CO2 emissions from fossil
fuels used in chemical recovery
furnaces using direct measurement of
fossil fuels consumed and default
emission factors according to the Tier 1
methodology for stationary combustion
sources in 40 CFR part 98, subpart C.
• Calculate CH4 and N2O emissions as
the sum of emissions from the
combustion of fossil fuels and the
combustion of biomass in spent
pulping liquor, as follows:
—For fossil fuel emissions, use direct
measurement of fuels consumed, a
default HHV, and default emission
factors according to the methodology
for stationary combustion sources in
40 CFR 98.33(c).
—For biomass emissions, use measured
quantities of spent liquor solids fired,
site-specific HHV, and default or sitespecific emission factors.
—Lime kilns at kraft and soda facilities.
• Lime kilns: Calculate CO2, CH4, and
N2O emissions from combustion 21 of
fossil fuels in pulp mill lime kilns using
direct measurement of fossil fuels
consumed and default emission factors
21 Biogenic CO from the conversion of CaCO to
2
3
CaO in kraft or soda pulp mill lime kilns is
accounted for in the biogenic CO2 emission factor
for the recovery furnace.
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and HHV found in 40 CFR part 98,
subparts AA and C, respectively.
• Makeup chemicals: Calculate CO2
emissions from the use of makeup
chemicals using direct or indirect
measurement of the quantity of
chemicals added and ratios of the
molecular weights of CO2 and the
makeup chemicals.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart AA.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
AA.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart AA: Pulp
and Paper Manufacturing.’’
• Language was added to clarify that
40 CFR part 98, subpart AA GHG
emissions are to be reported for makeup
chemicals added in the chemical
recovery areas of pulp mills (as opposed
to makeup chemicals used at paper
coating and laminating facilities).
• The frequency of measurements for
the spent liquor solids mass fired
(TAPPI Test Method T 650), heating
value (TAPPI Test Method T 684), and
carbon content (ASTM D5373–08) was
reduced from monthly to annually.
• An option to use data from existing
online solids meters to determine the
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annual mass of spent liquor solids fired
is provided (in lieu of conducting an
annual TAPPI Test Method T 650).
• The requirement to report quarterly
data was eliminated.
• The reporting requirements were
revised to specify units to standardize
inputs into the data reporting system.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
number of comments on pulp and paper
manufacturing were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart AA: Pulp
and Paper Manufacturing.’’
Definition of Source Category
Comment: Two commenters stated
that literal interpretation of 40 CFR part
98, subpart AA could require any
facility operating paper coating and
laminating processes to report emissions
for any system used to add makeup
chemicals. The commenters requested
that language be added to 40 CFR part
98, subpart AA to clearly exclude
facilities not intended to be covered and
which have not traditionally been part
of the pulp and paper source category.
Response: Definitions of terms used in
40 CFR part 98, subpart AA are
provided in 40 CFR 98.6 (in subpart A
of part 98). The definition of ‘‘makeup
chemicals’’ is specific to the chemical
recovery areas of pulp mills and serves
to limit the scope of the pulp and paper
subcategory. As defined in § 98.6
(emphasis added):
‘‘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.’’
‘‘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.’’
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mass of spent liquor solids with TAPPI
Test Method T 650.
Response: We disagree with
commenters that default fuel carbon
content and high heating values should
be allowed instead of measured values.
These parameters are already measured
by mills (though less frequently than
monthly) and thus are available for use
and more accurate than default values.
We are reducing the frequency of fuel
property measurements from monthly to
annual. There is little monthly variation
in fuel properties over the course of a
year. Therefore, annual measurements
are sufficient to develop site specific
emission factors. This change also
reduces the burden associated with
complying with the rule. These changes
have been incorporated throughout the
text and equations of 40 CFR part 98,
subpart AA.
In addition, the final rule allows use
of either an annual measurement of the
mass of spent liquor solids fired (with
TAPPI Test Method T 650) or use of
annual spent liquor solids data
calculated from continuous
measurements already performed for
process control purposes (e.g., with
existing online solids meters). If the
annual spent liquor solids fired is
determined using existing measurement
equipment, then reporters must retain
records of the calculations used to
determine the annual mass of spent
liquor solids fired from the continuous
measurements in order to demonstrate,
if necessary, that calculations where
done correctly. Reporters must also
document that these measurement
devices have been regularly and
properly calibrated according to the
manufacturer’s specifications.
Method for Calculating GHG Emissions
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Thus, we disagree that the rule could
be interpreted to require any facility
operating coating and laminating
processes to report emissions for any
system used to add makeup chemicals.
This was not the intent of the rule.
Nevertheless, we have added language
consistent with the definition of
‘‘makeup chemicals’’ to 40 CFR
98.270(b)(5) and 98.272(e) to further
clarify that GHG emissions are to be
reported for systems adding makeup
chemicals (CaCO3 and Na2CO3) in the
chemical recovery areas of pulp mills.
Comment: Commenters stated the rule
should include categorical exemptions
for emissions from the combustion of
non-condensable gases (NCG), stripper
off gases (SOG), tall oil and turpentine
(small sources of GHG that are difficult
to measure). The commenters noted that
these streams are of biogenic origin. One
commenter described safety issues
associated with sampling these gas
streams.
Response: Pulp mill NCG, SOG, tall
oil and turpentine were discussed in the
Proposed Rule TSD for the pulp and
paper manufacturing sector. The
Proposed Rule TSD noted that process
vent gases such as NCG and SOG and
the byproducts tall oil and turpentine
are derived from biomass. We
acknowledge the safety and
measurement issues described by
commenters regarding sampling of NCG
and SOG streams. No methods are
specified in the rule for calculation of
GHG associated with combustion of
NCG, SOG, tall oil and turpentine. Thus,
calculation of these emissions is not
required and there is no need for
categorical exemptions.
Data Reporting Requirements
Comment: One commenter noted that
presenting quarterly data in annual
reports for pulp and paper
manufacturing annual emissions,
consumption of biomass fuels, and
quantity of spent liquor solids fired is
unnecessary for an annual reporting
system.
Response: We have revised 40 CFR
98.276 and 98.277(a) to remove the
requirement for providing quarterly
details in the annual report. EPA agrees
that requiring quarterly details was not
necessary for ensuring the accuracy of
data reported annually.
Comment: One commenter requested
that the spreadsheets developed by the
National Council for Air and Stream
Improvement (NCASI) for the
International Council of Forest and
Paper Associations (ICFPA) be allowed
as an option for facilities subject to the
Rule to determine emissions. These
Comment: Commenters stated that
monthly measurements of the mass of
spent liquor solids, HHV, and carbon
content of spent liquor solids are
unnecessary. The commenters requested
that EPA either allow default fuel
carbon content and heating value for
spent pulping liquor, or reduce the
frequency of measurements to annually
or every two years. Commenters noted
that spent liquor HHV and carbon
content are measured from time to time
but less frequently than monthly. In
addition, one commenter pointed out
that chemical recovery furnaces often
have online solids meters installed to
provide continuous measurement of the
mass of spent liquor solids entering the
furnace for safety and process control
reasons. This commenter requested that
EPA allow use of such continuous
measurement devices instead of
requiring monthly measurement of the
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56329
spreadsheets segregate calculated GHG
emissions into fossil fuel and biogenic
categories. The commenter believes that
tools like those developed by NCASI
and others should be allowed as an
option for facilities subject to the
emission calculation requirements
imposed by 40 CFR 98.3. This
streamlined approach will provide the
Agency with valid GHG emission data
without imposing extraordinary capital
and labor burdens on the industry.
Response: The ICFPA/NCASI tools
were considered in developing the
requirements of the GHG reporting rule.
However, the ICFPA/NCASI
spreadsheets, though valuable tools, are
not broadly applicable to all industrial
sectors covered under the GHG
reporting rule, as are the monitoring,
reporting, recordkeeping, and emissions
verification requirements specified in 40
CFR 98.3. Additionally, these tools often
use default factors and estimates, which
differs from the approach proposed by
EPA. The data collected from all
subparts of the GHG reporting rule will
be tabulated in EPA’s electronic
reporting system. This system will be
used to verify emission calculations and
will require specific data be reported in
order to run the calculations used for
verification. The tools suggested by the
commenter, however, would only
provide a total emission number.
Consequently, EPA would not be able to
check the underlying calculations for
accuracy. The final GHG reporting rule
reflects the data reporting requirements
necessary for emissions verification by
EPA. Edits to the reporting and
recordkeeping language (40 CFR 98.276
and 98.277) of 40 CFR part 98, subpart
AA were made to clarify calculation
inputs and units of measure to be
reported. As part of the implementation
phase of today’s final rule, EPA intends
to prepare guidance documents to assist
the industry in complying with the
rule’s requirements. In recognition of
the fact that the pulp and paper industry
has been using the ICFPA/NCASI
spreadsheets, EPA will consider
including in the guidance materials a
comparison between these spreadsheets
and EPA’s electronic reporting system to
reduce the burden on the industry and
minimize confusion.
BB. Silicon Carbide Production
1. Summary of the Final Rule
Source Category Definition. The
silicon carbide production source
category consists of any process that
produces silicon carbide for abrasive
purposes.
Reporters must submit annual GHG
reports for facilities that meet the
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applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. Report process CO2
and CH4 emissions from all silicon
carbide production furnaces or process
units at the facility combined.
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable. For example,
report CO2, N2O, and CH4 emissions
from each stationary combustion unit on
site under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
GHG Emissions Calculation and
Monitoring. For CO2 emissions,
reporters must use one of the following
methods, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions from
silicon carbide production processes by
either (1) installing and operating CEMS
and following the Tier 4 methodology
(in 40 CFR part 98, subpart C) or (2)
calculating emissions using the
measured petroleum coke consumption
and a monthly facility-specific emission
factor. The facility-specific emission
factor is the carbon content of the
petroleum coke (provided monthly by
the supplier or measured monthly using
the appropriate test methods) adjusted
for carbon in the silicon carbide
product.
• However, if process CO2 emissions
from silicon carbide production are
vented through the same stack as a
combustion unit or process equipment
that uses a CEMS and follows Tier 4
methodology to report process CO2
emissions, then the CEMS must be used
to measure and report combined CO2
emissions from that stack. In such cases,
the reporter cannot use the CO2
calculation approach (2) outlined in the
above bullet.
For CH4 emissions, reporters must use
the measured petroleum coke
consumption and a default emission
factor of 10.2 kilograms (kg) per metric
ton of coke consumed.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart BB.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
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emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
BB.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart BB: Silicon
Carbide Production.’’
• The emissions calculation method
under 40 CFR 98.283(b) was revised to
require data on monthly petroleum coke
consumption and monthly petroleum
coke carbon contents rather than
quarterly determinations.
• Missing data procedures were
added under 40 CFR 98.285 for monthly
parameters used to calculate emissions,
including mass of petroleum coke, and
carbon contents of petroleum coke.
• 40 CFR 98.286 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.287 to 40 CFR 98.286, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.283 were added to 40 CFR
98.286 for clarity.
3. Summary of Comments and
Responses
No specific comments were received
pertaining to the proposed reporting
requirements for silicon carbide
production facilities. However, the
proposed rule did not clearly specify
how quarterly carbon contents should
be determined. This determination
should be made on a monthly basis as
proposed for other chemical production
processes where process emissions arise
from use of petroleum coke, such as
titanium dioxide production. Quarterly
reporting of carbon contents of
petroleum coke consumed for the
quarter would have to be averaged from
monthly data. For verification, EPA
would require reporting of the monthly
carbon contents of the petroleum coke.
Therefore, we revised the emissions
calculation method to directly require
monthly petroleum coke consumption
and monthly petroleum coke contents,
rather than quarterly based on an
arithmetic average of the monthly
estimates to improve accuracy of
emissions calculations. We have
retained the flexibility in use of supplier
data to determine carbon contents. We
understand that most supplier data on
carbon contents of petroleum coke is
readily available and that businesses
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track production inputs and outputs on
a monthly basis as a part of normal
business practice or existing accounting
procedures. The increased frequency of
data collection from quarterly to
monthly provides greater clarity and
accuracy without significantly
increasing burden. In addition, see the
Section II.N of this preamble for an
explanation of the emissions
verification approach.
CC. Soda Ash Manufacturing
1. Summary of the Final Rule
Source Category Definition. A soda
ash manufacturing facility is any facility
with a manufacturing line that produces
soda ash by either: calcining trona or
sodium sesquicarbonate; or by using a
liquid alkaline feedstock process that
directly produces CO2. In the context of
the soda ash manufacturing sector,
‘‘calcining’’ means the thermal/chemical
conversion of the bicarbonate fraction of
the feedstock to sodium carbonate.
Soda ash produced from a liquid
alkaline feedstock using sodium
hydroxide does not emit process CO2
and therefore is not subject to the
requirements of Subpart CC. However,
such facilities may be covered under
Subpart C (General Stationary
Combustion) if they meet the
requirements of either § 98.2(a)(1) or (2).
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For soda ash
manufacturing, report the following
emissions:
• CO2 process emissions from soda
ash manufacturing, reported for each
manufacturing line.
• CO2 combustion emissions from
each soda ash manufacturing line.
• N2O and CH4 emissions from fuel
combustion at each soda ash
manufacturing line under 40 CFR part
98, subpart C (General Stationary Fuel
Combustion Sources) using the
methodologies in subpart C.
• CO2, N2O, and CH4 emissions from
each stationary combustion unit other
than soda ash manufacturing lines
under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
In addition, report GHG emissions for
any other source categories at the
facility for which calculation methods
are provided in other subparts of the
rule, as applicable.
GHG Emissions Calculation and
Monitoring. For CO2 emissions from
soda ash manufacturing lines, reporters
must select one of the following
methods, as appropriate:
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• For each soda ash manufacturing
line with certain types of CEMS in
place, reporters must use the CEMS and
follow the Tier 4 methodology (in 40
CFR part 98, subpart C) to report under
the Soda Ash Manufacturing subpart (40
CFR part 98, subpart CC) combined
process and combustion CO2 emissions.
• For other soda ash manufacturing
lines, reporters can elect to either (1)
install and operate a CEMS and follow
Tier 4 methodology to measure and
report combined process and
combustion CO2 emissions or (2)
calculate CO2 process emissions using
the procedures specified in 40 CFR part
98, subpart CC and summarized below.
• If using approach 2, calculate
process CO2 emissions using one of
three alternative methods, as
appropriate for each manufacturing line:
—The trona input method calculates the
calcination emissions using: Monthly
mass of trona input (required to be
measured), the average monthly massfraction of inorganic carbon in the
trona (required to be measured
weekly), and the ratio of CO2 emitted
for each ton of trona consumed (a
default value is provided).
—The soda ash output method
calculates the calcination emissions
using: Monthly mass of soda ash
produced (required to be measured),
the monthly average mass-fraction of
inorganic carbon in the soda ash
(required to be measured weekly), and
the ratio of CO2 emitted for each ton
of soda ash produced (a default value
is provided).
—The site-specific emission factor
method calculates emissions from
production of soda ash using liquid
alkaline feedstock through an annual
performance test using: The average
process vent flow rate from the mine
water stripper/evaporator for each
manufacturing line, direct
measurements of hourly CO2
concentration, the hourly stack gas
volumetric flow rate, the annual
process vent flow rate from mine
water stripper/evaporator, and annual
operating hours.
—Report process CO2 emissions from
each soda ash manufacturing line
under 40 CFR part 98, subpart CC
(Soda Ash Manufacturing), and report
combustion CO2 emissions from each
calciner (kiln) in each manufacturing
line under 40 CFR part 98, subpart C
(General Stationary Fuel Combustion
Sources).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
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additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart CC.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
CC.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart CC: Soda
Ash Manufacturing.’’
• A site-specific emission factor
method has been added for production
of soda ash using liquid alkaline
feedstock or mine water. This method
was not included in the proposed rule.
• The frequency of inorganic carbon
content determination of either trona or
soda ash has been revised from daily to
monthly based on a weekly composite.
• Procedures were added to 40 CFR
98.295 for estimating missing data for
monthly values of inorganic carbon
content of trona and monthly values of
trona consumption or soda ash
production. We also added missing data
procedures for parameters specific to
calculating emissions from soda ash
produced from liquid alkaline feedstock
(i.e. site-specific emission factor
method).
• 40 CFR 98.296 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.297 to 40 CFR 98.296, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.293 were added to 40 CFR
98.296 for clarity.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. Two
sets of comments on soda ash
manufacturing were received covering
several topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart CC: Soda Ash
Manufacturing.’’
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Method for Calculating GHG Emissions
Comment: Both commenters noted
that facilities produced soda ash using
alternative methods to calcining trona or
other carbonate containing minerals.
Facilities also produce soda ash from
mine water, a liquid alkaline feedstock;
this is a ‘‘process’’ emissive production
process, but was not addressed in the
proposal. The methods in the proposal
did not include methods appropriate for
calculating process CO2 from the liquid
alkaline feedstock production process.
One commenter using this production
method recommended that the
appropriate method for calculating
emissions from this process would be an
annual performance test and described
the appropriate parameters that would
be measured during the annual
performance test to establish an
emission factor for calculating annual
emissions based on concentration of the
CO2 in the evaporated stripped mine
water and the annual flow from the
mine water stripper/evaporator.
Response: We agree that the final rule
should address process CO2 emissions
generated from this relatively new
alternative production process which
produces soda ash from liquid alkaline
feedstock or mine water. From
additional information provided by the
commenter, process CO2 emissions from
this production method are likely to be
significant and exceed 25,000 metric
tons CO2e. This process is currently
used by a single company, but could
become more widespread within the
industry in the future as it makes more
efficient use of raw materials previously
not used. We have updated all sections
of 40 CFR part 98, subpart CC for
calculating, monitoring and QA/QC, and
reporting of process CO2 emissions
specific to production of soda ash from
liquid alkaline feedstock or minewater.
We added procedures for developing
site-specific emission factor based on an
annual performance test consistent with
the recommendations provided by the
commenter.
Comment: One commenter noted that
using the total alkalinity of either trona
or soda ash as prescribed in Equations
CC–2 and CC–3 is inappropriate given
that the ratio of carbon dioxide to
carbon is a factor in the equations. The
equations’ results artificially inflated the
CO2 level by 3.67 times the actual
amount.
Response: Upon further review, we
agree with the commenter’s analysis
that the ratio 44/12 will overestimate
emissions and have removed this
fraction, which is the ratio of carbon
dioxide to carbon, from Equations CC–
2 and CC–3. Equations CC–2 and CC–3
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provide results directly for CO2
therefore it is not necessary to use a
conversion factor to convert the carbon
to carbon dioxide.
Comment: One commenter noted that
Equation CC–3 does not address plant
inefficiency specific to each
manufacturing line. The commenter
suggested that an efficiency factor
should be added to Equations CC–3 to
account for these inefficiencies.
Response: The commenter has not
suggested an efficiency factor or
otherwise provided data with enough
specificity to modify the equations and
modify the calculation methods as
suggested; therefore, we have decided
not to add efficiency factors to
Equations CC–3.
EPA needs more information to
effectively evaluate this comment and
update the equations noted, if
appropriate. Efficiency factors can relate
to a number of factors including
combustion and also kiln conditions,
which may vary. We need more
information to understand how this
factor would be derived for each kiln or
manufacturing line. The comment was
specific to CC–3, and we suggest the use
of Equation CC–2 as an alternative
calculation method.
Monitoring and QA/QC Requirements
Comment: One commenter stated that
daily sampling of inorganic carbon
content of each manufacturing line is an
unnecessary and potentially extremely
costly requirement. They suggested that
instead of daily testing, testing should
be completed as a weekly composite
analysis which would then be used in
calculating the monthly average.
Response: We concur that testing of
the inorganic carbon content can be
done on a weekly schedule and used to
calculate a monthly composite without
significant loss in accuracy. The weekly
composite would still be based on
several daily tests. We have updated the
monitoring and QA/QC requirements
accordingly in the rule under 40 CFR
98.294.
Comment: One commenter stated that
the prescribed ASTM method, ASTM
E359–00(2005), for determining the
inorganic carbon content of trona or
soda ash describes a manual titration
method using a methyl orange endpoint.
They stated that procedures that use
autotitrators with fixed endpoint
titration are commonly used in the soda
ash manufacturing industry and should
be allowed as an acceptable equivalent
alternative.
Response: We agree that methods
using autotitration to determine
inorganic carbon content of trona or
soda ash expressed as total alkalinity are
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acceptable equivalent methods for
determining the inorganic carbon
content of trona or soda ash. We
understand that manual titration offers
good levels of accuracy but are labor
and time intensive. From our
understanding, autotitration methods
provide comparable or improved levels
of accuracy and are less labor and time
intensive by ‘‘automating’’ the analysis
process. Autotitration methods could
provide more consistency in results
across the industry. We have updated
the procedures in 40 CFR 98.294 for
monitoring and QA/QC in the rule to
allow for such comparable methods.
DD. Sulfur Hexafluoride (SF6) From
Electrical Equipment
At this time EPA is not going final
with the electrical equipment subpart.
As we consider next steps, we will be
reviewing the public comments and the
relevant information.
Based on careful review of comments
received on the preamble, rule, and
TSDs under 40 CFR part 98, subpart DD,
EPA will perform additional analysis
and evaluate a range of data collection
procedures and methodologies. EPA’s
goal is to optimize methods of data
collection to ensure data accuracy while
considering industry burden. In
addition, EPA will further evaluate the
scope of coverage of electric power
systems and the reporting boundaries in
other subparts.
EE. Titanium Dioxide Production
1. Summary of the Final Rule
Source Category Definition. The
titanium dioxide production source
category consists of any facility that
uses the chloride process to produce
titanium dioxide.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For titanium dioxide
production, report CO2 process
emissions from each chloride process
line.
In addition, report GHG emissions for
other source categories for which
calculation methods are provided in the
rule, as applicable. For example,
facilities must report CO2, N2O, and CH4
emissions from each stationary
combustion unit on site under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources).
GHG Emissions Calculation and
Monitoring. Reporters must calculate
CO2 process emissions using one of two
methods, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions from
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titanium dioxide process lines by either
(1) installing and operating CEMS and
following the Tier 4 methodology (in 40
CFR part 98, subpart C) or (2) using the
calculation procedures specified below.
• However, if process CO2 emissions
from titanium dioxide production are
emitted through the same stack as a
combustion unit or process equipment
that uses a CEMS and follows Tier 4
methodology to report CO2 emissions,
then the reporter must use the CEMS to
measure and report combined CO2
emissions from that stack instead of
using the calculation procedures
described below.
• If using approach #2, calculate the
process CO2 emissions using the
equation provided 40 CFR part 98,
subpart EE and monthly determination
of the mass and carbon content of
calcined petroleum coke consumed in
each line and all lines combined.
Determine petroleum coke consumption
by either direct measurement or
purchase records. Determine carbon
content of petroleum coke using
supplier data or measurement using
appropriate test methods. If applicable,
also determine the quantity of carbon
containing waste generated and its
carbon contents using direct
measurement.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart EE.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
EE.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart EE: Titanium
Dioxide Production.’’
• Requirements were added for
reporting of carbon-containing waste
generated from less than 100 percent
oxidation of coke during the titanium
production process. 40 CFR 98.316
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allows for reporting of quantity of
carbon-containing waste generated and
associated carbon contents.
• Missing data procedures were
added under 40 CFR 98.315 for monthly
parameters used to calculate emissions,
including mass of calcined petroleum
coke, mass of carbon-containing waste,
and carbon contents of calcined
petroleum coke.
• 40 CFR 98.316 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.317 to 40 CFR 98.316, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.313 were added to 40 CFR
98.316 for clarity.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. We
received three sets of comments on
titanium dioxide production covering
several topics. Several of these
comments were directed at the
requirements for General Stationary
Fuel Combustion Sources in subpart C,
and responses to those comments are
provided in the preamble section
dealing with that source category.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
EE: Titanium Dioxide Production.’’
Method for Calculating GHG Emissions
Comment: One commenter noted that
the carbon oxidation factor for calcined
petroleum coke is not always 100
percent. They point out that the
calcined petroleum coke comes with
impurities, and a certain amount of the
calcined coke is returned to the ground
as landfill along with components such
as the un-converted TiO2. Thus, they
suggest that EPA should revise the
carbon oxidation factor to allow
facilities to use the most appropriate
factor for their process, with supporting
documentation of its derivation
available for EPA review as needed.
Response: EPA has considered the
comment but maintains the assumption
of 100 percent oxidation across all
sectors in the final rule. Data reporting
requirements have been added to 40
CFR 98.316 to collect information on the
quantity of carbon-containing waste
generated that is landfilled and its
carbon contents which are not emitted.
This information will help inform future
methods for calculating process
emissions from titanium dioxide
production (e.g., how to address
oxidation rates). EPA interpreted that
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this comment may also be applicable to
carbon content of calcined petroleum
coke. EPA agrees that carbon content
may not always be 100 percent and
therefore has revised the rule to allow
facilities to use supplier data or
determine carbon contents using
appropriate test methods as part of
calculating emissions in 40 CFR 98.313.
Procedures for Estimating Missing Data
Comment: Two commenters noted
there can be numerous reasons data may
not be available, on time, or in the
format EPA requires. In cases where a
required record is found to be missing
or determined to be incorrect, the
commenters requested that EPA should
provide a procedure for estimating
missing data.
Response: We concur that there may
be circumstances where data on carbon
contents of coke and petroleum coke
consumption may be missing. Records
could be misplaced or lost. Thus, we
have revised the rule and added specific
procedures for estimating missing data
in 40 CFR 98.315. These procedures are
consistent with those allowed across the
rule for similar parameters. For
example, if a facility is missing data on
carbon contents of petroleum coke we
allow facilities to allow sources to
substitute the missing data with another
quality assured parameter, such as the
arithmetic average of the carbon
contents from the month immediately
preceding and the month immediately
following the missing data incident.
Data Reporting Requirements
Comment: All commenters noted they
are concerned that the level of
information to be reported, which is
considered available for public
distribution, could put the domestic
TiO2 producers at a disadvantage
relative to international producers. The
commenters do not believe that CBI
provisions briefly outlined in the
preamble are adequate to safeguard the
proprietary technical and financial
positions of titanium dioxide
production facilities. The annual
production of titanium dioxide, annual
amount of petroleum coke consumed,
and annual operating hours are
considered CBI and are unnecessary to
carry out the purposes of this proposed
regulation. This data should only be
available onsite or offsite (e.g., a
centralized location), or as requested for
security cleared EPA personnel and
their security cleared contractors where
a need is demonstrated for the purposes
of this inventory.
Response: EPA reviewed CBI
comments received across the rule (both
general and subpart-specific comments)
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56333
and our response is discussed in Section
II.R of this preamble and in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Legal
Issues.’’
In addition, see the Section II.N of
this preamble for the response on the
emissions verification approach. The
amount of petroleum coke consumed is
necessary to calculate annual process
CO2 emissions. Production capacity and
annual production of titanium dioxide
are required for EPA to verify annual
CO2 process emissions. These
parameters help EPA to determine
whether reported emissions are within a
reasonable range. EPA concurs that data
on operating hours can be retained as a
record and does not need to be reported
to EPA. It is not a parameter used in
calculating process CO2 emissions.
However, operating hours would help to
verify any anomalies in reported
emissions or supporting parameters
related to temporary closures for repairs
or maintenance. This data has been
moved to recordkeeping requirements in
40 CFR 98.317.
FF. Underground Coal Mines
At this time, EPA is not finalizing the
Underground Coal Mines Subpart (40
CFR part 98, subpart FF). As EPA
considers next steps, we will be
reviewing the public comments on the
proposal preamble, rule and TSDs for
proposed 40 CFR 98 Subpart FF and
other relevant information. EPA will
perform additional analysis and
consider alternatives to the monitoring
requirements.
GG. Zinc Production
1. Summary of the Final Rule
Source Category Definition. Zinc
production facilities consist of zinc
smelters and secondary zinc recycling
facilities.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For zinc production,
report the following:
• CO2 process emissions from each
Waelz kiln and electrothermic furnace
used for zinc production.
• CO2, N2O, and CH4 combustion
emissions from each Waelz kiln and
each other stationary combustion unit
on site under 40 CFR part 98, subpart
C (General Stationary Fuel Combustion
Sources).
In addition, report GHG emissions for
other source categories at the facility for
which calculation methods are provided
in the rule, as applicable.
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GHG Emissions Calculation and
Monitoring. Facilities must calculate
CO2 process emissions using one of two
methods, as appropriate:
• Most reporters can elect to calculate
and report process CO2 emissions from
each Waelz kiln and electrothermic
furnace by either (1) installing and
operating CEMS and following the Tier
4 methodology (in 40 CFR part 98,
subpart C) or (2) using the calculation
procedures specified in the rule.
• However, if process CO2 emissions
from a Waelz kiln or electrothermic
furnace are emitted through the same
stack as a combustion unit or process
equipment that uses a CEMS and
follows Tier 4 methodology to report
CO2 emissions, then the CEMS must be
used to measure and report combined
CO2 emissions from that stack, instead
of the calculation procedure described
below.
• If using approach #2, calculate
process CO2 emissions by determining
on an annual basis the total mass
(metric tons) of carbon-containing input
materials (i.e., zinc-bearing material,
flux, electrodes, and any other
carbonaceous materials) introduced into
each kiln and furnace and the carbon
content of each material. Determine
carbon content annually either by using
supplier data, or by direct measurement
using appropriate test methods.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart GG.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
GG.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these changes can be found
below.
• The carbon input method was
revised to require an annual analysis of
all process inputs and outputs for
carbon content rather than monthly
sampling and monthly analysis.
• A de minimis was added to exclude
accounting for carbon-containing
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materials contributing less than one
percent of the total carbon into Waelz
kiln or electrothermic furnaces. These
materials do not need to be included in
carbon mass balance calculations.
• 40 CFR 98.336 was reorganized and
updated to improve the emissions
verification process. Some data
elements were moved from 40 CFR
98.337 to 40 CFR 98.336, and some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.333 were added to 40 CFR
98.336 for clarity.
3. Summary of Comments and
Responses
No comments specific to regulation of
the zinc production sector were
received. We revised the frequency of
sampling and analysis of carbon
contents for carbon containing input
materials from monthly to annual
consistent with revisions made in
response to comments for similar
production processes (e.g., emissions
from metal production, see the preamble
Section III.Q for iron and steel for
specific responses to comments). These
revisions reduce the reporting burden
for zinc production facilities. We
understand that the carbon content of
material inputs does not vary widely at
a given facility for the significant
process inputs that contain carbon, and
we continue to account for variations
due to changes in production rate,
which is likely a more significant source
of variability.
HH. Municipal Solid Waste Landfills
1. Summary of the Final Rule
Source Category Definition. This
source category consists of municipal
solid waste (MSW) landfills that
accepted waste on or after January 1,
1980. The source category includes the
MSW landfill, landfill gas collection
systems, and landfill gas destruction
devices (including flares) at the landfill.
This source category does not include
hazardous waste, construction and
demolition, or industrial landfills.
Reporters must submit annual GHG
reports for facilities that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble.
GHGs to Report. For MSW landfills,
report the following:
• Annual CH4 generation and CH4
emissions from the landfill.
• Annual CH4 destruction (for
landfills with gas collection and control
systems).
• Annual CO2, CH4, and N2O
emissions from stationary fuel
combustion devices under 40 CFR part
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98, subpart C (General Stationary
Combustion Sources).
GHG Emissions Calculation and
Monitoring. All facilities must calculate
modeled annual CH4 generation based
on:
• Measured or estimated values of
historic annual waste disposal
quantities; and
• Appropriate values for model
inputs (i.e., degradable organic carbon
fraction in the waste, CH4 generation
rate constant). Default parameter values
are specified for bulk municipal waste
and individual waste categories.
Facilities that do not collect and
destroy landfill gas must adjust the
modeled annual CH4 generation to
account for soil oxidation (CH4 that is
converted to CO2 as it passes through
the landfill cover before being emitted)
using a default soil oxidation factor. The
resulting value must be reported and
represents both CH4 generation and CH4
emissions.
Facilities that collect and control
landfill gas must calculate the annual
quantity of CH4 recovered and destroyed
based on either continuous or weekly
monitoring of landfill gas flow rate, CH4
concentration, temperature, and
pressure of the collected gas prior to the
destruction device.
Those facilities that collect and
control landfill gas must then calculate
CH4 emissions in two ways and report
both results. Emissions must be
calculated by:
1. Subtracting the measured amount
of CH4 recovered from the modeled
annual CH4 generation (with
adjustments for soil oxidation using the
default value and destruction efficiency
of the destruction device) using the
equations provided; and
2. Applying a gas collection efficiency
to the measured amount of CH4
recovered to calculate CH4 generation,
then subtracting the measured amount
of CH4 recovered (with adjustments for
soil oxidation using the default value
and destruction efficiency of the
destruction device) using the equations
provided. Default collection efficiencies
are specified, based on cover material
and other factors.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart HH.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
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summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
HH.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be founds below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart HH:
Landfills.’’
• Industrial landfills were removed
from the applicability provisions of 40
CFR part 98, subpart HH. The
applicability provisions were also
modified to exempt landfills that did
not accept any waste after January 1,
1980.
• Additional methods for estimating
quantities of waste for prior (historic)
years are provided.
• The requirement to continuously
monitor CH4 composition in the flare
gas was removed. If a continuous
monitoring system is in place, that data
must be used, but weekly sampling of
the gas is allowed if such a continuous
system is not in place.
• Direct flame ionization methods
were added to the rule as an alternative
to the gas chromatographic methods for
determining methane concentrations. To
use a direct flame ionization method, a
correction factor must be determined at
least once each reporting year and
applied to adjust the analyzer’s total
gaseous organic concentration to an
unbiased methane concentration.
• More detailed default values are
provided for landfill gas collection
efficiencies based on cover material and
other factors.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on landfills
were received covering numerous
topics. Responses to significant
comments received can be found in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart HH: Landfills.’’
Definition of Source Category
Comment: Several commenters stated
that EPA should limit the applicability
of the industrial landfills to landfills
located at food processing, pulp and
paper, and ethanol production facilities
(some also listed petroleum refineries)
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because these are the only industries for
which landfills were specifically called
out. Several commenters noted that
impacts were only estimated for pulp
and paper and food processing landfills,
so EPA should limit the rule to those
industries or correct the cost analysis to
reflect the true burden of the rule on
industrial landfills. Several commenters
noted that the reporting requirements
seemed tailored for MSW landfills and
were generally inappropriate for
industrial landfills (truck scales, etc.).
One commenter also noted that, if
reporting of GHG emissions from
industrial landfills is not limited to the
food processing, pulp and paper, and
ethanol production facilities, then EPA
should amend Table HH–1 of 40 CFR
part 98, subpart HH and provide
specific factors that are relevant to the
regulated industry. Several commenters
requested that EPA specifically exempt
inorganic chemical manufacturing and
mining landfills because they do not
contain organic waste; other
commenters suggested EPA delete
requirements for landfills in 40 CFR part
98, subpart Y because landfills are
insignificant compared to other sources
at a petroleum refinery.
On the other hand, one commenter
suggested that EPA may be overlooking
an important source of methane
emissions by excluding construction
and demolition landfills as it seems
possible that these landfills receive
organic materials such as wood or yard
waste that could degrade in an
anaerobic environment. This commenter
requested EPA provide information on
the waste composition of construction
and demolition landfills to explain more
fully the basis for its decision to
categorically exempt these sources from
GHG reporting requirements.
Response: At this time, EPA is not
going final with the industrial landfills
proposed requirements of this subpart.
In response to the proposal, EPA
received numerous detailed public
comments on the preamble, rule and
TSDs under 40 CFR part 98, subpart HH.
Comments addressed the
appropriateness, coverage, and
methodology for addressing GHG
emissions from industrial landfills. In
particular, commenters questioned
which industrial landfills should be
covered by the rule and the need for
industry specific factors and
methodologies for calculating and
reporting emissions. As EPA considers
next steps, we will be reviewing the
comments and other relevant
information and will perform additional
analysis and consider alternatives to the
proposed monitoring and reporting
requirements for industrial landfills.
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With regard to construction and
demolition landfills, we note that the
IPCC 2006 Guidelines for National
Greenhouse Gas Inventories estimates
that construction and demolition waste
has a degradable organic content (DOC)
of 0.04 kg/kg waste (see Table 2.5 in
Volume 5: Waste), and most of this
organic matter is expected to be wood,
with slow degradation rates (k=0.02
yr¥1). Based on the anticipated
properties of construction and
demolition wastes, we anticipated that
methane generation at dedicated
construction and demolition debris
landfills would be small compared to
MSW landfills. We will further review
these assumptions as we review
comments on industrial landfills.
Comment: Several commenters stated
that the reporting requirements for
closed landfills are burdensome, and the
rule should be limited to reporting for
active landfills. Information on waste
disposal quantities and waste
composition data are usually not
available for closed MSW facilities.
Thus, it is impossible to retain or
provide the agency with such records
for many old landfill sites. Several
commenters suggested that EPA should
provide additional guidance and
screening tools to identify landfills
likely to be below the threshold. The
commenters noted that small and closed
landfills have to collect all of the data
needed to report their emissions in
order to determine if they are above the
reporting threshold.
Response: Closed MSW landfills
account for approximately half of the
nationwide methane emissions from
MSW landfills. This is because landfills
can continue to emit for decades after
they are closed and because these
landfills are older, and less likely to
have been required to add landfill gas
collection systems. However, we do
agree that we can remove reporting
requirements for a subset of closed
landfills to lessen the burden on longclosed landfill facilities. We evaluated
the various landfill characteristics and
identified that a 30-year waste-in-place
(i.e., the total quantity of waste added to
the landfill in the past 30 years)
provided the best correlation of the data
to sites that account for the majority of
the contribution to the nationwide GHG
emissions from landfills (see
memorandum entitled ‘‘Correlations
with Landfill Methane Generation and
Actual Emissions’’ in the docket EPA–
HQ–OAR–2008–0508–2165). Providing
an applicability date for closed landfills
is essential to minimize the burden
associated with obtaining data on old
landfills that provide only a small
contribution to the nationwide GHG
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emissions for landfills, and landfills
closed prior to 1980 would not be
relevant for the purposes of policy
analyses. Therefore, the final rule
excludes MSW landfills that have not
accepted waste since January 1, 1980.
We have also expanded and clarified
options for projecting waste disposal
quantities that will help ease the burden
associated with calculating emissions
from landfills that have closed after
1980. EPA remains committed to
providing additional outreach materials,
guidelines, and screening tools to help
potential reporters determine whether
the reporting rule applies to their
landfill.
Method for Calculating GHG Emissions
Comment: Several commenters
requested additional guidance on how
to determine waste disposal rates for
years prior to the first reporting year.
One commenter noted that the
population method provided in the rule
was difficult for many landfills because
of contract carriers that may haul waste
to different landfills in different years,
so that the population served by a
landfill can be variable. Several
commenters noted that the data needed
to estimate waste disposal rates for past
years was especially challenging for
closed landfills and requested guidance
on how to comply with the rule if the
necessary data do not exist.
Response: EPA acknowledges that the
single proposed method of estimating
past year disposal rates is limiting and
may not provide the most accurate
projection of waste disposal rates in all
cases. We have provided a number of
alternative approaches that could be
used to estimate annual waste
acceptance rates. These include using
the current year’s annual waste
acceptance rate for all past years of
operation (for active landfills) and using
the landfill capacity and the operating
life of the landfill to calculate an
average annual acceptance rate (for
active and closed landfills). These
methods provide a reasonable estimate
of historic disposal quantities based on
readily available information, even for
older landfills. Furthermore, these
alternative methods may be just as
appropriate or more appropriate for
MSW landfills that do not serve a fixed
population area.
Comment: A few commenters noted
that the Solid Waste Industry for
Climate Solution (SWICS) has
developed protocols for calculating
GHG emissions from landfills [see paper
titled, Current MSW Industry Position
and State-of-the-Practice on LFG
Collection Efficiency, Methane
Oxidation, and Carbon Sequestration in
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Landfills (July 2007)]. The commenters
requested that the SWICS recommended
defaults for gas recovery system
efficiency, soil oxidation, and flare
combustion efficiency be provided in
the rule. They also stated that an
accurate inventory should account for
carbon sequestered in the landfill.
Response: We again reviewed the
SWICS methods in light of these
comments. We agree that the SWICS
default recommendations for gas
recovery system efficiency (which vary
from 60 to 95 percent for different types
of soil covers) could provide more
refined data than using the default
values provided in the rule. Therefore,
we have included these cover-specific
gas recovery efficiencies (commensurate
with the SWICS Protocol) as an
alternative to the 75 percent default
value for collection efficiency. We have
also reviewed the SWICS protocol for
soil oxidation, which provides
suggested oxidation factors ranging from
0.22 to 0.55 depending on the soil cover
type. We have several concerns with
these factors. First, the values were
calculated using arithmetic means
which appear to be biased high due to
a few high oxidation factors; the median
values were generally significantly
lower than the average values suggested.
Second, the recommended values
included laboratory test values, which
always yielded higher oxidation
fractions. The percent of methane
oxidized at the landfill surface is highly
dependent on the velocity of gas flow.
While areas of low flow are expected to
have significant oxidation, areas of high
flow will have little to no oxidation.
Landfill gas will generally flow to the
surface in fissures and channels that
offer the least resistance to flow.
Consequently, a significant portion of
the landfill gas is likely to exit the
landfill in a limited number of areas
under much higher flow rates than other
locations. These high volume flows will
not have significant oxidation.
Consequently, field test data tend to
show lower oxidation factors than
laboratory tests where flow is more
uniform. Data for five field studies for
clay covers (the predominant soil cover
type used in the U.S.) were included in
the SWICS report. Four of the five field
studies had oxidation factors ranging
from 0.08 to 0.21, and the median of all
five field studies was 0.14. These data
appear to support the default 0.10
oxidation factor as provided in the final
rule more than they do the 0.22
oxidation factor suggested by SWICS.
We will continue to assess the available
data to improve soil oxidation estimates;
however, we maintain that the use of
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the 10 percent default rate is
appropriate for this final rule, and
clarify that the site-specific oxidation
factors (based on the SWICS method or
other method) are not to be used. We
also find that the SWICS Protocol
recommended flare efficiency of 99.996
percent appears unreasonably high. The
combustion efficiency of flares is very
difficult to assess and may be affected
by wind speed and other variables that
are not under the direct control of the
landfill owner and operator.
Consequently, we retained the proposed
flare efficiency default. Finally, with
respect to the suggested sequestration
factors, since collecting data on carbon
sequestration is not the purpose of this
rule, we do not require facilities to
calculate or report carbon storage in
landfills.
Monitoring and QA/QC Requirements
Comment: Several commenters stated
that EPA’s proposal to require landfills
with gas collection systems to
continuously measure the methane flow
and concentration at the flare or energy
device is financially burdensome.
According to commenters, the capital
costs as well as operation and
maintenance costs of a continuous
composition analyzer are prohibitive for
many facilities, and EPA
underestimated the number of facilities
that would have to install the required
monitors. The commenters also stated
that the composition of landfill gas is
not highly variable, so less frequent
monitoring is justified. One commenter
noted that the standard operating
procedure at many landfills with gas
collection systems is to collect monthly
CH4, flow, and concentration data at the
flare. Another commenter recommended
that MSW landfills be allowed to
calculate quarterly, by means of
engineering formulae and/or modeling,
the amount of methane present at the
flare or energy device. The commenter
further noted that, in many cases, it is
not practical or even possible for the
MSW facility to measure the amount of
methane or even landfill gas at the
energy device because this device is not
owned, operated, or controlled by the
facility. Several commenters also
requested that EPA allow direct flame
ionization analyzers in addition to the
gas chromatography methods provided
in the proposed rule.
On the other hand, several
commenters suggested that EPA should
allow, require, or otherwise move
towards direct measurement
methodologies for characterizing
landfill emissions.
Response: Methane composition of
landfill gas can be expected to vary
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based on extreme barometric changes,
rainfall event, etc. We expect diurnal
variations as well (although not to the
same extent as seasonal variations). We
also expect variations if the gas
collection system has a variable speed
fan and the fan speed is adjusted. The
commenters provided no data to
support the claim that the anticipated
fluctuations are not significant enough
to warrant continuous monitoring. At
proposal, we required continuous flow
and composition monitors to improve
the accuracy of the emissions estimate.
However, after additional uncertainty
analysis, we determined that the cost of
continuous monitoring systems is not
justified in relation to the relatively
small improvement in certainty over
somewhat less frequent monitoring, i.e.
weekly. We do require landfill gas
collection systems already equipped
with continuous monitoring systems to
determine daily average flow and
concentrations and to use these data in
their gas recovery calculations. For
collection systems that do not have
continuous gas monitors, weekly
sampling is required. Weekly
monitoring provides an adequate
number of samples to evaluate the
variability and uncertainty associated
with methane generation. We did not
select monthly monitoring because
monthly monitoring would result in
greater uncertainty and would not
significantly reduce the costs compared
to weekly monitoring.
We did provide for direct flame
ionization analyzers to be used as an
alternative to the gas chromatography
methods provided in the proposed rule.
This alternative reduces the burden on
landfills that do not have existing gas
chromatography equipment. However,
direct flame ionization analyzers will
measure both methane and nonmethane organic compounds and, as
such, will tend to overstate the methane
concentration in the landfill gas and
provide a high bias to the amount of
methane recovered. To eliminate this
bias, we also required a correction factor
that must be determined at least
annually, to arrive at the ratio of the
methane concentration to the direct
flame ionization analyzer response
(calibrated with methane). Including
this alternative method with the
correction factor reduces the burden on
landfills, but still ensures that the
calculated methane recovery quantities
are unbiased and comparable to the
recovery quantities calculated when gas
chromatographic methods are used to
speciate methane specifically.
With respect to direct measurement
methods, we find that direct soil
measurements have high uncertainties
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due to heterogeneity of the landfill and
cover soils and are, therefore, less
desirable than the methods provided in
the rule (cost more and have higher
uncertainty). Optical sensing methods,
while potentially more accurate, are
very expensive. If measurements were
done for only a one-time performance
test, the measured emissions would
have rather high uncertainties due to
variations in temperature and
atmospheric pressure. If the
measurements were conducted more
often, they would be prohibitively
expensive. At this time, we cannot
justify requiring these types of
monitoring systems for this rule.
Furthermore, we find that the
monitoring requirements in the final
rule provide for accurate emission
estimates at a reasonable cost burden to
reporters.
II. Wastewater Treatment
At this time, EPA is not going final
with the wastewater treatment subpart
(40 CFR part 98, subpart II). As EPA
considers next steps, we will be
reviewing the public comments and
other relevant information. Please note,
as originally proposed for this rule,
centralized domestic wastewater
treatment plants continue to be
excluded.
The Agency received a number of
comments regarding the applicability of
this subpart as well as clarification of
the definition of anaerobic wastewater
treatment processes. In addition,
commenters requested that EPA
consider a de minimus exemption for
emissions from wastewater treatment.
The Agency also received a number of
comments requesting redefinition of the
monitoring requirements for this
subpart.
Based on careful review of comments
received on the preamble, rule and
TSDs under proposed 40 CFR part 98,
subpart II, EPA will consider
alternatives to data collection
procedures and methodologies and
examine additional study results that
have been released since the proposal
was issued. Specifically, EPA will
consider requirements for the location
of meters for taking flow measurements,
the frequency of flow and chemical
oxygen demand (COD) measurements
taken, as well as the potential use of
alternate parameters, such as BOD. EPA
will also consider the inclusion of
indirect or non-methane volatile organic
compound emissions. Lastly, EPA will
consider the acceptable methods for
estimating missing data. EPA will
consider optimal methods of data
collection in order to maximize data
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accuracy, while considering industry
burden.
JJ. Manure Management
1. Summary of the Final Rule
Source Category Definition. A
livestock facility that emits 25,000
metric tons CO2e or more per year from
manure management systems must
report. A facility with an average annual
animal population below those listed in
Table JJ–1 of 40 CFR part 98, subpart JJ,
does not need to calculate emissions or
report. A facility with an average annual
animal population that exceeds those
listed in Table JJ–1 should conduct a
more thorough analysis to determine
applicability. Average annual animal
populations for static populations (e.g.,
dairy cows, breeding swine, layers) are
estimated by performing an animal
inventory or review of facility records.
Average annual animal populations for
growing populations (meat animals such
as beef and veal cattle, market swine,
broilers, and turkeys) are estimated
using the average number of days each
animal is kept at the facility and the
number of animals produced annually.
The rule also contains procedures for
facilities with more than one animal
group present (e.g., swine and poultry)
to determine if they must report.
A manure management system
stabilizes or stores livestock manure, or
does both, in one or more of the
following system components:
• Uncovered anaerobic lagoons.
• Liquid/slurry systems with and
without crust covers (including but not
limited to ponds and tanks).
• Storage pits.
• Digesters, including covered
anaerobic lagoons.
• Solid manure storage.
• Drylots, including feedlots.
• High-rise houses for poultry
production (poultry without litter).
• Poultry production with litter.
• Deep bedding systems for cattle and
swine.
• Manure composting.
• Aerobic treatment.
GHG emissions from sources at
livestock facilities unrelated to the
stabilization and/or storage of manure
are not covered under this rule and are
not reported. Sources considered to be
unrelated to the stabilization and/or
storage of manure include daily spread
or pasture/range/paddock systems or
land application activities or other
methods of manure utilization not listed
above. In addition, manure management
activities located off site from a
livestock operation are not included in
this rule. These off site activities
include but are not limited to off site
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land application of manure, other off
site methods of manure utilization, or
off site manure composting operations.
Facilities that meet the applicability
criteria in the General Provisions (40
CFR 98.2) summarized in Section II.A of
this preamble must report GHG
emissions.
GHGs to Report. For all livestock
facilities with a manure management
system that meets or exceeds the
reporting threshold, the facility must
report aggregate CH4 and N2O emissions
from the system components listed
above. For those manure management
systems that include digesters, CH4
generated and destroyed, as well as any
CH4 leakage, at the digester must also be
reported.
A facility that is subject to this rule
only because of emissions from manure
management systems is not required to
report emissions under 40 CFR part 98
subparts C through PP other than
subpart JJ.
GHG Emissions Calculation and
Monitoring. Detailed methods for
calculating GHG emissions are included
in the rule and are briefly described
below. For each manure management
system component other than digesters,
facilities must calculate emissions using
the following inputs and data:
• Type of system component.
• Average annual animal population
(by animal type) contributing manure to
the manure management system
component.
• Typical animal mass (for each
animal type).
• Fraction of manure by weight for
each animal type managed in each
system component (assumed to be equal
to the fraction of volatile solids/nitrogen
handled in each system component).
• Volatile solids excretion rates
provided in look-up tables for the
animal populations contributing manure
to the manure management system
component.
• Maximum CH4-producing potential
of the managed manure and CH4
conversion factors provided in look-up
tables for the animal populations
contributing manure to the manure
management system component.
• Methane conversion factor used (for
each manure management system
component).
• Nitrogen excretion rates (by animal
type) using values provided in look-up
tables for the animal populations
contributing manure to the manure
management system component.
• N2O emission factors (by animal
type) provided in look-up tables for the
animal populations contributing manure
to the manure management system
component.
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For anaerobic digesters, facilities must
calculate CH4 emissions and the annual
mass of CH4 generated and destroyed
based on the following inputs and data:
• Continuous monitoring of CH4
concentration, flow rate, temperature,
and pressure of the digester gas.
• CH4 destruction efficiency of the
destruction device and fugitive (leakage)
emissions.
• The CH4 collection efficiency(ies)
used (for each digester).
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, facilities must submit
additional data that are used to calculate
GHG emissions. A list of the specific
data to be reported for this source
category is contained in 40 CFR part 98,
subpart JJ.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, facilities must keep records of
additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
JJ.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified below. The rationale for these
and any other significant changes can be
found below or in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Subpart
JJ: Manure Management.’’
• To assist facilities in determining if
they are subject to this rule, a table has
been provided that presents average
annual animal population values for
specific livestock operations (i.e., beef,
dairy, swine, and poultry). Facilities
that have average annual animal
population values below those shown in
the table will not be required to report
or complete the calculations to
determine whether they need to report.
• Since proposal, the requirements
for monthly manure sampling to
determine volatile solids (VS) and
nitrogen (N) content have been
removed. Instead of obtaining VS and N
content from manure sampling, facilities
must use default VS and N excretion
values as provided by EPA in look up
tables. The default VS and N excretion
values are consistent with the 1990–
2008 U.S. GHG inventory for manure
management and enteric fermentation.
For beef and dairy cows, heifers, and
steers, VS and N excretion rates were
calculated using the IPCC Tier II
methodology, based on the relationship
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between animal performance
characteristics such as diet, lactation,
and weight gain and energy utilization.
In response to comments, EPA used the
most up-to-date information on U.S.
animal diets to calculate these excretion
rates. For other animal groups, reference
values from ASAE and USDA are used.
• EPA has also adjusted the
calculations for CH4 and N2O emissions
from manure management systems to
account for volatile solids and nitrogen
removal through solid separation. If
solid separation occurs prior to the
manure management system
component, facilities must use default
removal efficiencies as provided by EPA
in look up tables. The default values are
consistent with those cited in the
‘‘Development Document for the Final
Revisions to the National Pollutant
Discharge Elimination System
Regulation and the Effluent Guidelines
for Concentrated Animal Feeding
Operations’’ (EPA–821–R–03–001),
published in December 2002.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on manure
management were received covering
numerous topics. Responses to
significant comments received can be
found in the comment response
document for manure management in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Subpart JJ: Manure
Management.’’
Comment: A number of commenters
supported EPA’s decision to include
livestock facilities with manure
management systems in the proposed
rule. These commenters noted that the
establishment of a mandatory GHG
reporting rule is the next logical step in
reducing and mitigating GHG emissions
in the U.S., and that manure
management is a significant source of
GHG emissions in the U.S. that should
be addressed.
However, other commenters stated
that livestock facilities should not be
required to report GHG emissions.
These commenters noted that a small
number of facilities would be covered
by the proposed rule, and these facilities
would represent a very small percentage
of the total number of livestock facilities
in the U.S. which would not provide a
large enough set of data to help improve
or reduce uncertainties associated with
GHG inventories. Several of the
commenters stated that manure
management is not a major source of
GHG emissions in the U.S., and the
environmental benefits from the rule
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would be minimal compared to the
effort required to report emissions.
Response: EPA disagrees that the
manure management source category be
excluded from this rule. Manure
management has been determined to be
a key source of GHG emissions in the
U.S., based on the key source category
methodology developed by the
Intergovernmental Panel on Climate
Change (IPCC). The IPCC identifies key
sources as those sources that have
significant impacts on the total
emissions or emission trends in a
country.
While livestock manure GHG
emissions represent a relatively small
fraction of the total U.S. GHG emissions,
these emissions are large in absolute
terms. According to the 2009 U.S. GHG
Inventory, CH4 emissions from manure
management systems totaled 44 million
metric tons CO2e, and N2O emissions
were 14.7 million metric tons CO2e in
2007; manure management systems
account for 7.5 percent of total
anthropogenic CH4 emissions and 4.7
percent of N2O emissions in the U.S.
In addition, the collection of facility
level GHG emission data, including the
type of manure management systems in
operation and the number and types of
animals serviced by those systems, will
help to inform future climate change
policy decisions. While the actual
number of facilities reporting will be
quite small in comparison to the total
number of facilities in the U.S., the data
gathered through this effort is valuable.
For example, these data will help to
improve the understanding of emission
rates and actions that facilities take to
reduce emissions and may improve the
effectiveness and design of voluntary
and/or mandatory programs to reduce
emissions.
Comment: Multiple commenters
stated that the monitoring requirements
in the proposed rule would be too
burdensome and expensive for industry
to comply with. These commenters
expressed concern that sampling
manure for VS and N would require
more time and effort and be more
expensive than EPA estimated. Multiple
commenters suggested that default
values such as from the American
Society of Agricultural and Biological
Engineers (ASABE) be permitted for VS
and N instead of measured values to
eliminate some of the expense
associated with the proposed rule.
In addition, a number of commenters
noted that there were some
methodological issues associated with
the monitoring requirements for VS and
N. Multiple commenters noted that the
requirements for manure sampling
should be clarified.
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Response: EPA acknowledges these
concerns and has removed the manure
sampling requirements from the final
rule. As discussed earlier, EPA used
default values for VS and N excretion
from USDA and ASAE for swine and
poultry, and has calculated these rates
for beef and dairy cows, heifers, and
steers using the IPCC Tier II
methodology, based on the relationship
between animal performance
characteristics such as diet, lactation,
and weight gain and energy utilization.
The use of these animal-specific default
values for VS and N will greatly reduce
the burden to comply with the reporting
rule, while only minimally impacting
the estimates of GHG emissions. The
variation in sampling techniques from
facility to facility when characterizing
manure ‘‘as excreted’’ from the various
animal populations on the facility (as
would have been required by the
proposal) would negate the benefit
derived from this requirement. EPA
considered designing a more complex
and rigorous program to ensure
consistency in the implementation of a
manure sampling program and to ensure
that manure samples represented ‘‘as
excreted’’ manure (prior to any storage
or treatment). However, after reviewing
comments, we determined that the
expected burden of such a program, in
terms of time, effort, and expense,
outweighed the merits at this time.
Comment: A number of commenters
noted that calculation errors caused
threshold head numbers to be
overestimated, which caused the
amount of emissions from these
operations and the number of operations
that would need to report to be
underestimated.
Response: To estimate the number of
facilities at each threshold, EPA first
developed a number of model facilities
to represent the manure management
systems that are most common on large
livestock operations and have the
greatest potential to exceed the GHG
reporting threshold. Next, EPA used the
U.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 livestock operation type.
Finally, EPA combined the numbers of
livestock required on each model
operation 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
livestock operation.
Since proposal, EPA made revisions
to the threshold analysis spreadsheet
calculations based on information and
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data provided by commenters. EPA
corrected conversion factors used in the
nitrous oxide emission calculations, and
corrected spreadsheet cell reference
errors along with using updated VS and
N values. EPA now estimates that there
will be approximately 107 livestock
facilities that will need to report under
the rule.
Comment: Commenters also
expressed concerns with the emission
calculations. Multiple commenters
noted that the maximum methane
producing capacity (Bo) values used do
not reflect variations in animal diet.
Several commenters had concerns about
the methodology used to estimate the
methane conversion factors. In addition,
some commenters suggested that other
data sources should be considered, such
as the ASABE manure standards.
Response: After a thorough review of
available information, EPA has
determined that the methodologies and
data sources used to calculate emissions
in this rule represent the best available
methods and data. EPA reviewed many
protocols and approaches prior to
selecting the proposed methodology.
EPA’s selected methodology for
reporting GHG emissions (methane and
nitrous oxide) associated with manure
management systems is based on EPA’s
Inventory of U.S. Greenhouse Gas
Emissions and Sinks, as well as the
IPCC Guidelines for National
Greenhouse Gas Inventories. These
methodologies rely on the use of activity
data, such as the number of head of
livestock, operational characteristics
(e.g., physical and chemical
characteristics of the manure, type of
management system(s)), and climate
data, to calculate GHG emissions
associated with traditional manure
management systems. In addition, the
selected methodology for the reporting
rule uses measured values for those
manure management systems (e.g.,
anaerobic digesters) that collect and
combust biogas.
EPA considered requiring direct
measurement of GHG emissions from
manure management systems, but
rejected this approach due to the
extreme expense and complexity of
such a measurement program. EPA is
promulgating an approach that allows
the use of default factors, such as a
system emission factor, for certain
elements of the calculation, and
encourages the use of some site-specific
data. The cost of such an approach is
significantly lower than a direct
measurement program. In addition, this
approach is consistent with the methods
used in offset programs throughout the
world, including the California Climate
Action Registry’s (CCAR) Manure
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Management Project Reporting Protocol.
For these offset programs, livestock
operations are required to complete
calculations that establish their
‘‘baseline’’ emissions (prior to the use of
a biogas collection system). These
baseline emission calculations use
similar emissions calculations and
default values as are in EPA’s Reporting
Rule.
The IPCC guidelines have been
established by a recognized panel of
experts and underwent significant peer
review prior to their adoption. In
addition, protocols for offset programs,
such as CCAR, have gone through
similar public review processes prior to
their acceptance and use.
Comment: Multiple commenters have
requested more detailed look up tables
and a tool to provide more clarity on
which facilities are required to report
under the final rule.
Response: EPA agrees that additional
tables and tools would facilitate
compliance with the rule and ease the
burden associated with reporting. In
response to the comments, EPA has
added a threshold table to the final rule
(Table JJ–1) to help livestock facilities
with manure management systems
better determine if they might be subject
to the requirements of the rule. EPA also
intends to develop applicability tools
that can assist facilities that could be
covered by the rule, based on table JJ–
1 in 450 CFR part 98, subpart JJ, in
conducting a more detailed evaluation.
These tools will include detailed lookup tables showing the estimated
livestock head numbers that would be
necessary in order to meet or exceed the
threshold and a calculation tool to assist
in performing the calculations in the
proposed rule.
KK. Suppliers of Coal
At this time, EPA is not going final
with a subpart for suppliers of coal. As
EPA considers next steps, we will be
reviewing the public comments and
other relevant information.
The Agency received a number of
lengthy, detailed comments regarding
the coal suppliers subpart. Commenters
generally opposed the proposed
reporting requirements and raised
multiple issues with EPA’s legal
authority for requiring coal suppliers to
report CO2 emissions. Several
commenters stated that reporting by
coal suppliers would represent a
duplication of the reporting by coal
users. For example, electric utilities and
industrial plants, which consume the
vast majority of coal supplied, are
already required to report data on
emissions based on their coal purchases.
Commenters also stated that the
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reporting requirement would entail
significant burden and capital costs to
coal suppliers. In most cases,
commenters provided alternative
approaches to the reporting
requirements proposed by EPA. For
example, commenters suggested that
EPA exempt from reporting coal mines
that supply coal to mine-mouth power
plants, modify the required coal
weighing and sampling standards, and
eliminate the required statistical
correlation between HHV and carbon
content.
Commenters raised other issues
regarding the reporting of data such as
concerns that coal suppliers and
laboratories could not realistically
purchase and install new coal testing
and sampling equipment and provide
training to meet the requirements of the
proposed rule.
Based on careful review of comments
received on the preamble, rule and
TSDs under proposed 40 CFR part 98,
subpart KK, EPA will perform
additional analysis and consider
alternatives to data collection
procedures and methodologies. These
alternatives will provide coverage of
coal supplied, imported, or exported
while concurrently taking into account
industry burden.
LL. Suppliers of Coal-Based Liquid Fuels
1. Summary of the Final Rule
Source Category Definition. This
source category consists of producers,
importers, and exporters of products
listed in Table MM–1 of 40 CFR part 98,
subpart MM that are coal-based (coal-toliquid products). A producer of coal-toliquid products is any owner or operator
who converts coal into liquid products
(e.g., gasoline, diesel) using the FischerTropsch or an alternative process.
Suppliers of coal-to-liquid products
that meet the applicability criteria in the
General Provisions (40 CFR 98.2)
summarized in Section II.A of this
preamble must report GHG emissions.
GHGs to Report. Suppliers of coal-toliquid products must report the CO2
emissions that would result from the
complete combustion or oxidation of the
coal-to-liquid products.
Suppliers of coal-to-liquid products
are not required to report data on
emissions of other GHGs that would
result from the complete combustion or
oxidation of their products, such as CH4
or N2O.
GHG Emissions Calculation and
Monitoring. For each type of coal-toliquid product, suppliers must calculate
CO2 emissions that would result from
the complete combustion or oxidation of
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the coal-to-liquid products by following
the procedures in 40 CFR 98.393.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
GHG emissions that would result from
the complete combustion or oxidation of
their products. A list of the specific data
to be reported for this source category is
contained in 40 CFR 98.386.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate GHG
emissions that would result from the
complete combustion or oxidation of
their products. A list of specific records
that must be retained for this source
category is included in 40 CFR 98.387.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below.
• We replaced the procedures and
calculations proposed in 40 CFR part
98, subpart LL with references to the 40
CFR part 98, subpart MM procedures
and calculations. As a result of
considerable comment and EPA
analysis, 40 CFR part 98, subpart MM
procedures and calculations were
significantly updated. Since the
procedures and calculations necessary
for sampling, testing, and measuring
coal-to-liquid products are intrinsically
linked to the procedures and
calculations used for petroleum
products, we concluded that referencing
40 CFR part 98, subpart MM in 40 CFR
part 98, subpart LL would achieve
consistency and completeness.
• We reorganized and updated 40
CFR 98.386 by mirroring 40 CFR 98.396
in order to reflect the updates we made
to procedures and calculations and to
assist in EPA data verification.
3. Summary of Comments and
Responses
EPA did not receive any specific
comments on proposed 40 CFR part 98,
subpart LL (suppliers of coal-based
liquid fuels). Changes made to this
subpart were implemented to ensure
consistency with changes made to 40
CFR part 98, subpart MM based on
public comments provided and EPA
analysis conducted.
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MM. Suppliers of Petroleum Products
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1. Summary of the Final Rule
Source Category Definition. Suppliers
of petroleum products consist of:
• Petroleum refineries that produce
petroleum products through distillation
of crude oil.
• Importers who satisfy the same
meaning given in 40 CFR 98.6,
including any entity that imports
petroleum products or NGLs as listed in
Table MM–1 of 40 CFR part 98, subpart
MM. Any blender or refiner of refined
or semi-refined petroleum products
shall be considered an importer if it
otherwise satisfies the aforementioned
definition.
• Exporters who satisfy the same
meaning given in 40 CFR 98.6,
including any entity that exports
petroleum products or NGLs as listed in
Table MM–1 of 40 CFR part 98, subpart
MM. Any blender or refiner of refined
or semi-refined petroleum products
shall be considered an exporter if it
otherwise satisfies the aforementioned
definition.
Suppliers of petroleum products that
meet the applicability criteria in the
General Provisions (40 CFR 98.2)
summarized in Section II.A of this
preamble must report GHG emissions
that would result from the complete
combustion or oxidation of the
product(s) they supply.
GHGs to Report. Suppliers of
petroleum products must report
annually:
• 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.
• CO2 emissions that would result
from the complete combustion or
oxidation of any biomass co-processed
with petroleum feedstocks at a refinery.
Suppliers of petroleum products are
not required to report data on emissions
of other GHGs that would result from
the complete combustion or oxidation of
their products, such as CH4 or N20.
GHG Emissions Calculation and
Monitoring. Suppliers of petroleum
products must choose one of two
methods to calculate CO2 emissions that
would result from the combustion or
oxidation of each petroleum product
and natural gas liquid:
• Method 1: Use the default CO2
emission factors provided in the
regulations for a given petroleum
product or NGL; or
• Method 2: Develop an emission
factor for a given petroleum product or
natural gas liquid using direct
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measurements of density and carbon
share.
To calculate CO2 emissions that
would result from the combustion or
oxidation of biomass co-processed with
petroleum feedstock, reporters must use
a CO2 emission factor that is provided
in the regulations for each type of
biomass.
In calculating total CO2 emissions that
would result from the combustion or
oxidation of all petroleum products and
natural gas liquids that leave the
refinery, refineries must subtract the
emissions from petroleum products and
natural gas liquids that enter the
refinery to be further refined or used on
site as well as biomass and biomassbased fuels that are co-processed or
blended with petroleum feedstocks.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data used to calculate GHG
emissions that would result from the
complete combustion or oxidation of the
product(s) supplied as well as
information on the characteristics of
crude oil used at a refinery. The specific
list of data to be reported for this source
category is contained in 40 CFR part
98.396 and includes information to
support the data verification process.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to determine the
quantities and characteristics of
product(s) reported under this subpart
and to calculate GHG emissions that
would result from the complete
combustion or oxidation of the
product(s) supplied. A list of specific
records that must be retained for this
source category is included in 40 CFR
part 98.387.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart MM:
Suppliers of Petroleum Products.’’
• We established a reporting
threshold for importers and exporters of
25,000 metric tons of CO2 per year.
• We changed the source category
definition of petroleum refinery for the
purposes of 40 CFR part 98, subpart MM
to only include facilities that process
crude oil. As such, we are not requiring
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reporting from facilities that only
handle intermediary petroleum
products.
• We refined the definition of
importers and exporters of petroleum
products to clarify reporting
requirements for blenders.
• We are not requiring reporters to
rely on an exclusive list of standard
methods for the measurement of the
quantity of products or the calibration
and recalibration of equipment. Instead,
reporters must use an appropriate
standard method published by a
consensus-based standards organization.
If no such standard exists, reporters are
allowed to rely on industry standard
practices.
• We provide more flexibility in the
frequency of equipment recalibration.
Reporters must now comply with the
frequency specified by the
manufacturer’s directions or the
selected quantity measurement method.
• We removed the option for
reporters to directly measure density but
not carbon share under Calculation
Method 2. We determined that using a
measured density and a default carbon
share factor will likely adversely affect
the accuracy of the calculated emission
factor since the density and carbon
share of hydrocarbons are, in the
absence of impurities, correlated.
• We are not requiring reporters to
rely on an exclusive list of standard
methods for sampling products,
measuring density, and measuring
carbon share under Calculation Method
2. Instead, reporters must use an
appropriate standard method published
by a consensus-based standards
organization.
• We added more specific
requirements for the frequency of
sampling under Calculation Method 2
and now allow for mathematical
composites of samples in addition to
physical composites of samples.
• To ensure consistent accounting of
denaturant across reporters, we are
requiring reporters to assume that 2.5
percent of the volume of any ethanol
product that is blended into a
petroleum-based product is a
petroleum-based denaturant. See below
for further explanation.
• For bulk NGLs, reporters must
calculate the emissions that would
result from the complete combustion or
oxidation of the individual components
that constitute the NGL (i.e., ethane,
propane, butane, isobutane, and
pentanes plus).
• We updated the definition of
petroleum products to be clear that no
petroleum product supplier must report
on plastics and plastic products and that
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importers and exporters must report on
asphalt, road oil, and lubricants.
• We updated the default emissions
factors based on technical research since
the proposal. We updated certain factors
to correct technical errors and to reflect
more recent data. We expanded the
factors to four significant digits to
enhance precision. We also added
grade-based sub-categories of finished
motor gasoline and blendstocks,
combined diesel and fuel oil categories
into ‘‘distillate fuel’’ categories, and
added sulfur-based subcategories of
distillate fuel No. 1 and 2 to better
distinguish between product categories
with potentially different carbon
contents. Full documentation of default
emissions factors can be found in the
TSD.
• We updated 40 CFR 98.396. First,
we made 40 CFR 98.396 more specific,
in some cases breaking up one reporting
requirement into two for clarity.
Second, to allow for EPA verification of
reporter calculations, we added
reporting requirements for data that a
reporter must already use to calculate
GHGs as specified in 40 CFR 98.393
through 98.396. Third, after removing
the prescriptive list of allowable
methods, we added data reporting
requirements on the method selected to
measure quantity, density, and carbon
content and the method selected to
sample in order to track the
appropriateness of these methods.
We require reporters to assume that
ethanol contains 2.5 percent petroleumbased denaturant because we want to
ensure that reporters account for the
CO2 emissions that would result from
the combustion or oxidation of the
denaturant. All ethanol that is blended
with petroleum products reported in 40
CFR part 98, subpart MM should
contain more than 1.96 percent
petroleum-based denaturant by volume,
per the requirements in 27 CFR Parts 20
and 21 to make ethanol non-potable. We
considered relying on reporters to
estimate the percent volume of
denaturant in their products, but we
determined that, in many cases,
reporters would not know this
information. We have concluded that
2.5 percent is a suitable assumption for
the level of denaturant since, according
to an Internal Revenue Service
interpretation of Section 15332 in the
Food, Conservation, and Energy Act of
2008 in notice 2009–06, ethanol
containing greater than 2.5 percent
denaturant by volume would not be
eligible for the full value of the
Volumetric Ethanol Excise Tax Credit.
There may be cases where ethanol
containing less than 2.5 percent
denaturant is blended with petroleum-
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based products, but we concluded that
it is better to conservatively account for
potential petroleum-based carbon
emissions rather than arbitrarily pick a
number between 1.96 percent and 2.5
percent.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on suppliers
of petroleum products were received
covering numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart MM:
Suppliers of Petroleum Products.’’
Selection of Threshold
Comment: In the proposed rule, EPA
sought comment on whether or not to
establish a de minimis level of imported
and exported petroleum products, either
in terms of the quantity of products or
the CO2 emissions associated with the
combustion or oxidation of products, to
eliminate any reporting burden for
parties that may import or export a
small amount of petroleum products on
an annual basis. In response, EPA
received several comments in support of
establishing some type of de minimis
value, including a threshold of 25,000
metric tons of CO2 from the complete
combustion or oxidation of all products
from individual importers and
exporters. EPA also received at least one
comment in support of establishing a
threshold value for refineries reporting
under 40 CFR part 98, subpart MM.
Response: In today’s rule, we are
establishing a threshold of 25,000 metric
tons of CO2 per year for importers and
exporters of petroleum products and
natural gas liquids; the threshold is
based on a calculation of CO2 emissions
that would result from complete
combustion or oxidation of the imported
or exported petroleum products and
natural gas liquids.
When we conducted the threshold
analysis for the proposed rule, we
estimated from EIA data that 224
companies would be covered in 40 CFR
part 98, MM as importers. Through this
analysis, we found that at a threshold of
25,000 metric tons CO2 per year, 175
importers and 99.9 percent of total
emissions that would result from the
combustion or oxidation of imported
products would be covered by the
proposed rule. Therefore, establishing a
25,000 metric ton CO2 threshold would
drop 49 reporters in exchange for a 0.1
percent drop in total emissions.
Nonetheless, we decided to propose
reporting for all importers because we
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felt the reporting burden would be
minimal since importers already report
the product quantity data to other
Federal agencies.
Since proposing the rule, EPA has
learned new information, through
comments and research, about importers
that could be covered as reporters under
40 CFR part 98, Subpart MM. EPA may
have omitted some importers of small
volumes of petroleum products or
natural gas liquids from our original
threshold analysis, due to lack of public
data. We never intended to cover such
small volume imports with this rule
(e.g., importers of non-fossil fuel
products that contain small quantities of
petroleum or natural gas liquids, such as
butane lighters). Therefore, for the final
rule, EPA concludes that establishing a
25,000 metric ton CO2 threshold for
importers will relieve burden on
importers of insignificant quantities of
petroleum products and natural gas
liquids that we never intended to cover
with this rule without significantly
diminishing the amount of information
received by the agency. In addition, a
25,000 metric ton CO2 threshold is
consistent with other upstream fuel and
industrial gas supplier thresholds for
importers and exporters in today’s rule.
When we conducted the threshold
analysis for the proposed rule, we could
not estimate the number of exporting
companies that would be covered in 40
CFR part 98, subpart MM because the
necessary data was not publically
available. Nonetheless, we decided to
propose reporting for all exporters
because we concluded that the reporting
burden would be minimal given the
type of information that exporters must
maintain as part of their normal
business operations.
Since proposing the rule, based on
analogous information learned on
importers, EPA has concluded that some
exporters of very small volumes of
petroleum products or natural gas
liquids could be covered as reporters
under 40 CFR part 98, subpart MM. We
never intended to cover such small
volume exporters with this rule (e.g.,
exporters of non-fossil fuel products
that contain small quantities of
petroleum or natural gas liquids, such as
butane lighters). Therefore, for the final
rule, EPA has concluded that
establishing a threshold for exporters
will relieve burden on exporters of
insignificant quantities of petroleum
products and natural gas liquids that we
never intended to cover with this rule.
In today’s rule, we have selected a
25,000 metric ton CO2 threshold
because we conclude that it will not
significantly diminish the amount of
information received by the agency;
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overall, exports of refined and semirefined products are lower than imports,
so the threshold adopted for imports
will be adequate for collecting data on
exports. In addition, a 25,000 metric ton
CO2 threshold is consistent with other
upstream fuel and industrial gas
supplier thresholds for importers and
exporters in today’s rule.
In today’s rulemaking, we require all
refineries as defined in 40 CFR part 98,
subpart MM to report, as was proposed.
Our threshold analysis of refineries in
the proposed rule indicated that all
refineries would be covered even if we
were to establish a 100,000 metric ton
CO2 threshold. Furthermore, we have
determined that all refineries covered by
this subpart are already tracking the
necessary data to comply with the
reporting requirements so the
requirements would not pose an undue
burden.
Monitoring and QA/QC Requirements
Comment: EPA received several
comments that the proposed approach
to determining product quantity was too
prescriptive. These comments indicated
that the list of allowable methods and
equipment types for determining the
quantity of products in the proposed
rule was incomplete, would result in
significant costs for industry, and could
adversely impact the quality of the
measurements. Commenters noted that
industry uses a much larger and evergrowing number of industry methods
and equipment types to determine
quantity for purposes of product
transfers and financial records,
including methods and equipment types
used to comply with Internal Revenue
Service, Securities and Exchange
Commission, and Department of
Homeland Security’s Bureau of U.S.
Customs & Border Protection
regulations. Commenters suggested that
EPA’s ability to develop and maintain a
comprehensive list of methods would
require considerable resources, since
companies and consensus-based
standards organizations review quantity
measurement methods regularly to
ensure consistency with technological
changes and advancements.
Commenters also suggested that
methods may improve over time for
certain products as a direct result of this
rulemaking.
Response: In today’s rule, we are
addressing these concerns by adopting
an approach that recognizes the
multitude of appropriate industry
standard methods and practices and
leaves open the possibility that industry
may adopt better methods, equipment,
and practices over time to determine
quantities of products. EPA is requiring
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that petroleum product suppliers use an
appropriate standard method developed
by a consensus-based standards
organization, when such a standard
method exists. If no such standard
method exists, reporters are allowed to
follow industry standard practices.
Consensus-based standards
organizations include organizations
such as ASTM International, the
American National Standards Institute
(ANSI), the American Gas Association
(AGA), the American Society of
Mechanical Engineers (ASME), the
American Petroleum Institute (API), and
North American Energy Standards
Board (NAESB). Reporters must ensure
that all equipment used for measuring
quantity is calibrated and periodically
recalibrated according to the
manufacturer’s directions or
specifications in the appropriate
consensus-based industry standard
method.
In order to further EPA’s
understanding of the methods and
equipment that reporters use, and to
help us better assess the appropriateness
of the standard methods and industry
practices that individual reporters
select, we are requiring that all
petroleum product suppliers report the
standard method or industry standard
practice they use to measure each
distinct product quantity that they
report to EPA.
Comment: Several commenters
recommended that EPA provide more
flexible approaches to the direct
measurement of carbon share and
density under Calculation Method 2.
Some noted that the proposed
requirement to test samples at the end
of the year could negatively impact the
integrity and quality of those samples.
These commenters suggested that EPA
allow reporters to test samples monthly
and create a mathematical composite of
these test results at the end of the year.
Some commenters suggested that EPA
develop a mechanism whereby reporters
could reduce the frequency of sampling
once the reporter demonstrates that the
variability in the density and carbon
share of the product is sufficiently
small, and even eliminate direct
measurement requirements and allow
reporters to use emissions factors
developed in previous years. We also
received comments requesting that we
expand our list of acceptable carbon
share measurement methods.
Response: We have incorporated
several of the suggestions to increase the
flexibility of the Calculation Method 2
approach in today’s rule. Reporters are
now allowed to test their monthly
samples throughout the year and
conduct a mathematical composite of
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the test results at the end of the year. We
have also expanded the list of
acceptable sampling, density, and
carbon share methods to include any
appropriate standard method published
by a consensus-based standards
organization.
We could not determine an adequate
approach for allowing reporters to
reduce the sampling frequency of
products based on statistical evidence of
low variability in the density and
carbon share for a given product. We
want to capture changes in product
characteristics over time and have
determined that taking monthly samples
of an entire product category would not
be overly burdensome. Furthermore,
reporters are allowed to use default
factors under Calculation Method 1 if
they so choose.
Data Reporting Requirements
Comment: EPA received several
comments requesting that we eliminate
reporting requirements related to
products that have potentially nonemissive uses, including plastics and
plastic products, petrochemical
feedstocks, petroleum coke sent to
landfill, asphalt and road oil, and
lubricants and waxes. One commenter
questioned the incongruity in reporting
requirements proposed for refiners, who
would report on all products, and
importers and exporters who would not
be required to report on asphalt, road
oil, lubricants, waxes, plastics, and
plastic products.
Response: Today’s rule requires
reporting on products with potentially
non-emissive uses. Comprehensive
upstream data will provide EPA with a
full accounting of the emissions that
would result from the complete
combustion or oxidation of all
petroleum products and natural gas
liquids introduced into the economy.
Furthermore, comprehensive facilitylevel data can help us conduct a more
robust mass balance assessment for data
verification purposes. While we
recognize that carbon in some
petroleum products, such as asphalt,
can remain un-oxidized for long
periods, petroleum product supplier
cannot always know with certainty
whether or not the carbon in their
products will be released into the
atmosphere. Even asphalt can be burned
as fuel or incinerated as waste. In the
Inventory of US Greenhouse Gas
Emissions and Sinks, EPA notes several
areas of uncertainty surrounding the fate
of carbon in petroleum products
including those for which the Inventory
assumes a 100 percent storage factor for
the purposes of the national inventory
(e.g., asphalt roofing, asphalt cement,
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and asphalt paving materials). As
discussed in the proposal, a
comprehensive and rigorous system for
tracking the fate of petroleum products
that may have non-emissive uses is
beyond the scope of this rule, and
would require a much more
burdensome reporting obligation for
petroleum product suppliers and other
downstream users of petroleum
products and natural gas liquids. The
data reported as a result of this
rulemaking will allow EPA to conduct
further research in the future on the
pathways and ultimate fate of products
with potential non-emissive uses.
It was never EPA’s intention to
require reporting on plastics and plastic
products, so we made this explicit in
the definition of petroleum products as
well as our definition of a refinery in 40
CFR part 98, subpart MM, which now
excludes any facility (e.g. a plastics
manufacturing plant) that does not
process crude oil. Any CO2 emissions
that would result from the combustion
or oxidation of plastics and plastic
products manufactured in the U.S.
should already be accounted for when a
petroleum product supplier introduces
the petrochemical feedstock (e.g.,
propylene) into the economy.
In response to comments on the
incongruity of the reporting burden for
refiners compared to importers and
exporters, we have reevaluated the list
of petroleum products with potentially
non-emissive uses that importers and
exporters do not have to report. In the
proposed rule, this list included asphalt,
road oil, lubricants, waxes, plastics, and
plastic products. Our rationale for
excluding these products for importers
and exporters was our assessment that
there is a much larger variety of these
products entering and leaving the
country than is produced at a petroleum
refinery. Upon further consideration,
however, we have concluded that only
waxes, plastics, and plastic products
would pose an undue administrative
burden on importers and exporters.
Waxes, plastics, and plastic products
enter and leave the country in wideranging forms (e.g., cosmetics, candles,
lawn furniture, plastic wear) making it
difficult to accurately assess the
petroleum-based carbon content of these
products. We have concluded that the
types of asphalt, road oil, and lubricants
imported in and exported from the
country is much less variable, and
importers already track these products
and report the quantities to EIA. We
have also established a 25,000 metric
ton CO2 annual reporting threshold for
importers and exporters in today’s rule,
which should reduce the number of
reporters and minimize the reporting of
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products that are imported or exported
in very low quantities. Therefore, we are
requiring importers and exporters to
report the volume and CO2 emissions
that would result from the complete
combustion or oxidation of the asphalt,
road oil, and lubricants they supply.
In response to comments that
collecting data on products with
potentially non-emissive uses will
overestimate actual emissions released
into the atmosphere, EPA has and will
continue to characterize CO2 emissions
data reported under 40 CFR part 98,
subpart MM as emissions that would
result from the complete combustion or
oxidation of the reported product(s) and
not as actual emissions.
Comment: EPA received many
comments urging us to leverage data
that petroleum product suppliers
already report to the Energy Information
Administration (EIA) and to follow
EIA’s data collection procedures and
protocols. For example, one commenter
urged EPA to require refiners on a
facility-level and company-wide basis to
report to EPA the same level of
information on crude imports and
processing that is currently reported to
the EIA and to follow a process similar
to the one used by the EIA; and another
commenter urged us to align our
reporting requirements with what the
industry is already providing to the EIA.
Some commenters, urged EPA to make
use of data already reported to EIA or
other Federal agencies instead of
requiring reporting directly to EPA
through this rulemaking. EPA also
received comments recommending that
EIA reporting remain separate from the
reporting requirements of this rule.
Response: In the proposed
rulemaking, EPA stated that we
considered, but did not propose, the
option of obtaining data by accessing
existing Federal government reporting
databases and we sought comment on
this decision.
In today’s rulemaking, we are
requiring reporters to report data
directly to EPA. We have determined
that in order to collect facility-level data
from refineries (and company-level data
from importers and exporters) that is
consistent with other reporters in this
rule, in terms of timing, reporting, and
verification procedures, we are not able
to rely upon EIA data. In addition, EIA
relies on a number of legal authorities
to pledge confidentiality to statistical
survey respondents for company-level
information. Some data are collected
with legal authority from the
Confidential Information Protection and
Statistical Efficiency Act of 2002
(CIPSEA), under which reported
information must be held in confidence
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and must be used for statistical
purposes only. Collection of data
directly by EPA in a central system will
allow EPA to electronically verify and
publish the data quickly, to use the
information for non-statistical purposes,
and to handle confidential business
information in accordance with the
CAA (see the general provisions
preamble for addition discussion on
CBI). In today’s rulemaking we did not
replicate EIA’s reporting requirements
and methodologies if we did not
consider them sufficient to achieve our
objective, which is to collect
comprehensive and accurate data on the
CO2 emissions that would result from
the complete combustion or oxidation of
petroleum products introduced into the
economy. For example, we provide a
comprehensive list in Tables MM–1 and
MM–2 of 40 CFR part 98, subpart MM,
according to which reporters must
categorize their products for reporting
under today’s rulemaking. This list
differs from EIA’s list of products,
according to which reporters must
report to EIA. Some of the products are
the same on both lists (e.g., aviation
gasoline and kerosene) while some
products are classified differently on
one list than on the other (i.e., EPA’s list
breaks reformulated gasoline up by
summer and winter varieties while EIA
breaks reformulated gasoline up by type
of oxygenate blended into it). We crafted
EPA’s product list carefully and we feel
that each category has the potential to
have a unique carbon share and/or
density. Overall, the items on our list
are common products in commerce and
are already tracked by refineries,
importers, and exporters. Therefore, we
estimate that the additional burden to
comply with this rule will be minimal.
NN. Suppliers of Natural Gas and
Natural Gas Liquids
1. Summary of the Final Rule
Source Category Definition. Suppliers
of natural gas and natural gas liquids
are:
• NGL fractionators, which are
installations that fractionate NGLs into
their constituent liquid products:
ethane, propane, normal butane,
isobutane or pentanes plus for supply to
downstream facilities.
• Local natural gas distribution
companies (LDCs) that own or operate
distribution pipelines that deliver
natural gas to end users. Companies that
operate interstate pipelines transmission
or intrastate transmission pipelines are
not part of this source category.
Suppliers of natural gas and NGLs
that meet the applicability criteria in the
General Provisions (40 CFR 98.2)
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summarized in Section II.A of this
preamble must report GHG emissions
that would result from complete
combustion or oxidation of products
they supply.
GHGs to Report. Natural gas
fractionators must report CO2 emissions
that would result from the complete
combustion or oxidation of the annual
quantities of propane, butane, ethane,
isobutene, and pentanes plus supplied.
Local distribution companies must
report CO2 emissions that would result
from the complete combustion or
oxidation of the annual volume of
natural gas distributed to their
customers.
Suppliers of natural gas and NGLs are
not required to report data on emissions
of other GHGs that would result from
the complete combustion or oxidation of
their products, such as CH4 or N20.
GHG Emissions Calculation and
Monitoring. Reporters must use one of
two methods to calculate the CO2
emissions that would result from the
complete combustion or oxidation of
natural gas supply or NGL supply:
• One method uses either a measured
or default fuel heating value and either
a measured or default CO2 emissions
factor. This method is most appropriate
for liquid fuels.
• The second method uses either a
measured or default CO2 emissions
factor. This method is most appropriate
for gaseous fuels.
• A NGL fractionator must then
follow two additional equations, if
applicable, to subtract the CO2
emissions that would result from the
complete combustion or oxidation of
NGL supply that are double-counted. A
LDC must then follow up to four
additional equations, if applicable, to
subtract the CO2 emissions that would
result from the complete combustion or
oxidation of natural gas supply that is
double-counted.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
natural gas or NGL supply. A list of the
specific data to be reported for this
source category is contained in 40 CFR
part 98, subpart NN.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate
natural gas or NGL supply. A list of
specific records that must be retained
for this source category is included in
40 CFR part 98, subpart NN.
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2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart NN:
Suppliers of Natural Gas and Natural
Gas Liquids.’’
• We changed the source category
responsible for reporting NGL supply in
40 CFR part 98, subpart NN from all
natural gas processors to only facilities
that fractionate natural gas liquids.
• We eliminated the requirement to
report bulk NGL since NGL fractionators
do not supply bulk NGL.
• We added equations to calculate
emissions that would result from the
oxidation or combustion of the
following volumes of natural gas and
NGLs because they should be subtracted
from the reporter’s total emissions
calculation, when applicable:
fractionated NGLs received from other
fractionators; natural gas injected for
storage; natural gas delivered to
individual customers already reporting
under another Subpart of this rule; and
natural gas delivered by an LDC to
another LDC.
• We clarified the points of
measurements for reporting purposes.
• We changed the rule to allow local
distribution companies to use
transmission pipeline metered volumes
and calculated heating value where the
local distribution companies do not
perform their own measurements.
• We provide flexibility in frequency
of equipment calibration, requiring
reporters to comply with standard
industry practices for measurements
used for billing purposes as audited
under Sarbanes Oxley regulations.
• We added a procedure for
measuring the carbon content of blends
of NGLs since NGL fractionators may
supply blends of NGLs.
• We updated 40 CFR 98.406. First,
we made 40 CFR 98.406 more specific,
in some cases breaking up one reporting
requirement into two for clarity.
Second, to allow for EPA verification of
reporter calculations, we added
reporting requirements for data that a
reporter must already use to calculate
GHGs as specified in 40 CFR 98.403 to
40 CFR 98.406. This includes the
addition of reporting requirements for
new calculations introduced in the final
rule to prevent supply double-counting.
Third, after removing the prescriptive
list of allowed standards and methods,
we added data reporting requirements
on the method selected to measure
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quantity, HHV, and carbon content.
Fourth, we added a reporting
requirement for the quantity of odorized
propane. Fifth, we added data reporting
requirements for inputs received by a
NGL fractionator in order to conduct
verification using a mass-balance
approach.
3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on suppliers
of natural gas and NGLs were received
covering numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart NN:
Suppliers of Natural Gas and Natural
Gas Liquids.’’
Definition of Source Category
Comment: EPA received many
comments on the non-emissive use of
natural gas liquids (NGLs). In general,
these comments stated that NGLs such
as ethane, butane, and isobutene, are
either used as feedstocks in the
petrochemical industry or as
blendstocks that are reported by
refineries in 40 CFR part 98, subpart
MM, and should not be reported as
though they are completely combusted
or oxidized. Several commenters
proposed that odorized propane should
be the focus of 40 CFR part 98, subpart
NN rather than all NGLs because
odorized propane is the only NGL that
is combusted as fuel.
Response: Today’s rule still requires
reporting on all NGL products, even
those with potentially non-emissive
uses. Comprehensive upstream data will
provide EPA with a full accounting of
the emissions that would result from the
complete combustion or oxidation of all
natural gas liquids introduced into the
economy.
As discussed in the proposal, a
comprehensive and rigorous system for
tracking the fate of natural gas liquids
that may have non-emissive uses is
beyond the scope of this rule, and
would require a much more
burdensome reporting obligation for
NGL fractionators and downstream
users of natural gas liquids. Based on
the data available today, we do not
believe that a NGL fractionator can
know with certainty whether or not the
carbon in their products will be released
into the atmosphere. The data reported
as a result of this rulemaking will allow
EPA to conduct further research on the
pathways and ultimate fate of NGL and
to refine our understanding of and
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policy on products with potential nonemissive uses.
Therefore, EPA does not concur with
the proposal to replace NGL reporting
with propane odorizers. However, EPA
concurs that odorized propane lines up
closely with propane combusted
downstream, and that data collection on
odorized propane would help EPA
decide if and how to carry out a wide
variety of CAA provisions on emission
sources, as authorized broadly under
CAA sections 114 and 208. As a result,
we have added reporting requirements
on the volume of propane odorized on
site in today’s rule.
We do not concur that products
reported under 40 CFR part 98, subpart
NN, such as isobutane to be blended
with fuel, will be double-counted as
products reported under 40 CFR part 98,
subpart MM. Subpart MM requires
refineries to report all non-crude
feedstocks that enter the facility in order
to subtract the emissions that would
result from the oxidation or combustion
of those products from their
calculations. Such methodology allows
EPA to collect data on the entire
petroleum and natural gas liquids
system without any double-counting.
Finally, in response to comments that
collecting data on products with
potentially non-emissive uses will
overestimate actual emissions released
into the atmosphere, EPA will continue
to characterize CO2 emissions data
reported under 40 CFR part 98, subpart
NN as emissions that would result from
the complete combustion or oxidation of
the reported product(s) and not as actual
emissions.
Comment: Many commenters
discouraged EPA from requiring
reporting from natural gas processors. In
general, these comments stated that
processors do not know the constituents
of the gas they process. They further
stated that since bulk NGLs are often
sent from one processor to another,
reporting by processors on bulk NGLs
would result in double-counting of
supply. Ultimately, several commenters
were confused by the multiple
definitions provided in the rule for a
natural gas processor and were not clear
on the exact covered party in 40 CFR
part 98, subpart NN.
Response: In the final rule, we specify
the source category as NGL fractionators
rather than as natural gas processors,
and we have removed the requirement
to report bulk NGLs. To avoid any
remaining potential for doublecounting, we provide an equation for a
fractionator to subtract from its
calculations any NGL constituents
received from other fractionators that
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would report those products under this
rule.
By requiring reporting from NGL
fractionators, we have removed the need
for the term ‘‘natural gas processor’’ in
40 CFR part 98, subpart NN. Multiple
definitions for this term no long exist in
the rule.
Monitoring and QA/QC Requirements
Comment: Many commenters
interpreted EPA’s measurement and
calibration requirements differently
than we intended, and as a result
pressed upon EPA the inability of
industry to reasonably meet such
requirements. Many commenters
interpreted that EPA required meter
reading and calibration of every
customer meter. Other commenters
interpreted that EPA required daily
measurement totals of throughput.
Response: In today’s rule, we provide
precise language to remove any
confusion about monitoring and QA
requirements. First, we clarify that the
point of measurement for natural gas
supply is the city gate meter. If the LDC
makes its own measurements at the city
gate according to business as usual
practices, then it must use its own
measurements. If not, it must use the
delivering pipeline invoices
measurements. The only exceptions are
that the point of measurement for
natural gas delivered to large end-users
is the customer meter and the point of
measurement for natural gas stored or
removed from storage is the appropriate
storage meter. However, we clarify that
customer meters and storage meters are
not subject to the 40 CFR part 98,
subpart NN calibration requirements.
Second, we clarify that the minimum
frequency of the measurements of
quantities of NGLs and natural gas shall
be based on the reporter’s standard
practices for commercial operations. For
NGL fractionators the minimum
frequency of measurements shall be the
measurements taken at custody transfers
summed to the annual reportable
volume. For natural gas the minimum
frequency of measurement shall be
based on the LDC’s standard
measurement schedules used for billing
purposes and summed to the annual
reportable volume. If daily
measurements are not standard practice
for a reporter, then that reporter need
not conduct daily measurements.
EPA clarifies in the final rule that
customer meters do not face calibration
requirements under 40 CFR part 98,
subpart NN. Other equipment used to
measure quantities must be calibrated
prior to their first use for reporting
under this subpart, using a suitable
standard test method published by a
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consensus based standards organization
or according to the equipment
manufacturer’s directions. Such
equipment must also be recalibrated at
the frequency specified by the standard
test method used or by the
manufacturer’s directions. EPA has
concluded that initial calibration
requirements are necessary to ensure
consistency across all reporters and
accuracy of data. Since such a wide
variety of calibration methods is
allowed and since commenters stated
that industry already calibrates carefully
as a result of State Utility Commission
and other regulations, EPA concluded
that industry is already following such
calibration requirements for usual
business operations.
Data Reporting Requirements
Comment: EPA received many
comments on the requirement for LDCs
to report information on individual
customers. In general, commenters
interpreted the reason for EPA to collect
this data differently than was intended.
Many commented on the CBI nature of
customer-specific delivery information.
Others commented that LDCs do not or
may not have access to the EIA or EPA
numbers of their customers. One
commenter told us that a LDC can only
attest to the gas volume delivered
through a single particular meter at a
single particular location, which is not
necessarily an individual customer.
Response: In the final rule, EPA has
clarified that an LDC must report on
customers that receive more than
460,000 million standard cubic feet
(Mscf) per year in order to subtract that
volume out of its total calculations.
EPA’s intention is to use this data to
remove potential double-counting and
to prevent a LDC from calculating and
reporting an overstated supply volume.
EPA can also use these data to verify
that covered direct emitters are
approximately reporting under the rule.
In response to comments that LDCs do
not or may not have access to
customers’ EIA or EPA numbers, we
have changed the reporting of this from
required to voluntary, if known. We
have further specified that LDCs must
report large volumes delivered to a
single meter rather than to a particular
end-user.
OO. Suppliers of Industrial GHGs
1. Summary of the Final Rule
Source Category Definition. Suppliers
of industrial GHGs consist of the
following:
• Facilities producing any fluorinated
GHG or N2O, except those that produce
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only HFC–23 generated as a byproduct
during HCFC–22 production.
• Bulk importers of fluorinated GHGs
or N2O, if the total combined imports of
industrial GHGs and CO2 exceed 25,000
metric tons of CO2e per year.
• Bulk exporters of fluorinated GHGs
or N2O, if the total combined exports of
industrial GHGs and CO2 exceed 25,000
metric tons CO2e per year.
Suppliers of Industrial GHGs that
meet the applicability criteria in the
General Provisions (40 CFR 98.2)
summarized in Section II.A of this
preamble must report industrial GHG
supply flows.
GHGs to Report. Suppliers of
industrial GHGs must report the amount
of N2O and each fluorinated GHG
produced, imported, exported,
transformed, or destroyed during the
calendar year. Importers and exporters
of CO2 must calculate and report annual
amounts of CO2 according to 40 CFR
part 98, subpart PP.
GHG Emissions Calculation and
Monitoring. Suppliers must use the
following methods to calculate annual
industrial GHG supply flows:
• The mass of each fluorinated GHG
or N2O produced must be determined by
measurements of gas production, less
the mass of that GHG added to the
process upstream (e.g., where used
GHGs are added back to the production
process for reclamation).
• The mass of each fluorinated GHG
transformed must be determined
considering the mass of fluorinated
GHG fed into the transformation process
and the efficiency of that process (as
indicated by yield calculations or
quantities of unreacted fluorinated
GHGs or nitrous oxide permanently
removed from the process and
recovered, destroyed, or emitted).
• The mass of each fluorinated GHG
destroyed must be determined by
measurements of the mass of fluorinated
GHG fed to the destruction device and
a measurement of the destruction
efficiency.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
industrial GHG supply flows or that can
be used to verify industrial gas supply
flows. A list of the specific data to be
reported for this source category is
contained in 40 CFR part 98, subpart
OO.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
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of additional data used to calculate GHG
emissions. A list of specific records that
must be retained for this source category
is included in 40 CFR part 98, subpart
OO.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart OO:
Suppliers of Industrial GHGs.’’
• EPA has elaborated on the
definition of ‘‘produce’’ to clarify what
it does and does not include. The
definition now explicitly includes (1)
the manufacture of a fluorinated GHG
for use in a process that will result in
the transformation of that GHG (either at
or outside of the production facility)
and (2) the creation of a fluorinated
GHG (with the exception of HFC–23)
that is captured and shipped off site for
any reason, including destruction. The
definition now explicitly excludes the
creation of by-products that are released
or destroyed at the production facility.
• EPA has eased the accuracy and
precision requirements for measuring
production, transformation, and
destruction. EPA is also permitting
facilities flexibility in the frequency of
measurements and calibration of
measurement devices. Masses produced,
fed into transformation processes, and
fed into destruction devices must now
be estimated to a precision and accuracy
of one percent rather than 0.2 percent.
Requirements to measure
concentrations, which had previously
been associated with the transformation
and destruction provisions, have been
changed to requirements to estimate
concentrations or related quantities.
• EPA has eliminated the requirement
that fluorinated GHG production
facilities that destroy fluorinated GHGs
annually verify the destruction
efficiency of their destruction devices.
• EPA has added an additional
method for estimating missing mass
flow data in the event that a secondary
mass measurement for that stream isn’t
available. In that event, producers can
use a related parameter and the
historical relationship between the
related parameter and the missing
parameter to estimate the flow.
• EPA has removed the option for
reporters to develop their own methods
for estimating missing data if they
believe that the prescribed method will
over- or under-estimate the data.
• EPA has added some reporting
requirements to be consistent with the
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changes to the calculations and
monitoring sections and to permit
verification of emissions calculations.
• EPA has added an exemption from
reporting requirements for import or
export shipments containing less than
250 metric tons of CO2e.
• EPA has clarified that the criteria
for imported container heels at
paragraph 98.417(e) set forth the
conditions under which importers do
not need to report heels; they do not
establish requirements for all containers
containing residual gas. If importers
import containers with residual gas that
does not meet these conditions, they
must simply report these imports under
paragraph 98.416(c). In addition, EPA is
adding another condition under which
imported heels do not need to be
reported; that is the case in which the
heels are recovered and included in a
future shipment.
• EPA is requiring fluorinated GHG
production facilities to submit a onetime report describing current
measurement and estimation practices.
EPA is requiring the one-time report
on measurement practices because the
Agency is providing some flexibility to
reporters regarding the methods that
they use to calculate industrial gas
supply flows. This flexibility permits
reporters to use a larger range of
methods and measurement equipment
than were proposed, and it is important
for EPA to understand the methods and
equipment and their accuracies. Similar
reports are required under EPA’s
Stratospheric Ozone Protection
Regulations at 40 CFR part 82.
As noted above, EPA removed the
option for reporters to develop their
own methods for estimating missing
data if they believe that the prescribed
method will over- or underestimate the
data. EPA removed this option for two
reasons. First, the proposed provision
lacked clear guidance on when
alternative methods should be used
(e.g., on the size of an underestimate
that would justify use of an alternative
method) and on how they should be
developed. Second, the proposed
provision was redundant with the new
provision that permits reporters to
estimate missing data using a related
parameter and the historical
relationship between the related
parameter and the missing parameter.
This new option provides reporters with
flexibility in substituting for missing
data in the event that a secondary mass
measurement is not available, but sets
out general guidance on how to select
the substitute data.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on suppliers
of industrial GHGs were received
covering numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart OO:
Suppliers of Industrial GHGs.’’
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Definition of Source Category
Comment: EPA received a number of
comments regarding the proposed
definition of ‘‘fluorinated greenhouse
gas.’’ Several commenters argued that
the proposed definition was too broad
because it would include nonvolatile
materials that could not be emitted to
the atmosphere and materials for which
GWPs had not been calculated. One
commenter suggested establishing a
lower vapor pressure limit for
fluorinated GHGs (heat transfer fluids)
of 400 Pa (0.004 bar, or three mm Hg
absolute) at 25 C. Some commenters
expressed the concern that the lack of
GWPs for some covered compounds
would lead to incomplete or
inconsistent reporting because facilities
would assign their own GWPs to
compounds for which GWPs were not
provided in Table A–1 of 40 CFR part
98, subpart A.
Some commenters recommended that
EPA address these concerns by
requiring reporting of only those
fluorinated compounds listed in Table
A–1 of 40 CFR part 98, subpart A.
However, one of these commenters
noted that the list in A–1 is incomplete
and inconsistent, excluding for
example, some high-GWP compounds
whose low-GWP alternatives are
included. This commenter
recommended that EPA establish a
‘‘visible and participative process’’ to
add other compounds as appropriate to
Table A–1 of 40 CFR part 98, subpart A.
Response: In today’s final rule, EPA is
modifying the proposed definition of
fluorinated GHG by adding an
exemption for ‘‘substances with a vapor
pressure of less than one mm of Hg
absolute at 25 degrees C.’’ This
modification ensures that non-volatile
fluorocarbons such as fluoropolymers
are excluded from reporting
requirements, while requiring reporting
of fluorocarbons (as well as SF6 and
NF3) that could reasonably be expected
to be emitted to the atmosphere.
As noted by several commenters, this
definition would require reporting of
some fluorocarbons to which GWPs
have not been assigned in either IPCC or
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World Meteorological Organization
(WMO) Scientific Assessments (i.e.,
fluorocarbons for which Table A–1 of 40
CFR part 98, subpart A does not provide
GWPs). However, the lack of GWPs for
some fluorocarbons will not impede
reporting because EPA is requiring
reporting of production and other
quantities in tons of chemical rather
than in tons of CO2e. For purposes of
determining whether or not the 25,000
metric ton CO2e import or export
threshold is exceeded, EPA is requiring
facilities to include only substances
whose GWPs appear in Table A–1 of 40
CFR part 98, subpart A.
EPA believes that this approach is
prudent and appropriate. As
acknowledged by commenters, Table A–
1 of 40 CFR part 98, subpart A is not a
complete listing of current or potential
fluorinated GHGs; the IPCC and WMO
lists on which it is based reflect only the
facts that the listed materials have been
synthesized, their atmospheric
properties investigated, the results
published, and the publications found
by the IPCC and WMO Assessment
authors. Table A–1 is known to omit
some existing fluorinated GHGs and it
unavoidably omits future fluorinated
GHGs that have not yet been
synthesized. Given the radiative
properties of the carbon-fluorine bond,
any fluorocarbon emitted into the
atmosphere may have a significant
GWP. This is true even for some
fluorocarbons with lifetimes of less than
one year, including, for example, HFE–
356pcc3, with a lifetime of four months
and a 100-year GWP of 110.
Reporting of fluorocarbons that do not
appear in Table A–1 of 40 CFR part 98,
subpart A will provide valuable
information on the full range of volatile
fluorocarbons entering U.S. commerce.
This information can be used to assess
the overall volume and importance of
compounds for which GWPs have not
been evaluated and to help identify
which compounds should have their
GWPs evaluated first. In addition, once
GWPs have been identified for these
compounds, historical reports in tons of
chemical can be converted into CO2e.
Without a comprehensive reporting
requirement, such historical information
could be lost. Ultimately, all of this
information can be used to inform
policy decisions regarding the
appropriate type and scope of emission
reduction measures for these gases.
Considering the modest cost of reporting
production, import, and export of such
compounds, the potential value of this
information justifies a comprehensive
definition of fluorinated GHG.
EPA agrees with commenters who
noted that Table A–1 of 40 CFR part 98,
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subpart A should be periodically
updated through a visible and
participative process. EPA anticipates
that as GWPs are evaluated or reevaluated by the scientific community,
the Agency will update Table A–1 of 40
CFR part 98, subpart A through notice
and comment rulemaking. EPA may
also, through rulemaking, establish a
more proactive process for ensuring that
GWPs are appropriately evaluated or reevaluated.
Comment: EPA received comments
both supporting and opposing a
requirement to report imports of
fluorinated GHGs contained in
equipment and foams. Commenters
supporting such a requirement noted
that these imports comprised a
significant fraction of U.S. consumption
of fluorinated GHGs, that excluding
these imports from reporting would put
domestic manufacturers at a
disadvantage and lead to leakage of
manufacturing and increased emissions
of GHGs, and that the burden of
reporting these imports would be low,
since there are relatively few importers
and the reported information is easily
accessible. Commenters opposing such a
requirement stated that the benefit of
reporting would be small because precharged equipment and foams are
‘‘hermetically sealed systems that
essentially emit no GHGs,’’ while the
cost would be high due to the large
number of importers.
Response: EPA did not propose to
require reporting of fluorinated GHGs
contained in imported products because
EPA was concerned that the
administrative burden of such a
requirement could be considerable,
while the quantities imported in at least
some types of products could be small.
However, in the proposal EPA
acknowledged that the quantities of
fluorinated GHGs imported in precharged equipment and foams appeared
significant, and that ascertaining the
identity and quantity of fluorinated
GHGs in these products might be
relatively straightforward. EPA is
continuing to research these issues, and
is deferring the final decision on
whether to include imports of
equipment and foams containing
fluorinated GHGs to a later rulemaking.
Monitoring and QA/QC Requirements
Comment: Several commenters stated
that facilities could not meet the
proposed accuracy, precision, and
frequency requirements for their
measurements of production,
transformation, and destruction using
existing equipment and practices. These
commenters stated that they would need
to expend significant funds (millions of
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dollars in some cases) and time to
install Coriolis flowmeters in multiple
streams and to implement daily
sampling protocols to analyze the
contents of these streams. One
commenter requested that EPA revise its
precision and accuracy requirements to
one percent for measurements of mass.
Other commenters argued that instead
of establishing strict accuracy,
precision, and frequency requirements
for measuring production, EPA should
permit facilities to use existing
measurement instruments and practices,
such as NIST Handbook 44 and the trial
HFC reporting program patterned on
EPA’s reporting requirements for ozonedepleting substances.
Response: Given the limited amount
of time before 2010 data collection must
begin, EPA agrees that it is appropriate
to ease the accuracy and precision
requirements proposed for measuring
production, transformation, and
destruction. EPA is therefore revising
these requirements in the final rule.
EPA is also permitting facilities
flexibility in the frequency of
measurements and calibration of
measurement devices.
This approach will permit facilities to
begin measuring their production,
transformation, and destruction for
purposes of the rule beginning in
January 2010, using their current
practices and equipment. However, EPA
is planning to revisit the precision and
accuracy requirements for industrial gas
supply as we review public comments
and perform analyses related to
proposed 40 CFR part 98, subpart L
(fluorinated gas production), which is
not included in today’s final rule. This
is because the accuracy and precision
with which production facilities track
production, transformation, and
destruction can have a profound
influence on the accuracy and precision
of these facilities’ fluorinated GHG
emission estimates. For one method of
monitoring F–GHG emissions under
consideration, a one percent relative
error in production mass measurements
could result in a much higher relative
error in the emissions estimate, e.g.,
over 90 percent at an emission rate of
1.5 percent. For other methods of
monitoring F–GHG emissions, however,
a one percent relative error in
production mass measurements would
not lead to large errors in emission
estimates. For both 40 CFR part 98,
subpart OO and 40 CFR part 98, subpart
L, EPA’s goal is to optimize methods of
data collection to ensure data accuracy
while considering industry burden.
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PP. Suppliers of Carbon Dioxide (CO2)
1. Summary of the Final Rule
Source Category Definition. Under the
rule, suppliers of CO2 consist of the
following:
• Facilities with production process
units that capture and supply CO2 for
commercial applications or that capture
and maintain custody of a CO2 stream
in order to sequester or otherwise inject
it underground.
• Facilities with CO2 production
wells that extract a CO2 stream for the
purpose of supplying CO2 for
commercial applications.
• Importers of bulk CO2, if total
combined imports of CO2 and other
GHGs exceed 25,000 metric tons of CO2
equivalent (CO2e) per year.
• Exporters of bulk CO2, if total
combined exports of CO2 and other
GHGs exceed 25,000 metric tons CO2e
per year.
This source category is focused on
upstream supply. It does not cover:
Storage of CO2 above ground or in
geologic formations; use of CO2 in
enhanced oil and gas recovery;
transportation or distribution of CO2; or
purification, compression, on-site use of
CO2 captured on site, or processing of
CO2. This source category does not
include CO2 imported or exported in
equipment, such as fire extinguishers.
Suppliers of CO2 that meet the
applicability criteria in the General
Provisions (40 CFR 98.2) summarized in
Section II.A of this preamble must
submit GHG reports.
GHGs to Report. Suppliers of CO2
must report the mass of CO2 in a stream
captured from production process units
and extracted from production wells,
and the mass of CO2 in containers that
is imported and exported.
GHG Emissions Calculation and
Monitoring. While this source category
is focused on upstream supply of CO2,
EPA recognizes that all CO2 supplied to
the economy does not necessarily result
in an emission. There are a variety of
downstream applications for CO2—some
applications are emissive and some are
non-emissive. Under this rulemaking, a
CO2 supplier facility must calculate the
mass of CO2 supplied quarterly by
measuring the mass or volumetric flow
of gas and multiplying by the CO2
concentration, and density in the case a
volumetric flow meter is used, of the gas
or liquid, as specified below. EPA
requires quarterly monitoring because
EPA has concluded that the CO2
concentration of the stream varies
throughout the year, and a quarterly
concentration number multiplied by a
quarterly volume will generate more
accurate calculation of CO2 supply than
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56349
annual measurements. EPA requires
these quarterly numbers to be reported
so that EPA can electronically verify the
calculations. The CO2 supplier must
also provide information on the
downstream CO2 application, if known.
Reporters must use the following
methodologies, as applicable, for
calculating CO2 supplied:
• For suppliers that make
measurements with mass flow meters,
calculate quarterly for each meter the
total mass of CO2 in a CO2 stream in
metric tons, prior to any subsequent
purification, processing, or
compressing, according to Equation PP–
1 of 40 CFR 98.423. Measure mass flow
and concentration in accordance with
40 CFR 98.424.
• For suppliers that make
measurements with volumetric flow
meters, calculate quarterly for each
meter the total mass of CO2 in a CO2
stream in metric tons, prior to any
subsequent purification, processing, or
compressing, according to Equation PP–
2 of 40 CFR 98.423. Measure volumetric
flow, concentration and density in
accordance with 40 CFR 98.424.
• For suppliers that have multiple
flow meters, aggregate data according to
methods specified in Equation PP–3 in
40 CFR 98.423.
• Importers or exporters that import
or export CO2 in containers must
calculate the total mass of CO2 supplied
in metric tons, prior to any subsequent
purification, processing, or
compressing, according to equation PP–
4 of 40 CFR 98.423. Use weigh bills,
scales, or load cells to measure the mass
of CO2 imported or exported in
containers.
Data Reporting. In addition to the
information required to be reported by
the General Provisions (40 CFR 98.3(c))
and summarized in Section II.A of this
preamble, reporters must submit
additional data that are used to calculate
CO2 supply. A list of the specific data
to be reported for this source category is
contained in 40 CFR 98.426.
Recordkeeping. In addition to the
records required by the General
Provisions (40 CFR 98.3(g)) and
summarized in Section II.A of this
preamble, reporters must keep records
of additional data used to calculate CO2
supply. A list of specific records that
must be retained for this source category
is included in 40 CFR 98.427.
2. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
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Reporting Rule: EPA’s Response to
Public Comments, Subpart PP:
Suppliers of Carbon Dioxide.’’
• We added equations and QA
requirements to allow reporters to
determine CO2 quantity using
volumetric flow meters, weigh bills,
scales, or load cells, as appropriate.
These additions supplement the
proposed equations and quality
assurance requirements to determine
CO2 quantity using mass flow meters.
• We revised the reporting
procedures for missing data in 40 CFR
98.425. Facilities must use quarterly
values as substitute data as they can no
longer use annual average values. We
added missing data procedures to allow
for more quarterly data points to be
used, as appropriate. EPA concluded
that quarterly missing data values will
generate more accurate estimates than
annual average values.
• To improve the emissions
verification process, we reorganized and
updated 40 CFR 98.426. We moved
some data elements from 40 CFR 98.427
to 40 CFR 98.426, and added some data
elements that a reporter must already
use to calculate GHGs as specified in 40
CFR 98.423 to 40 CFR 98.426 for clarity.
• We revised the reporting and
calculation procedures to require
facilities using flow meters to determine
annual mass for every flow meter used.
To aggregate data at the facility level for
CO2 being captured in production wells
or production process units, we have
added Equation PP–3.
• To decrease unnecessary sampling
burden, we have removed the
requirement of quarterly concentration
sampling for importers and exporters
that use containers of CO2.
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3. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on suppliers
of CO2 were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Subpart PP:
Suppliers of Carbon Dioxide.’’
Definition of Source Category
Comment: EPA received many
comments about how we defined the
source category in this Subpart. One
group of comments stated that the CO2
supplied to the economy should not be
characterized as an emission. Some in
this group of comments specified that
much of the supplied CO2 is stored at
enhanced oil recovery (EOR) sites,
which are ‘‘closed systems’’, rather than
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emitted. In general, these same
commenters stated that any CO2
reporting requirements placed by EPA
on industry should be placed on
downstream CO2 users, such as EOR
facilities, rather than CO2 suppliers and
should be for actual emissions only.
Other comments echoed that EPA needs
to collect data from recipients of
supplied CO2 such as EOR sites. This
group pressed upon EPA the need to
collect not only data on actual
emissions but also data on injection,
production, and geologic sequestration
of CO2. Some of the benefits cited for
collecting such comprehensive data
include: Assisting in ensuring no more
than negligible releases at a facility if it
is properly sited, designed, and
permitted; achieving full public
accountability of CO2 geologic
sequestration effectiveness; and tracking
the CO2 throughout the entire carbon
dioxide capture and sequestration (CCS)
chain for the purposes of adjusting CO2
emissions reported or assigning offsets.
Along those lines, some commenters
urged EPA to rely on or expand the
existing underground injection control
(UIC) program to deal with CCS.
Response: EPA did not intend to
characterize all CO2 supplied to the
economy as emissions and recognizes
that there are a variety of applications
for CO2, both emissive and nonemissive. CO2 supplied to the economy
would result in an emission if the CO2
were used in an application which
would ultimately result in release of the
CO2 to the atmosphere. EPA is also
collecting information from upstream
suppliers in other subparts of this
rulemaking such as natural gas supply
and petroleum product supply.
EPA recognizes that, in order to
determine whether or not supplied CO2
has been or will be released to the
atmosphere (e.g., emitted), the Agency
needs information on the downstream
CO2 end-use. In today’s final
rulemaking, CO2 suppliers must provide
information on the downstream CO2
application, if known. EPA believes
information on the end-use will provide
some idea of the amounts of CO2 which
are emitted. Where that end-use is
geologic sequestration (at EOR or other
types of facilities), EPA will need
additional information on the amount of
CO2 that is permanently and securely
sequestered and on the monitoring and
verification methodologies applied.
With respect to EOR, the geology of an
oil and gas reservoir can create a good
barrier to trap CO2 underground.
Because these formations effectively
stored oil or gas for hundreds of
thousands to millions of years, it is
believed that they can be used to store
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injected CO2 for long periods of time.
However, EPA also recognizes that the
requirements to identify a suitable GS
site extend beyond geophysical trapping
parameters alone and include: The
evaluation and appropriate management
of potential leakage pathways,
appropriate rate and pressure of
injection, appropriate monitoring, and
other such features. While some amount
of CO2 injected into oil and gas
reservoirs for EOR purposes will be
trapped in the subsurface, these and
other site-specific elements influence
the amount of CO2 securely sequestered
and the potential for release of CO2
during EOR operations.
Given the comments in support of
downstream data collection, particularly
with respect to EOR systems and CO2
geologic sequestration (at EOR or other
types of facilities), EPA plans to issue a
new proposal on geologic sequestration
and will consider how to address
emissions and sequestration at active
EOR facilities. EPA will take action on
this issue in the near future with the
goal that data collection for these types
of facilities can begin as quickly as
possible. EPA will seek comment on
monitoring, reporting, and verification
methodologies which can be used to
determine the amount of CO2 emitted
and geologically sequestered at active
EOR facilities and geologic
sequestration sites where CO2 is injected
(for long-term storage) into saline
aquifers, oil and gas reservoirs, or other
geologic formations. Furthermore, as
stated in Section III.W of this preamble,
EPA plans to take additional time to
consider alternatives to data collection
procedures and methodologies in the
proposed 40 CFR part 98, subpart W and
will consider inclusion of GHG
reporting from other sectors of the oil
and gas industry besides those proposed
for reporting in proposed 40 CFR part
98, subpart W. EOR surface facility
operations may be part of those
considerations. The data reported under
subsequent regulatory actions and the
data reported under today’s rulemaking
will together enable EPA to understand
the amount of CO2 supplied, emitted,
and sequestered in the U.S., to carry out
a wide variety of CAA provisions. The
options that we will have considered
and the resulting recommended
approaches will be further fleshed out
through a notice and comment process.
See the next comment response for a
discussion of why EPA still needs to
collect CO2 supplier data in today’s
rulemaking even though a new
rulemaking on sequestration is planned.
In response to comments that EPA
should rely on or expand the UIC
program to address emissions of CO2,
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that issue is outside the scope of this
rulemaking. However, EPA agrees that
the UIC program and EPA’s authority
under the Safe Drinking Water Act
(SDWA) will provide a foundation for
ensuring safe and effective containment
of CO2. However, SDWA is focused on
permitting sites for protection of ground
and drinking water; the new proposal
discussed above will be designed to
address issues related to the CAA. EPA
intends to harmonize CCS requirements
across relevant statutory or other
programs in order to minimize any
redundancy and any burden on
reporters. The reporting requirements in
today’s rulemaking for CO2 suppliers
and the reporting requirements in new
rulemaking for CO2 geologic
sequestration sites will complement
each other and together they can be
harmonized with reporting
requirements under the UIC proposed
rulemaking. In a new CAA rulemaking
on geologic sequestration reporting, EPA
will rely on UIC permit requirements to
the maximum extent possible. EPA will
seek comment on these issues and will
also endeavor to issue a geologic
sequestration GHG reporting rule in the
same time frame as it has planned for
the stand-alone UIC GS rulemaking.
Comment: EPA received comments
requesting information on how CO2
supply will assist EPA in developing
future climate policy. Commenters
stated that they do not believe CO2
supply data will provide EPA with
useful information. Commenters stated
that data collection from CO2 suppliers
does not fit within EPA’s mandate from
Congress to measure upstream
emissions only as appropriate.
Response: As discussed in Sections
I.C and II.Q of this preamble, EPA is
collecting data from CO2 suppliers in
today’s rule to carry out a wide variety
of CAA provisions, as authorized
broadly under CAA Sections 114 and
208. For example, this data will enable
EPA to evaluate the appropriate action
to take under section 103 regarding nonregulatory strategies for pollution
prevention. It will also inform
evaluation of possible CAA regulation of
the supplier and/or recipient of the CO2
Data on CO2 supply to the economy will
allow EPA to make a well informed
decision about whether and how to use
the CAA to regulate facilities that
capture, sequester, or otherwise receive
CO2 as an end-user.
Though CO2 capture and geologic
sequestration are occurring now on a
relatively small scale, CCS is expected
to play a major role in mitigating GHG
emissions from a wide variety of
stationary sources. According to the
Inventory of U.S. Greenhouse Gas
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17:39 Oct 29, 2009
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Emissions and Sinks: 1990–2007 (EPA,
April 2009), stationary sources
contributed 67 percent of the total CO2
emissions from fossil fuel combustion in
2007. The stationary sources represent a
wide variety of sectors amenable to CO2
capture; electric power plants (existing
and new), natural gas processing
facilities, petroleum refineries, iron &
steel foundries, ethylene plants,
hydrogen production facilities,
ammonia refineries, ethanol production
facilities, ethylene oxide plants, and
cement kilns. Furthermore, 95 percent
of the 500 largest stationary sources are
within 50 miles of a candidate CO2
reservoir.22
With this rule, EPA will begin
building capacity to track the growth in
CO2 supply and learn about its
disposition throughout the economy.
EPA has concluded that we need data
now from CO2 suppliers—both
industrial facilities and CO2 production
wells—in order to effectively track how
the supply sources will change over
time. For example, we will need to track
if and by how much CO2 captured from
industrial facilities will offset or
displace CO2 produced from natural
formations. Even after EPA begins
collecting data on CO2 geologic
sequestration under the proposed new
rulemaking (discussed above), EPA will
continue to need data from CO2
suppliers in order to track any CO2 that
is not sequestered.
Comment: EPA received some
comments asking whether a specific
situation results in coverage under 40
CFR part 98, subpart PP, and some
comments requesting that their specific
situation be exempt from coverage. For
example, one commenter asked whether
a facility separating CO2 that is not
supplied to downstream customers is a
covered facility. Another asked that a
pulp and paper mill that transfers a CO2
stream to an adjacent facility by
pipeline be exempt from 40 CFR part 98,
subpart PP. Several commenters
requested clarification on specific
scenarios such as taking ownership of
an already separated CO2 stream for
further processing, separating CO2 for
their own use, and operating versus
owning the separation unit.
Response: EPA did not intend for 40
CFR part 98, subpart PP to cover
facilities that take ownership of a CO2
stream that has already been separated
22 Dooley, JJ, CL Davidson, RT Dahowski, MA
Wise, N Gupta, SH Kim, EL Malone, ‘‘Carbon
Dioxide Capture and Geologic Storage: A Key
Component of a Global Energy Technology Strategy
to Address Climate Change.’’ Joint Global Change
Research Institute, Battelle Pacific Northwest
Division. May 2006. PNWD–3602. College Park,
MD.
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and removed from a manufacturing
process or that has already been
extracted from CO2 production wells in
order to do any of the following: Store
it in above ground storage of CO2;
transport or distribute it via pipelines,
vessels, motor carriers, or other means;
purify, compress, or process it; or sell it
to other commercial applications. 40
CFR part 98, subpart PP covers facilities
that own or operate the equipment that
physically separates and removes CO2
from an industrial or manufacturing
process or physically extracts CO2 from
production wells because we concluded
that the entity with first touch of the
CO2 supply was the most logical point
of coverage. We wanted to minimize any
unnecessary duplicative reporting of the
same CO2 by being as specific as
possible about who in the supply chain
is responsible for reporting it.
We did not intend for this source
category to include facilities that
capture CO2 for further processing or
use within the fence line of the facility
(e.g., for their own use). EPA proposed
that 40 CFR part 98, subpart PP only
cover CO2 that is captured or extracted
for purposes of sequestration or supply
to other facilities for commercial
applications because we concluded that
CO2 captured and used on-site is
equivalent to an intermediary step in
production rather than an actual supply
of CO2.
Comment: EPA received a comment
requesting that ethanol plants and other
facilities capturing CO2 from biomass be
exempt from Subpart PP.
Response: A long standing inventory
convention adopted by the IPCC, the
UNFCCC, the US GHG Inventory, and
many other reporting programs is
separate treatment of emissions of CO2
from the combustion of biomass and
biomass-based fuels from emissions of
CO2 from the combustion of fossil-based
products. In national inventories,
emissions from the combustion of
biomass-based fuels are accounted for as
part of a comprehensive system-wide
tracking of carbon dioxide emissions
and sequestration in the land-use, landuse change and forestry sector and the
agriculture sector, rather than at the
point of fuel combustion. Consistent
with this approach, in the proposed and
final rule, downstream emitters must
only consider non-biogenic emissions
when conducting a threshold analysis;
however, downstream emitters must
report both biogenic and non-biogenic
emissions once they trigger the
reporting threshold because data on
non-biogenic emissions is useful and
informative.
For the final rule, EPA has decided
not to apply the same approach to
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suppliers of CO2. We have concluded
that data on capture of biogenic CO2
would be useful and informative
because biogenic CO2 can potentially be
stored in GS sites, or displace fossil CO2
applications. We need a full picture of
the CO2 being supplied into the
economy. Though CO2 capture and
sequestration is occurring now on a
relatively small scale, it is expected to
play a major role in mitigating GHG
emissions. Therefore information on all
potential sources of CO2 for
sequestration is necessary for a
complete picture. Thus, a facility that
captures CO2 from biomass and
otherwise meets the applicability test is
covered under 40 CFR part 98, subpart
PP and is required to report all CO2
supplied along with the percentage of
that supply that is biomass-based.
Monitoring and QA/QC Requirements
Comment: A large number of
commenters requested that volumetric
flow meters be allowed for purposes of
calculating CO2 supply in place of or in
addition to mass flow meters. These
comments indicated that mass flow
meters are not in operation at many
covered facilities, and the cost to
comply with such an equipment
requirement would be unnecessarily
high. Some commenters suggested that
reporters should be allowed to use sales
contracts to determine quantity of CO2
as long as the CBI is protected. Some
commenters indicated that CO2
liquefaction and purification facilities
do not operate flow meters for the
course of usual business. One of these
also commented that importers and
exporters of CO2 do not operate flow
meters for the course of usual business
if they handle the product in containers
and requested consideration of this
incongruity.
Response: As a result of these
comments, EPA added two equations to
the methodology section of 40 CFR part
98, subpart PP in today’s rule in order
to ensure that all covered CO2 can be
reported, irrespective of technical or
physical conditions. Therefore, a
reporter that measures CO2 in a stream
using a volumetric flow meter may use
this volumetric flow meter to determine
quantity rather than having to purchase
and install a mass flow meter. EPA has
concluded that providing this additional
methodology reduces the burden on
reporters without compromising the
quality of data received by the agency.
In addition, a reporter that imports or
exports CO2 in containers may use
weigh bills, scales, or load cells to
determine quantity because applying a
mass flow meter would be technically
impossible. EPA has concluded that
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providing this additional methodology
reduces the burden on reporters without
compromising the quality of data
received by the agency.
The final rule does not require
reporting from facilities that liquefy or
purify CO2 that has already been
separated or removed from a
manufacturing process or already
extracted from production wells.
Therefore we did not give consideration
to the types of equipment in operation
at such facilities.
Finally, the rule does not allow
reporters to use sales contracts to
determine quantity because EPA has
concluded that reporters capturing or
extracting CO2 already operate mass or
volumetric flow meters, or already
determine quantities of CO2 imported or
exported in containers using weigh
bills, scales, or load cells. EPA has
concluded that mass and volumetric
flow meters provide more accurate data
than sales contracts.
IV. Mobile Sources
A. Summary of Requirements of the
Final Rule
For manufacturers of engines used in
mobile sources outside of the light-duty
sector,23 this rule includes new
requirements for reporting emission
rates of GHGs.24 Mobile source engine
manufacturers have been measuring CO2
emission rates from their products for
many years as a part of normal business
practices and existing criteria pollutant
emission certification programs, but
they have not consistently reported
these values to EPA. This final rule
requires manufacturers to consistently
measure and report CO2 for all engines
beginning with model year 2011 and
other GHGs in subsequent model
years.25 Manufacturers meeting the
definitions of ‘‘small business’’ or
‘‘small volume manufacturer’’ under
EPA’s existing mobile source emissions
regulations will generally be exempt
from any new GHG reporting
requirements.26
23 Manufacturers of light-duty vehicles, light-duty
trucks, and medium-duty passenger vehicles are not
covered in this final rule.
24 The term ‘‘manufacturer,’’ as well as the term
‘‘manufacturing company,’’ as used in this
preamble, means companies that are subject to EPA
emission certification requirements. This primarily
includes companies that manufacture engines
domestically and foreign manufacturers that import
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 engines.
25 For aircraft engine manufacturers, reporting
requirements will apply for the engine models in
production in 2011.
26 Small business manufacturers will continue to
be subject to measurement and/or reporting
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In addition to CO2, most
manufacturers will now be required to
report on two other major GHGs emitted
by mobile sources, nitrous oxide (N2O)
and methane (CH4). Although most
current engines have relatively low
emission rates of these GHGs compared
to CO2, these compounds have global
warming potentials significantly higher
than CO2. It is important that EPA
improve its understanding of these
emissions from today’s engines and
monitor trends over time. The broad
base of emission data that will begin to
accrue from requirements in this rule
will support emissions modeling by
EPA and others, and will help guide
future GHG policy.
Emissions of N2O are related to
catalytic treatment of engine exhaust,
specifically aftertreatment of NOX
emissions. Therefore, we will require
that manufacturers begin to measure
and report N2O emissions, but only for
engine models that incorporate NOX
aftertreatment technology (as shown in
Table IV–1 of this preamble). The
program will not require N2O reporting
before model year 2013, and the
requirements will only apply to new
engines equipped with NOX
aftertreatment technology.
(Manufacturers of some engine
categories have employed aftertreatment
for many years to meet NOX standards;
for other engine categories,
manufacturers are unlikely to introduce
NOX aftertreatment technologies for
some years to come.)
Emissions of CH4 are a part of overall
hydrocarbon emissions from mobile
sources. Because CH4 is not very
reactive in the atmosphere, EPA has
often excluded CH4 from mobile source
hydrocarbon regulations since it has not
traditionally been a major determinant
of ozone formation.27 The new reporting
requirements are necessary to evaluate
the magnitude of mobile source CH4
emissions from a GHG (rather than
ozone precursor) perspective.
As described above, we are finalizing
manufacturer reporting requirements for
N2O and CH4 emission rates in order to
understand current emissions of these
GHGs and to monitor potential changes
as technologies and policies change in
the future. However, we believe that
manufacturers may be able to provide
requirements for compliance with existing
regulations.
27 But see Ford Motor Co. v. EPA, 604 F. 2d 685
(D.C. Cir. 1979) (permissible for EPA to regulate
CH4 under CAA section 202 (b)). In addition,
although CH4 is not itself regulated, manufacturers
subject to ‘‘non-methane hydrocarbon’’ standards
have needed to determine CH4 emission levels, in
some cases by using a default value and in many
cases by way of testing.
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alternative test data (and/or other
information including engineering
judgments based on test data) that
would give EPA a reasonable basis for
estimating the likely N2O and CH4
emission rates for each certified engine
family. Therefore, we are including a
provision in this final rule that would
allow a manufacturer the opportunity to
provide such alternative information in
lieu of N2O and/or CH4 test data for each
engine family.
In assessing such alternative
information, EPA would consider how
well the information provided by the
manufacturer allows EPA to reasonably
anticipate the emission performance of
each of the manufacturer’s engines. For
example, we expect that in most cases
a manufacturer wishing to omit engine
testing will provide EPA with N2O test
data from relevant testing programs (by
such sources as industry collaboratives
and/or from the suppliers of the
catalytic NOX aftertreatment systems
they are using on an engine. We would
expect the manufacturer to also include
an explanation of the manufacturer’s
engineering judgment as to why the data
should apply to the engine family in
question. For CH4 emissions, our
primary concern is the potential for
unusually high emissions from natural
gas fueled engines. Thus, we expect that
in most cases a manufacturer of such an
engine will provide test data on similar
engines with similar catalyst systems for
hydrocarbon control (with an
explanation of their engineering
judgment as to why the data should
apply to that engine family).
The reporting requirements related to
C3 marine engines and turbofan and
turbojet aircraft engines differ from
other engine categories. As with other
manufacturers, C3 marine engine and
aircraft engine manufacturers will report
CO2 emission rates beginning in 2011
(for aircraft engines, they will report
CO2 separately for each mode of the
landing and take-off (LTO) cycle used in
the certification test, as well as the
entire LTO cycle). For aircraft engine
manufacturers, however, the reporting
requirements will apply not just to
engines introduced in that year, but for
all engines still in production. (This
should not require manufacturers to
conduct any new testing, only to report
existing data.) We are not requiring
manufacturers of C3 marine engines and
aircraft engines to measure or report
N2O or CH4 emission rates because of
unique aspects of their industries and
technologies.
C3 marine engines are very large and
manufacturers generally test them as
they are installed into ships rather than
in a laboratory setting. For this reason,
we have determined that requiring the
addition of new N2O and CH4
measurement equipment for C3 engines
would not be practical, and, as
proposed, are not requiring such
reporting in this rule.
Since aircraft engine manufacturers
are unlikely to employ NOX after
treatment devices in the foreseeable
future, we did not propose requiring
N2O reporting from aircraft engines and
are not finalizing any requirements in
this final rule. We are not finalizing our
proposed requirement that aircraft
engine manufacturers measure and
report CH4, as we learned that aircraft
jet turbine engines have been shown to
56353
consume CH4 from the ambient air
during the dominant operating modes.28
However, unlike NOX emissions from
most mobile sources, NOX emissions
from aircraft have been shown to make
a potential contribution to climate
change.29 For this reason, we are
requiring that aircraft engine
manufacturers report the NOX emission
data for the LTO modes and the overall
LTO cycle for all engine models
currently in production, and for new
engines as they are introduced.
Manufacturers are already measuring
NOX as part of current criteria pollutant
certification requirements. NOX
emissions rate data from LTO modes
will support modeling of overall NOX
emissions from aircraft.
For all engine categories, when a
manufacturer certifies the engine in one
year and then carries over the
certification to subsequent years, EPA
will not require re-testing of that engine
model for reporting purposes.
As proposed, we are not including
any requirements for mobile source fleet
operators or State and local
governments to report in-use travel
activity or other emissions-related data
in this final rule.
Table IV–1 of this preamble shows the
basic reporting requirements we are
finalizing in this notice for each engine
category. We discuss in more detail how
these reporting requirements will apply
to manufacturers of each engine
category in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Motor Vehicle and
Engine Manufacturing.’’
TABLE IV–1—FIRST MODEL YEAR FOR GHG REPORTING REQUIREMENTS
Engine category
N2Oa
CO2
Highway Heavy-Duty (engine and vehicle) ............................................................
Nonroad Diesel .......................................................................................................
Marine Diesel (other than C3) ................................................................................
C3 Marine ...............................................................................................................
Locomotives ............................................................................................................
Small Spark-Ignition ................................................................................................
Large Spark-Ignition ...............................................................................................
Marine Spark-Ignition ..............................................................................................
Snowmobiles ...........................................................................................................
Highway Motorcycles ..............................................................................................
Off Highway Motorcycles/ATVs ..............................................................................
Aircraft b ...................................................................................................................
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2011
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
None ...................................
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
2013 or NOX AT .................
None ...................................
a N O reporting for new engines begins in 2013 or when the manufacturer introduces NO aftertreatment technology, whichever is
2
X
b Applies to all turbofan and turbojet engines in production in 2011 with a rated output greater than 26.7 kilonewtons. Reporting
CH4
2012
2012
2012
None
2012
2012
2012
2012
2012
2012
2012
None
later.
of NOX also
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28 Aerodyne, Rich Miake-Lye, AAFEX Methane
presentation at the Seventh Meeting of Primary
Contributors for the Aviation Emissions
Characterization Roadmap, June 9–10, 2009.
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29 IPCC, Aviation and the Global Atmosphere,
1999, at https://www.grida.no/climate/ipcc/aviation/
index.htm, and NOAA, Written Testimony of Dr.
David W. Fahey, Hearing on ‘‘Aviation and the
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Environment: Emissions,’’ Before the Committee on
Transportation and Infrastructure, Subcommittee on
Aviation, U.S. House of Representatives, May 6,
2008.
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B. Summary of Major Changes Since
Proposal
The major changes since proposal are
identified in the following list. The
rationale for these and any other
significant changes can be found below
or in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Motor Vehicle and
Engine Manufacturers.’’
• We are not finalizing the proposed
requirements related to light-duty
vehicles (including light-duty trucks
and medium-duty passenger vehicles).
EPA expects to propose a
comprehensive light-duty GHG
emission control program commencing
in MY 2012 (see Notice of Upcoming
Joint Rulemaking to Establish Vehicle
GHG Emissions and CAFE Standards,
74 FR 24007 (May 22, 2009)), which is
likely to contain monitoring, reporting
and GHG data retention requirements
that would supersede any reporting
requirements established in this rule.
Eliminating light-duty reporting
requirements from this final rule will
avoid issues of inconsistency and
duplication.
• We have revised our proposal that
all engine manufacturers measure and
report N2O for all of their engines, and
instead will require N2O reporting only
for engines that use NOX exhaust
aftertreatment technology.
• We have delayed the proposed MY
2011 start year for N2O reporting until
MY 2013, and later for categories where
the manufacturer has not applied NOX
aftertreatment technology.
• We have added additional emission
test methods that manufacturers can
choose for measuring N2O, to assure that
an appropriate method is available for
any foreseeable circumstance (including
the need to measure very low N2O
emission rates).
• The final rule incorporates an
opportunity for a manufacturer to
provide EPA with appropriate
alternative information in lieu of N2O
and/or CH4 testing, as described above.
• We have added one year of lead
time to the proposed start year for
reporting of CH4 emissions, until 2012.
• We are not finalizing our proposal
to require reporting of CH4 for aircraft
engines because, for the dominant
operating modes, jet engines may
consume CH4 in the air.
• We are finalizing a requirement that
we took comment on in the proposal to
have aircraft engine manufacturers
report NOX emissions data they already
collect, since, at altitude, NOX
emissions from aircraft have been
shown to make a potential contribution
to climate change.
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• Since aircraft engines are not
certified every year (there is no annual
certification as is the case with other
mobile sources), we have removed
references to ‘‘model year’’ in the
regulations and revised them to reflect
the change to a January 1, 2011 start
date for reporting CO2 and NOX
emissions.
C. Summary of Comments and
Responses
This section contains a brief summary
of major comments and responses. A
large number of comments on mobile
source were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Motor Vehicle and
Engine Manufacturers.’’
Comment: Light-duty vehicle
manufacturers and their trade
organizations raised several concerns
about the timing and nature of the
reporting requirements.
Response: We agree in part with these
comments. However, more
fundamentally, we have concluded that
the likelihood of GHG emission
regulations affecting light-duty vehicles
(including light-duty trucks and
medium-duty passenger vehicles) in the
near future argues for consolidating any
new GHG reporting requirements into
that upcoming rule. Therefore, we have
elected to not finalize the proposed
requirements relating to these vehicles
at this time, and expect to incorporate
similar provisions in a proposed rule on
GHG standards for light-duty vehicles in
the near future.
Comment: Engine manufacturers and
their trade organizations challenged the
proposed rule in several ways. In
general, they questioned the need for
the data to be reported; expressed
concern that the proposed timing of the
requirements, especially for N2O and
CH4, was too aggressive; and
commented that the proposed test
procedure for N2O was not adequate.
Response: We still conclude that there
is significant value to collecting CO2,
N2O, and CH4 emissions rate data on the
broad range of mobile sources being
produced. As stated earlier, the
domestic and international attention to
GHGs and their effects will only grow,
and the ability for EPA and the public
to understand and monitor emissions
from mobile sources will be increasingly
important as policies relating to GHGs
are considered. Collecting emissions
rate data from engine manufacturers on
their new engines can improve
modeling of emissions for the entire
mobile source sector since current
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modeling relies on assumptions about
N2O and CH4 emissions based on a
limited number of field surveys. The
data from this rule will also help EPA
track emissions impacts from changes in
technologies and policies over time.
For N2O and CH4, we agree that
revisions in the proposed provisions are
warranted. We have limited the
reporting requirements for N2O to
engines equipped with NOX
aftertreatment technology as a way to
reduce the reporting burden on engine
manufacturers without significantly
diminishing the amount of information
we receive. As discussed earlier,
emissions of N2O are related to catalytic
treatment of engine exhaust, specifically
aftertreatment of NOX emissions, and
we have concluded that collecting N2O
emissions data from engines without
NOX aftertreatment technology would
provide marginal value to the agency.
We expanded the number of approved
test methods for N2O measurement
since we learned from comments and
our own technical research that our
proposed test methods for N2O were not
appropriate for every foreseeable
circumstance, including measurement
of very low levels of N2O. We also
extended the lead time available to
manufacturers before N2O and CH4
reporting is required. We are providing
this flexibility based on our conclusion
that we can reduce the burden of
purchasing and installing the required
CH4 and N2O emissions rate
measurement equipment by extending
the lead time, without significantly
diminishing the amount of information
we receive. Finally, as described above,
the final rule includes an opportunity
for a manufacturer to provide EPA with
appropriate alternative information in
lieu of N2O and/or CH4 testing.
Comment: States and environmental
organizations were generally supportive
of the proposed reporting requirements,
although some argued for earlier
implementation, in 2010.
Response: We believe that the lead
times we are finalizing for each GHG
and for each engine category represent
the earliest feasible timing, taking into
consideration existing test capabilities
and past experience, or the lack thereof.
Comment: Aircraft engine
manufacturers commented that
reporting of CO2 emissions from each
mode of the LTO 30 cycle used in the
emission certification test, as proposed,
is acceptable as long as existing
methods for CO2 are retained. In
particular, commenters noted that
reporting would result in minimal
30 Modes of the landing and takeoff cycle are taxi/
idle, takeoff, climb out, and approach.
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burden as long as CO2 is calculated
utilizing the engine fuel mass flow rate
measurements, which are currently part
of the test procedure requirements for
the LTO cycle. However, an industry
trade association expressed concern that
reporting CO2 from the LTO cycle is
unjustified because LTO measurements
do not include CO2 emissions from an
entire aircraft flight, which is affected
by the propulsion system, drag, etc.
Response: We determined that
calculating aircraft engine CO2
emissions from fuel mass flow rate
measurements is an appropriate method
for reporting CO2 emissions. Therefore,
for turbofan and turbojet engines of
rated output greater than 26.7
kilonewtons, we are finalizing that
manufacturers report CO2 separately for
each mode of the LTO cycle by
calculation of CO2 from fuel mass flow
rate measurements or, alternatively,
according to the measurement criteria
for CO2 in Appendices 3 and 5 to ICAO
Annex 16, volume II. Comprehensive
and consistent reporting of LTO CO2
emissions, along with knowledge of
aircraft aerodynamic performance, will
support modeling of full-flight CO2
emissions and help us to better
understand overall contributions to
global warming from aircraft operations.
Comment: Aircraft engine
manufacturers raised two major issues
related to our proposed CH4 reporting.
First, in response to EPA’s request for
comment on the degree to which engine
manufacturers now have the needed
equipment in their certification test
cells to measure CH4, manufacturers
replied that test stands are not currently
equipped to measure CH4, and thus,
they would incur additional costs to
measure CH4. Second, manufacturers
noted that aircraft jet turbine engines
have been shown to be consumers of
CH4 from the ambient air during the
dominant operating modes (CH4 is
emitted at aircraft engine idle operation,
but at higher power modes aircraft
engines usually consume CH4. Over the
range of engine operating modes—
including cruise—aircraft engines are
typically net consumers of CH4).
Response: Given that aircraft engines
are likely net consumers of CH4 and that
manufacturers do not currently collect
CH4 data as part of existing test
procedures, we are not requiring CH4 to
be measured and reported at this time.
Comment: We received several
responses to our request for comment on
whether to require aircraft engine
manufacturers to report NOX emissions
in the four LTO test modes and for the
overall LTO cycle. Manufacturers
commented that NOX emissions do not
need to be reported directly to EPA,
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since this information is already
voluntarily reported to the International
Civil Aviation Organization (ICAO) and
provided to the Federal Aviation
Administration (FAA), and redundancy
of reporting is unnecessary.
Environmental organizations
commented that EPA should require
manufacturers to report NOX since they
currently do not report the data to EPA.
In addition, environmental
organizations commented that NOX at
high altitude can contribute to global
warming.
Response: In this final rule, we are
requiring that engine manufacturers of
turbofan and turbojet engines of rated
output greater than 26.7 kilonewtons
record and report NOX emissions in the
four LTO test modes and for the overall
LTO cycles. As discussed in the
proposal and earlier in this final rule,
NOX from aircraft have been shown to
make a potential contribution to climate
change at high altitude. As required in
40 CFR part 87, manufacturers must
already measure and record NOX
emissions in each of the four LTO test
modes in order to comply with the LTO
NOX emission standard (for the entire
LTO cycle). These data are not currently
reported to EPA for public consideration
as is the case with all other mobile
sources. Manufacturers voluntarily
report the data to ICAO, but there is no
assurance that EPA will receive this
information. Likewise, the information
provided to FAA is not readily
accessible to EPA, and it is not of the
detail provided to ICAO.
Comprehensive and consistent reporting
of LTO NOX emissions rate data will
support modeling of overall NOX
emissions from aircraft and help us to
better understand overall contributions
to global warming from aircraft
operations.
V. Collection, Management, and
Dissemination of GHG Emissions Data
This section of the preamble describes
the general processes by which EPA
intends to collect, manage, and
disseminate data under the GHG
reporting rule. Section A contains a
brief description of the provisions in the
final rule concerning these processes,
and Section B summarizes public
comments and responses on data
collection, management, and
dissemination.
Major changes since proposal include
revisions in 40 CFR 98.4 that provide
flexibility for designated representatives
to delegate their responsibility to agents,
and to submit revisions to the certificate
of representation within 90 days of a
change in owners or operators (rather
than 30 days). In addition, the final rule
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includes a requirement that the
designated representative submit the
certificate of representation at least 60
days before the deadline of the facility
or supplier’s initial GHG report. The
rationale for these and any other
significant changes can be found in
Section V.B of this preamble or in
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments, Designated Representative,
and Data Collection, Reporting,
Management, and Dissemination.’’
A. Summary of Data Collection,
Management and Dissemination for the
Final Rule
1. Designated Representatives, Alternate
Designated Representatives, and Agents
Each covered facility and each
supplier must identify one and only one
designated representative who is
responsible for certifying, signing, and
submitting all submissions to EPA. A
designated representative must certify
and sign a submission, in accordance
with the final rule, before it is
considered a complete submission.
The designated representative also
serves as a single point of contact for
EPA to provide information about the
program or a submission or to ask
questions about a submission. Those
facilities submitting any other emission
report under 40 CFR part 75, for
example, ARP facilities, must use the
same designated representative for
certifying, signing and submitting all
submissions and reports under this rule.
Each covered facility or supplier may
also identify one alternate designated
representative to act in lieu of the
designated representative. The alternate
designated representative can perform
the same duties as the designated
representative, but the designated
representative is responsible for
ensuring the appropriate information is
submitted to EPA by the timelines
specified in the rule.
A designated representative or
alternate designated representative may
delegate the submission of information
to one or more ‘‘agents.’’ The agent can
make electronic submissions to EPA,
but is not allowed to certify or sign a
submission. By delegating to an agent
the ability to make electronic
submissions to EPA, a designated
representative or alternate designated
representative agrees that a submission
to EPA by the agent is deemed to be a
submission that is certified, signed, and
submitted by such designated
representative or alternate designated
representative.
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2. Certificate of Representation
A designated representative must
submit a certificate of representation
that identifies the owners and operators
of the facility or supplier, the designated
representative, any alternate designated
representative, and other information as
specified in 40 CFR 98.4. EPA will
establish an electronic data reporting
system that provides for the submission
of initial, as well as subsequently
signed, certificates of representation.
In order to ensure sufficient
processing time before a facility or
supplier’s initial GHG report under this
part, EPA is requiring that the
designated representative submit a
certificate of representation at least 60
days before the deadline for the initial
GHG report.
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3. Data Collection
Methods. If a reporting entity already
reports GHG emissions data to an
existing EPA program, the Agency will
make efforts to minimize any additional
burden on the reporter when developing
the reporting system for the final rule.
Some existing programs, however, have
data collection and reporting
requirements that are inconsistent with
the requirements for the mandatory
GHG reporting rule. When it is not
feasible to adapt an existing program to
collect the appropriate GHG data and
supplemental data, EPA will require
reporters to submit the data required by
the mandatory GHG reporting rule to the
new data reporting system for this rule.
Such reporters would also continue to
submit data to the existing reporting
systems for other applicable programs as
required by those programs.
Reporters may fall into one or more
categories:
(1) Reporters that use existing data
collection and reporting methods and
will not be required to report separately
to the new data reporting system for the
GHG reporting rule.
(2) Reporters that use existing data
collection and reporting methods but
will be required to report the data
separately to the new data reporting
system for the GHG reporting rule.
(3) Reporters that are not currently
required to collect and report GHG
emissions data to EPA and will be
required to report using the new data
reporting system for the mandatory GHG
reporting rule.
For categories (2) and (3), EPA is
developing a new system for reporters to
submit the required data. The detailed
data elements that must be reported are
specified in the rule. In general,
reporters using this new system must
report annually to the Agency according
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to the schedule specified in 40 CFR
98.3(b).
Data Submission. The Designated
Representative (described in 40 CFR
98.4) must use an electronic signature
device (for example, a personal
identification number (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 intend to design
the new reporting system to 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.)
Unique Identifiers for Facilities and
Units. 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., EPAassigned facility ID codes and the Office
of Regulatory Information Systems
(ORIS) (DOE) ID code, and consistency
from one reporting year to the next, we
plan for the reporting system to provide
each facility with a unique
identification code to be specified by
the Administrator.
Reporting Emissions in a Single Unit
of Measure. To maintain consistency
with existing State-level and Federallevel GHG programs in the U.S. and
internationally, all emission
measurements must be reported 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 must be included in the data
submission. All emissions data must be
submitted to the Agency in kg or metric
tons per unit of time.
Conversion of Emissions to CO2e.
Reporters must submit the quantity of
each applicable GHG emitted (or other
metric such as quantities supplied for
industrial GHG suppliers) in two forms.
The data will be in the form of quantity
of the gas emitted (e.g., metric tons of
N2O) per unit of time and CO2e
emissions per unit of time.
Delegation of Authority to State
Agencies to Collect GHG Data. Reporters
must submit the emissions data and
supplemental data directly to EPA. At
this time, EPA does not intend to
delegate the authority to collect data to
State or local agencies.
Submission Method. All entities
covered by this rule must report in an
electronic format to be specified by the
Administrator. The electronic format,
which will reflect the underlying
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electronic data reporting system, will be
developed prior to the first reporting
date. By specifying in the rule text the
exact information that must be reported
but not specifying the exact reporting
format, EPA informs reporters about
exactly what information they must
report and has flexibility to modify the
electronic reporting format and
electronic data reporting system in a
timely manner based on implementation
experience and new technology. EPA
has used this approach successfully in
existing programs, such as the ARP and
the Title VI Stratospheric Ozone
Protection Program, facilitating the
deployment of new reporting formats
and reporting systems that take
advantage of technologies such as,
eXtensible Markup Language (XML),
and reducing the burden on reporters
and the Agency. The electronic reports
submitted under this rule are subject to
the provisions of 40 CFR part 3,
specifying EPA systems to which
electronic submissions must be made
and the requirements for valid
electronic signatures.
4. Data Management
QA Procedures. The new reporting
system will include automated checks
for data completeness, data quality, and
data consistency. Such automated
checks are used for many other Agency
programs (e.g., ARP).
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 when we develop the
electronic data reporting system.
Regardless of data collection system
specifics, the goal is to ensure
appropriate transparency and timeliness
when providing feedback to reporters
who submitted data.
5. Data Dissemination
Public Access to Emissions Data. The
Agency plans to publish data submitted
or collected under this rulemaking
through EPA’s Web site, reports, and
other formats (e.g., XML), with the
exception of any confidential business
information (CBI) data. For further
discussion of CBI, see Section II.R of
this preamble.
EPA will disseminate data after the
reporting deadline. The Agency
recognizes the high level of public
interest in this data and plans to
disclose it in a timely manner, while
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also assuring completeness and
accuracy.
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. In order to be consistent with
and supportive of these programs and to
reduce burden on reporters and program
agencies, EPA plans to share emissions
data, with the exception of any CBI data,
with relevant agencies or approved
entities using, where practical, common
data exchange standards and
infrastructure.
B. Summary of Comments and
Responses on Collection, Management,
and Dissemination of GHG Emissions
Data
This section contains a brief summary
of major comments and responses. A
large number of comments on data
collection, management, and
dissemination were received covering
numerous topics. Responses to
significant comments received can be
found in ‘‘Mandatory Greenhouse Gas
Reporting Rule: EPA’s Response to
Public Comments, Designated
Representative and Data Collection,
Reporting, Management, and
Dissemination.’’
1. Designated Representatives,
Alternative Designated Representatives,
and Agents
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Designated Representatives
Comment: Several commenters
requested that EPA use the ARP
definition for designated representatives
to maintain consistency across the two
EPA programs and provide more
flexibility regarding who can be a
designated representative. Other
commenters requested that EPA use the
responsible official definition from Title
V or senior management official from
TRI to maintain consistency with those
programs. Other commenters raised
concerns over the employment status of
designated representatives.
Comment: A commenter noted that
rule language was inconsistent in
defining the relationships between
designated representatives, facilities and
suppliers, and owners and operators.
Response: EPA agrees that owners and
operators should have more flexibility
to identify a designated representative,
including third-party representatives.
EPA is striking the language requiring
the designated representative to be a
person responsible for the overall
operation of the facility or supplier.
Further, EPA is not requiring the use of
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a responsible official or senior
management official because either
approach would be more restrictive than
the designated representative definition
of the final rule. EPA believes that the
proposed rule was neutral with respect
to the employment status of the
designated representative. The final rule
provides flexibility for the owners and
operators to choose any individual,
employee or non-employee, to represent
them. EPA modified the rule to clarify
that each facility and each supplier shall
have one and only one designated
representative and that the designated
representative must be authorized by
binding agreement of the owners and
operators.
Agents
Comment: Several commenters
requested that EPA allow designated
representatives and alternate designated
representatives the option of delegating
their responsibility to prepare and
submit reports to EPA to a preparer or
agent. Commenters also stated that the
designated representative requirement is
inconsistent with Title V reporting.
Response: EPA agrees that it is
beneficial to give the designated
representatives and alternate designated
representatives flexibility concerning
who prepares the reports that they are
responsible for submitting. The final
rule does not specify who must prepare
reports, but only specifies who must
certify, sign, and submit them. EPA also
agrees that flexibility should be
provided concerning who actually
submits the reports, similar to the
flexibility provided in the ARP. This
flexibility was implied in the provision
in the proposed rule that reports be
submitted ‘‘in a format specified by the
Administrator,’’ which format has
included, in other programs such as the
ARP, the ability to use agents. However,
EPA decided to make this flexibility
explicit by including in the rule
provisions allowing and setting
requirements for agents selected by
designated representatives or alternate
designated representatives. The
structure of designated representative,
alternate designated representative and
agent fits a wide range of circumstances
from large companies to small,
including those accustomed to reporting
under Title V.
Certification Statement
Comment: Several commenters
described the self-certification
procedures in the proposed rule as too
restrictive or suggested that the rule
should be consistent with requirements
of the Title V or TRI program. For
example, the rule’s requirement that the
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designated representative certify that
they have ‘‘personally examined’’ the
data should be replaced by the Title V
requirement that a responsible official
certify that they have made a
‘‘reasonable inquiry’’ as to the accuracy
of the data.
Response: EPA believes that the high
level of public interest in the data
collected under this rule, as well as its
importance to future policy, warrants
establishment, by rule pursuant to CAA
Sections 114, 208, and 301(a)(1), of a
high standard for data quality and
consistency and a high level of
accountability for reported data, which
will help ensure that the data quality
and consistency standard is met. The
certification requirements set forth in
this rule are similar to the ARP (Title
IV). EPA has successfully implemented
this approach in the ARP and found that
it provides a high degree of both data
quality and consistency and
accountability.
2. Certificate of Representation
Comment: One commenter requested
that EPA designate a deadline for the
submission of the certificate of
representation to ensure sufficient time
to process the submissions.
Response: EPA agrees that an earlier
deadline for submitting certificates of
representation is advisable to provide
additional lead time to process the
certificates and, if necessary, verify
identities and resolve issues. Because
any delay in processing a certificate of
representation could delay the
submission of data, EPA is requiring
that the designated representative
submit the initial certificate of
representation at least 60 days prior to
the deadline for a facility or supplier’s
initial GHG report.
Comment: Several commenters noted
that a certificate of representation for
each facility and supplier is
burdensome either due to timing with
the annual report, the need to maintain
current information, or ambiguities as to
whether the certificate is complete.
Commenters also requested that
reporters be allowed more than 30 days
to submit a revised certificate of
representation in the event of a change
in operators or owners.
Comment: Several commenters
requested that EPA provide an
electronic system for submitting and
processing certificates of representation.
Response: EPA does not agree that
certificates of representation are
unnecessary or overly burdensome or
that there should be any uncertainty as
to whether a certificate of representation
is complete. The information required
on the certificate of representation is
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listed in the rule and should be well
known to the owners and operators of
the facility or supplier. It is the
responsibility of the individual
submitting the certificate to ensure its
completeness. This certificate of
representation has been used
successfully for over a decade in the
ARP.
To minimize burden, the electronic
data reporting system will provide the
means to electronically submit both the
initial and any subsequent certificate of
representation. EPA agrees that
reporters should be allowed more time
to update changes in owners or
operators but does not agree that doing
so in the annual report is sufficient. The
designated representative is the primary
point of contact between the owners and
operators and the EPA. However, the
owners and operators are ultimately
responsible for compliance with the
requirements of reporting rule, and it is
therefore essential that the information
in the certificate of representation be
timely and accurate in the event EPA
finds it necessary to contact the owners
and operators of the facility or supplier
during periods in between the
submission dates of the annual reports,
for example, to perform an audit. The
final rule allows reporters up to 90 days
to submit a revised certificate of
representation when a change in owners
or operators occurs. In addition, EPA
modified both the owner definition and
rule to clarify that the certificate of
representation does not need to list
persons whose legal or equitable title to
or leasehold interest in a facility or
supplier arises solely because they are
limited partners in a partnership with
legal or equitable title to, a leasehold
interest in, or control of, the facility or
supplier.
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3. Data Collection Methods
Comment: Several commenters
requested that EPA use current emission
inventory reporting programs (e.g., NEI)
to handle data collection or to sunset
the GHG reporting rule, and instead use
such programs, after five years.
Response: EPA is requiring electronic
reports to be submitted directly to EPA
using a new data reporting system for
the GHG reporting rule. The rationale
for the decision to report directly to EPA
is contained in Sections II.N (emissions
verification) and VI.B (compliance and
enforcement) of this preamble. EPA
recognizes the value of integrating the
GHG data reported under this rule with
other emission reporting programs. NEI,
for example, plans to incorporate the
GHG emissions data from this
collection, as feasible.
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Comment: Commenters requested that
the design of the new data system be
modeled on existing electronic reporting
programs, incorporate measures to
handle system errors, and provide
opportunities for testing and user
training.
Response: EPA agrees that a national
electronic emissions database should be
the basis for receiving GHG data, and
that the ARP database provides a useful
model for a future GHG emissions
database. Data would be provided to
EPA electronically to reduce the burden
on the reporters and EPA, and to
increase the accuracy of the reported
emissions, among other reasons. The
issue of transmission failures and
transmission errors will be addressed in
the development of the electronic
reporting system. EPA agrees that is it
important for data reporters to be able
to confirm that their data were accepted
by the system and to compare the data
in the system to the data that they
reported to ensure it was accurately
incorporated into the database. The new
data system will meet Agency
requirements for security and hosting.
EPA acknowledges comments
supporting a ‘‘user friendly’’ reporting
system. EPA plans to follow well known
design practices within the constraints
of security, accessibility and Agency
design requirements.
EPA agrees with commenters on the
need for testing and user training. We
will continue the outreach effort
undertaken during this rulemaking to
encourage stakeholder participation in
‘beta’ testing and training opportunities.
Unique Identifiers for Facilities and
Units
Comment: Several commenters
requested that EPA assign and track
corporate identifiers for reporting
facilities to facilitate corporate-level
analysis of emission data. Commenters
also requested that EPA publish a list of
identifiers for all EPA programs that a
covered facility may report to.
Response: EPA is collecting owner
and operator information through the
Certificate of Representation (40 CFR
98.4). At this time, EPA is not proposing
to assign unique identifiers to the
owners and operators because of the
complexity of ownership structures
(including percentage shares of owners,
subsidiaries, holding companies, and
limited liability partnerships) that can
be used in the multiplicity of industrial
sectors required to report emission data
under this rule. Although as explained
earlier in the preamble, we are exploring
options for adding additional data
elements to the reports, such as name of
parent company and NAICS code(s), to
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allow easier aggregation of facility-level
data to the corporate level under this
program. EPA expects to subject any
additional requests to notice and
comment rulemaking.
EPA’s Facility Registry System (FRS)
links EPA program identification
numbers under a unique facility record.
The FRS database is publicly available
to queries from the EPA.GOV Web site
under the Envirofacts Data Warehouse
home page: https://www.epa.gov/enviro/
html/fii/fii_query_java.html. Descriptive
information about FRS can be found at:
https://www.epa.gov/enviro/html/fii/
index.html. FRS may be searched by
program identification, facility name or
geographic location. The Agency will
continue to make FRS and all program
identification numbers readily available
and will include the facilities reporting
under this rule in the FRS collection of
program ID’s once public release of the
data is authorized.
Submission Method
Comment: Several commenters
requested that EPA specify the format of
the data collection methods and subject
it to public comment before finalizing
the rule. These commenters indicated
that without the details of the data
collection methods it was not possible
to evaluate the GHG reporting rule,
including implementation costs and
reporting burden.
Response: The final rule requires
reports to be submitted ‘‘in a format
specified by the Administrator.’’ EPA is
thereby retaining the flexibility to
specify the electronic format, and the
underlying electronic reporting system
reflected in the format, after
promulgation of this rule but well before
the first reporting deadline and, if
necessary, to change the electronic
format and electronic reporting system
based on implementation experience
and new technology. Several other
reporting programs (e.g., ARP) use a
similar approach where the specific
electronic reporting system is not
included within the rule or subjected to
formal notice and comment. The
relevant subparts of the proposed GHG
reporting rule specified the data
elements that each entity must report,
and therefore parties could evaluate the
reporting burden and costs under the
proposed rule and had an opportunity
to comment on that aspect of the
proposed rule. In addition, before
specifying the electronic format and
underlying electronic reporting system,
EPA will conduct outreach and provide
opportunities for stakeholder feedback
on the specific reporting format and
reporting system.
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Comment: Several commenters
requested that EPA provide alternative
methods to report emission data,
including paper submissions, scanned
documents, and direct data upload.
Response: EPA is requiring electronic
reporting of the GHG and supplemental
data to increase the accuracy and
timeliness of the reported emission data
and is not providing options for paper
or scanned GHG reports. Requiring
electronic submission of data allows
EPA to conduct electronic QA testing of
all such data when it is received and to
provide electronic feedback to the
reporters almost instantaneously. This
gives reporters the opportunity to
correct any errors, or to provide
explanations of potentially problematic
data, within a short time frame, thereby
increasing the accuracy and timeliness
of the data. Moreover, electronically
submitted data can be readily sorted and
analyzed by EPA and members of the
public. In contrast, submission of
hardcopy data (whether in paper or
scanned documents) would make audit
and correction, as well as sorting and
analysis, of the data much more
cumbersome, inefficient, and time
consuming. Indeed, particularly in light
of the large number of facilities and
suppliers that will be reporting and the
large amounts of reported data that will
be received as a result, the ability to
audit and analyze the data received in
hardcopy format would likely be
significantly limited. This would
adversely affect the usefulness, as well
as the accuracy and timeliness of the
data.
In requiring electronic data
submission, EPA will provide a Webbased reporting system to guide
reporters through the data entry,
emission calculation, and submission
process. This reporting system will
conform to EPA information technology
standards and 40 CFR part 3. In
addition, EPA will provide a
mechanism for reporters to submit data
files directly to EPA using a standard
format (e.g., XML) to be prescribed by
the Administrator before the first
reporting date. To reduce the burden on
reporters and reduce errors, EPA will
conduct outreach and training for
reporters on the reporting format and
underlying reporting systems. EPA will
also provide a hotline to answer
questions about the program and
reporting format and reporting systems.
EPA expects that most reporters affected
by this rule are already familiar with
Web-based or electronic reporting
systems through other EPA programs.
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Delegation of Authority to State
Agencies To Collect GHG Data
Comment: Several commenters
requested that EPA delegate rule
implementation, including data
collection, to State and local agencies.
These commenters indicated that
several States already have GHG
reporting requirements and have
systems in place to collect and verify
this data, and suggested that delegation
of the rule could help reduce
inconsistency or duplication of effort
between State programs and this Federal
mandatory GHG reporting rule. Other
commenters supported requiring
facilities to submit data directly to EPA,
without delegation of data collection to
State and local agencies, in order to
provide national consistency.
Response: EPA is requiring electronic
reports to be submitted directly to EPA,
and is not delegating data collection to
State and local agencies. The rationale
for this decision is provided in Section
VI.B of this preamble.
5. Data Dissemination
Public Access to Emissions Data
Comment: Several commenters
supported EPA’s proposal to make the
data submitted under the reporting rule
available to the public. Some requested
that data be published in real time,
while others requested the data be
released in a timely manner.
Response: With the exception of CBI,
EPA intends to make data submitted
under this program available to the
public in a timely manner after the
reports have been submitted and EPA
has completed QA/QC of the data. To
that end, EPA intends to establish a new
reporting system that will accept
electronic submissions of GHG
emissions and supporting data and
facilitate EPA’s verification of the
submissions. EPA plans to provide
public access to the data by posting
electronic data on a Web site in a timely
manner after the reporting deadline.
This level of transparency is important
to public participation in future policy
development and for building public
confidence in the quality of the data
collected.
Sharing Emissions Data With Other
Agencies
Comment: Some commenters stressed
that electronic data reporting systems
need to be consistent and inter-operable
and allow data exchange between TCR,
State rules, NEI, ARP, other
stakeholders and EPA.
Response: EPA will continue to
coordinate with other Federal, State,
and regional programs and will make
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56359
efforts to facilitate data exchange when
designing the data reporting system that
will be used for the GHG reporting rule.
EPA intends to employ inter-operable
data exchange standards. EPA intends to
design and manage the GHG data
collection to take advantage of existing
efforts on data exchange standards and
to work with stakeholder groups to
promote the easy exchange and sharing
of the data collected under this rule. For
example, EPA is extending the
Consolidated Emissions Reporting
Schema (CERS), currently in use by the
EPA’s NEI program, to support data
reporting and publication under this
rule. EPA also intends to use existing
tools, such as FRS and SRS, to ensure
data consistency.
To the extent possible, EPA will
consider existing reporting systems and
work with those programs and systems
to develop a reporting scheme that
facilitates data exchange. EPA
anticipates that this coordination will
reduce the burden of reporting for both
reporters and government agencies.
However, as explained in Section II.O of
this preamble, the various reporting
programs do not have identical data
needs and requirements. Therefore, at
this time, it is not possible for
companies reporting under State and
Federal rules and voluntary programs to
file a single report that will satisfy all
reporting requirements.
Comment: Commenters requested that
the data system utilize common
standards, such as XML and geographic
identifiers, and provide descriptive text
wherever codes or abbreviations are
used.
Response: EPA agrees that publishing
the results of this data collection using
common, standards-based schemas and
formats will promote the exchange of
data between EPA, States and other
entities. The published results will
include the latitude and longitude of
facilities as well as help text with
definitions of codes and abbreviations.
VI. Compliance and Enforcement
This section of the preamble generally
describes the compliance assistance and
enforcement activities EPA intends to
implement for the GHG reporting rule
and summarizes public comments and
responses on compliance assistance,
role of the States, and enforcement.
A. Compliance and Enforcement
Summary
1. Compliance Assistance
EPA plans to conduct an active
outreach and technical assistance
program following publication of the
final rule. The primary audience is
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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 $37,500 per day per violation.31
Actions (or inactions) that could
ultimately be considered violations
include but are not limited to the
following:
• Failure to report GHG emissions
(for suppliers, the emissions that would
result from combustion or use of the
products they supply).
• Failure to collect data needed to
calculate 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 calculate GHG emissions
according to the methodology(s)
specified in the rule.
• Failure to keep required records
needed to verify reported GHG
emissions.
• Falsification of reports.
2. Role of the States
While EPA does not intend to
formally delegate data collection and
enforcement of the GHG reporting rule
to State agencies, EPA will likely enlist
State assistance, when it is available, for
outreach and compliance assistance
with the final rule. (However, State and
local agencies will not be required to
provide EPA any assistance with these
activities, given State and local agency
resource constraints and priorities.).
State and local air pollution control
agencies routinely interact with many of
the sources that would report under this
rule. Further, several States have
experience implementing State
mandatory GHG reporting and reduction
programs. Therefore, we plan to work
with those State and local agencies that
are able to assist EPA to define their 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 may
also be able to assist with educating
facilities and assuring compliance at
facilities subject to this rule.
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potentially affected industries. We
intend to develop implementation and
outreach materials and training to help
potential reporters understand whether
the rule applies to them and explain the
reporting requirements and timetables.
The program particularly will target
industrial, commercial, and institutional
sectors that do not routinely deal with
air pollution regulations.
Compliance materials will be tailored
to the needs of various sectors. These
materials might include, for example,
fact sheets, information sheets, plain
English guides, frequently asked
question and answer documents,
applicability tools, monitoring and
recordkeeping checklists, and training
on rule requirements and the electronic
reporting system. We also expect to
implement a compliance assistance
e-mail and telephone hotline for
answering questions and providing
technical assistance. Note that while
EPA plans to issue compliance
assistance materials, reporters should
always consult the final rule to resolve
any ambiguities or questions.
B. Summary of Public Comments and
Responses on Compliance and
Enforcement
3. Enforcement
Facilities or suppliers that fail to
monitor or report GHG emissions,
quantities supplied, or other data
elements according to the requirements
of the applicable rule subparts could
potentially be subject to enforcement
action by EPA under CAA sections 113
and 203–205. The CAA provides for
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This section contains a brief summary
of major comments and responses. A
large number of comments on
compliance and enforcement were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments,
Compliance and Enforcement.’’
1. Role of States in Compliance and
Enforcement
Comment: Several commenters
requested that EPA delegate rule
implementation, including data
collection, emissions verification, and
enforcement of the rule to State and
local agencies. These commenters
indicated that several States already
have GHG reporting requirements and
have systems in place to collect and
verify these data, and they suggested
that delegation of the rule could help
reduce inconsistency or duplication of
effort between State programs and this
31 The Federal Civil Penalties Inflation
Adjustment Act of 1990, Public Law 101–410, 104
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 $37,500 per day of violation.
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Federal mandatory GHG reporting rule.
However the majority of commenters,
including industry, environmental
organizations, and many public citizens
supported requiring facilities to submit
data directly to EPA, without delegation
of data collection or emissions
verification to State and local agencies,
in order to provide national consistency.
Response: Section 114(b) of the CAA
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
(such as data collection and
enforcement activities) to State and
local agencies, as discussed in Section
II.O of this preamble. The goal of data
collection under this rule is to establish
a consistent, verified, national data set
that is available to EPA, States, other
agencies, policy makers, and the public
for use in developing and implementing
future GHG policies and reduction
programs. To meet these data
consistency and timeliness constraints,
and to serve policy objectives, it is most
efficient to have the data submitted
directly into one central EPA system
and have centralized emissions data
verification. Direct reporting to EPA will
also help us better understand and
address common compliance problems
that may arise from the GHG reporting
rule.
EPA recognizes that several States
already have mandatory GHG reporting
programs that are broader in scope, in
a more advanced state of development,
and have different policy objectives
than this rulemaking. These are
important programs that not only led
the way in reporting of GHG emissions
before the Federal government acted but
also have catalyzed important GHG
reductions.
As discussed in Section II.O of this
preamble, we are committed to working
with States and other groups (e.g, TCR,
Environmental Council of the States
(ECOS)) to develop electronic reporting
tools that can both collect and share
data in an efficient and timely manner.
At this time, EPA is in the process of
developing the reporting format and
tools and therefore has not specified the
exact reporting format, other than it will
be electronic, in order to maintain
flexibility to modify the reporting
format and tools in a timely manner. To
the extent possible, EPA will work with
existing reporting programs and systems
to develop a reporting scheme that
minimizes the burden on sources.
While EPA is not delegating authority
to the States, we will work with States
as we develop rule implementation
plans to determine appropriate
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implementation roles, such as assisting
with outreach efforts and site visits to
audit facility reports. For related
comments and responses, please see the
following sections of this preamble: II.N
(verification approach), II.O (role of
States) and II.R (CBI).
2. Enforcement
Comment: Some commenters
suggested that States should be allowed
to participate in the enforcement of the
GHG reporting rule, perhaps through
delegated enforcement authority.
Response: EPA welcomes States’
interest in helping EPA enforce this or
any other Federal rule and we will work
with States to determine appropriate
roles as described above. We do not
plan to delegate the enforcement of this
rule in the same sense that we do under
other CAA programs such as the
NESHAP program in which, for
example, notices may be sent only to the
delegated States. If a State would like
the authority to enforce this rule, then
the State may adopt the provisions of
this GHG reporting rule into State laws
or regulations by reference. This would
make the provisions enforceable as a
matter of State law which can be
enforced in a State court.
Comment: Some commenters stated
that they should be able to petition EPA
to enforce against violators where they
have evidence of or suspect violations.
Response: EPA welcomes any tips
from citizens about suspected violations
of this or any rule through our tips Web
site, https://www.epa.gov/tips. However,
we are not including a formal petition
process in the rule because such a
process was not proposed. We do not
favor a formal petition process because
a formal petition is not necessary for us
to investigate concerns raised by
citizens and such a process might take
extra time or divert resources from other
priorities.
Comment: Some commenters stated
that a flexible enforcement policy is
needed. They noted that the proposed
rule cited the CAA for the authority for
the GHG reporting rule and stated that
a violation of the reporting rule is a
violation of the CAA and subject to
maximum daily penalties allowed under
the CAA. However, the commenters
were concerned that the maximum
penalty should not be applied in most
cases and argued that there are many
instances when a less severe action is
appropriate.
Response: EPA agrees with the
commenters that flexibility is needed in
enforcing the rule. The penalty cited in
the proposal preamble and rule is a
statutory maximum, and would not be
applied in every case. EPA’s objective
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with the reporting rule is to collect
accurate GHG data in a timely manner.
In order to achieve that objective, EPA
will generally work with sources that
must submit GHG reports in order to
facilitate compliance and provide the
needed data to EPA. The CAA allows
EPA discretion to pursue a variety of
informal and formal actions in order to
achieve compliance. While EPA is
committed to working with reporters to
ensure accuracy, this does not relieve
reporters from their obligation to report
data that are complete, accurate, and in
accordance with the requirements of
this rule.
In many instances, based on past
enforcement experience, less punitive
enforcement actions are exhausted
before more punitive fines and penalties
are imposed on a non-complying source.
These less punitive actions may include
a warning to the source that it is in noncompliance along with advice on what
needs to be done to comply and a
request for response from the facility.
Initial actions may also include a formal
legal notification from EPA that defines
the violation, provides evidence, and
requires (orders) corrective actions by
specific dates. The EPA enforcement
office always uses discretion and takes
case-specific circumstances into account
when determining the appropriate
actions to address violations of CAA
rules. We will continue to do so in
enforcing the reporting rule, and we are
not laying out a specific enforcement
policy or hierarchy in order to maintain
the necessary flexibility.
VII. Economic Impacts on the Rule
This section of the preamble examines
the costs and economic impacts of the
GHG reporting rule, including the
estimated costs and benefits of the rule,
and the estimated economic impacts of
the rule on affected entities, including
estimated impacts on small entities.
Complete detail of the economic
impacts of the final rule can be found
in the text of the Regulatory Impact
Analysis (RIA) for the final rule (EPA–
HQ–OAR–2008–0508).
This section also contains a brief
summary of major comments and
responses. A large number of comments
on economic impacts of the rule were
received covering numerous topics.
Responses to significant comments
received can be found in ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments, Cost and
Economic Impacts of the Rule.’’
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56361
A. How were compliance costs
estimated?
1. Summary of Method Used To
Estimate Compliance Costs
EPA estimated costs of complying
with the rule for reporting process
emissions of GHGs in each affected
industrial facility, as well as emissions
from stationary combustion sources at
industrial facilities and other facilities,
GHG and supply data from fuel
suppliers and industrial gas suppliers,
and GHG data for 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 rule
will 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. The costs include
labor costs for performing the
monitoring, recordkeeping, and
reporting activities necessary to comply
with the rule. For some 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 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 will 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 Bureau of Labor Statistics (BLS).
Equipment Costs. Equipment costs
include both the initial purchase price
of monitoring equipment and any
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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
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 seven percent.
2. Summary of Comments and
Responses
Comment: A majority of the
comments received on the compliance
costs of the reporting rule focused on
facility level costs for monitoring and
reporting. Commenters noted that costs
estimated for a representative facility
may differ from actual facility level
costs. Some commenters specifically
referred to the costs associated with
installing and maintaining capital
equipment. Other commenters noted
that some source categories had higher
estimated compliance costs than others.
Several commenters expressed
confusion over how combustion related
monitoring costs are added to process
related monitoring costs.
Response: EPA recognizes that the
costs presented for facilities represent
costs that would be incurred by a
representative facility, and may not
reflect the costs that would be incurred
by each individual facility in each
industry because facilities affected by
each subpart vary.
Nevertheless, after reviewing the
comments received, EPA has
determined that its analysis provides a
reasonable characterization of costs for
facilities affected by each subpart and
that its documentation provides
adequate documentation of how the
costs were estimated. As described in
the next section, EPA collected and
evaluated cost data from multiple
sources, and weighed the analysis
prepared at proposal against the input
received through public comments. In
any analysis of this type, there will be
variations in costs among facilities, and
after thoroughly reviewing the available
information, we have concluded that the
costs developed for this rule
appropriately reflect a ‘‘representative
facility’’ in the sector.
The costs facing facilities in some
sectors include not only process costs
but additional costs associated with
other subparts of the rule. While these
costs are presented individually in
Section 4 of the RIA for the final rule,
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where these conditions apply the costs
are summed across applicable subparts
and compared to revenues in the
economic and small entity impact
analyses.
B. What are the costs of the rule?
1. Summary of Costs
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. EPA
also considered cost data submitted in
public comments on the proposed rule,
as further discussed in Section VII.B.2
of this preamble. 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.
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
rule (to allow only the incremental costs
to be estimated). Many of the affected
source 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.
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A detailed engineering analysis was
conducted for each subpart of the rule
to develop unique unit costs. This
analysis is documented in the RIA for
the final rule. The TSDs for each source
category provide a discussion of the
applicable measurement technologies
and any existing programs and
practices. The appropriate volume of
‘‘Mandatory Greenhouse Gas Reporting
Rule: EPA’s Response to Public
Comments’’ for each source category
provide responses to any public
comments on these source category
engineering and cost analyses. Section 4
of the RIA for the final rule contains a
description of the engineering cost
analysis.
Table VII–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 rule. EPA
estimates that the total national
annualized cost for the first year is $132
million, and the total national
annualized cost for subsequent years is
$89 million (2006$). Of these costs,
roughly 13 percent fall upon the public
sector for program administration in the
first year, while 87 percent fall upon the
private sector. General stationary
combustion sources, which are widely
distributed throughout the economy, are
estimated to incur approximately 26
percent of costs in the first year; other
sectors incurring relatively large shares
of costs are pulp and paper
manufacturing (9 percent) and vehicle
and engine manufacturers (9 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 VII–2 of this
preamble provides the cost-effectiveness
analysis for various thresholds
examined. Two metrics are used to
evaluate the cost-effectiveness of the
emissions threshold. The first is the
average cost per metric ton of emissions
reported ($/metric ton CO2e). The
second metric for evaluating the
threshold option is the incremental cost
of reporting emissions. The incremental
cost is calculated as the additional
(incremental) cost per metric ton
starting with the least stringent option
and moving successively from one
threshold option to the next. For more
information about the first year capital
costs (unamortized), project lifetime and
the amortized (annualized) costs for
each subpart, please refer to section 4 of
the RIA for the final rule and the RIA
cost appendix. Not all subparts require
capital expenditures but those that do
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are clearly documented in the RIA for
the final rule.
TABLE VII–1—ESTIMATED COVERED ENTITIES, EMISSIONS AND COSTS BY SUBPART (2006$)
Downstream emissions
First year capital costs
First year total
annualized costs 2
Number
covered of
entities
Subpart
(Million
of MtCO2e)
0
0
0.0
0.0
0
0
$0.0
0.0
0
0
$0.0
0.0
0
0
3,000
1,108
4
14
23
107
9
55
3
41
121
13
89
0
45
80
150
14
425
1
5
8
5
2,551
107
220.0
2262.0
9.3
6.4
12.9
86.8
2.3
2.2
13.8
15.0
85.0
0.8
25.4
0.0
17.7
54.4
204.7
3.8
57.7
0.1
3.1
3.7
0.8
91.1
4.5
6
59
0
0
0
2
0
0
0
0
2
0
1
0
0
1
5
0
2
0
0
0
0
2
0
10.5
0.0
0.0
0.0
0.0
5.4
0.0
0.0
0.0
0.0
0.0
0.0
4.9
0.0
0.2
0.0
1.6
0.8
14.8
0.0
0.0
0.0
0.0
1.3
0.0
27
0
0
0
0
14
0
0
0
0
0
0
12
0
1
0
4
2
37
0
0
0
0
3
0
25.8
3.3
0.1
0.2
0.4
6.8
0.1
0.5
0.0
0.4
3.7
0.1
5.3
0.0
0.9
2.2
6.1
0.8
8.6
0.0
0.1
0.1
0.1
12.4
0.3
20
2
0
0
0
5
0
0
0
0
3
0
4
0
1
2
5
1
7
0
0
0
0
9
0
315
0.0
0
0.0
0
3.7
3
1,502
0.0
0
0.0
0
6.8
5
Share
(percent)
(Million)
Share
(percent)
(Million)
Share
(percent)
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 K—Ferroalloy Production .........................
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 U—Miscellaneous Uses of Carbonates ...
Subpart V—Nitric Acid Production .........................
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 EE—Titanium Dioxide Production ............
Subpart GG—Zinc Production ...............................
Subpart HH—Landfills ...........................................
Subpart JJ—Manure Management ........................
Subpart LL -Suppliers of Coal & Subpart MM—
Suppliers of Petroleum Products .......................
Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids .................................................
Subpart OO—Suppliers of Industrial Greenhouse
Gases .................................................................
Subpart PP—Suppliers of Carbon Dioxide (CO2)
Subpart QQ—Motor Vehicle and Engine Manufacturers ..............................................................
Coverage Determination Costs for Non-Reporters
Private Sector, Total ..............................................
Public Sector, Total ................................................
167
13
643.4
0.0
17
0
0.0
0.0
0
0
0.5
0.0
0
0
317
NA
10,152
NA
NA
NA
3,827
NA
NA
NA
100
NA
0.0
NA
39.6
NA
0
NA
100
NA
8.6
17.2
115.0
17.0
7
13
87
13
Total ................................................................
10,152
3,827
100
39.6
100
132.0
100
1
Emissions from upstream facilities are excluded from these estimates to avoid double counting.
Total 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 section 4 of the RIA for the final rule).
2
TABLE VII–2—THRESHOLD COST-EFFECTIVENESS ANALYSIS (2006$)
Facilities
required
to report
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Threshold
(tons CO2e)
100,000 ....................................................................................................
25,000 ......................................................................................................
10,000 ......................................................................................................
1,000 ........................................................................................................
6,269
10,152
16,718
54,229
Total
costs
(million
$2006)
$89
132
160
398
Downstream
emissions
reported
(MtCO2e/
year)
Percentage of
total
downstream
emissions
reported
(percent)
Average
reporting
cost
($2006/
ton)
Incremental
cost
($/metric
ton)
3,738
3,827
3,861
3,926
53
54
55
56
$0.02
0.03
0.04
0.10
0.49
0.83
3.67
* Cost per metric ton relative to the selected option.
Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ).
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Table VII–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., refineries)
are also direct emitters of GHGs and are
included in the downstream side of the
table. As shown in Table VII–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 VII–3—UPSTREAM VERSUS DOWNSTREAM COSTS
Upstream 1
Downstream 2 3 4
No. of reporters
Emissions
coverage
(%) 10
First year
cost
(millions)
Coal Supply .................................
Petroleum Supply ........................
Natural Gas Supply .....................
0
315
1,502
0
100
68
$0.00
3.66
6.76
Industrial Gas Supply ..................
167
100
0.52
Source category
No. of reporters 2
Source category
Coal 5 6 Combustion ....................
Petroleum 5 Combustion 9 ...........
Natural Gas 5 Combustion ..........
Sub Total Combustion ................
Industrial Gas Consumption .......
Industrial Processes ...................
Fugitive Emissions (coal, oil and
gas).
Biological Processes ..................
Vehicle 8 and Engine Manufacturers.
Emissions
coverage 3 7 10
(%)
N/A
N/A
N/A
4,108
17
1,068
0
99.0
20.0
23.0
N/A
14
99.6
0
N/A
N/A
N/A
$29.04
0.24
36.2
0.00
2,658
317
58
80
12.77
8.61
First year
cost 3
(millions)
Notes
1 Most upstream facilities (e.g., refineries) 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 threshold (e.g., 25,000 metric tons of CO2e/yr).
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 ARP.
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 will 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 total heavy-duty highway vehicles and engines, motorcycles, and nonroad engine sales covered by manufacturer reporting in this proposal rather than emissions coverage. The ‘‘threshold’’ for mobile sources is based on manufacturer
size rather than total emissions. In this rule, all heavy-duty highway and nonroad vehicle and engine manufacturers, except those that meet
EPA’s definition of ‘‘small business’’ or ‘‘small volume manufacturers’’, would report emissions rates of CO2, CH4, and N2O from the products
they supply. This source category is neither upstream nor downstream, but is included in the downstream column for illustrative purposes.
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 one percent
of the total emissions.
sroberts on DSKD5P82C1PROD with RULES
2. Summary of Comments and
Responses
Comment: EPA received comments on
source specific cost data reflected in the
engineering cost analysis presented in
section 4 of the RIA for the proposed
rule (EPA–HQ–OAR–2008–0318–002).
Some commenters asked EPA to not
overly burden entities that may be
required to report and to balance
reporting costs with the need for
accurate reporting of GHG emissions.
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Additional comments received
questioned EPA’s estimate of the costs
associated with third party verification,
as well as the estimated burden to the
Federal government for self certification
with EPA verification.
Response: EPA considered all relevant
comments regarding source specific cost
data developed in the engineering cost
analysis and used in the RIA for the
proposed rule. In some cases, we
revised our cost estimates, and in some
cases we revised monitoring and
reporting requirements in ways which
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reduced burden. Please see source
specific comments and responses in
Section III of this preamble and the
relevant volume of ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments’’.
EPA believes the selected option for
the mandatory GHG reporting rule
strikes a balance between impacts on
small entities, consistency with other
programs, costs incurred by the
reporting entities, and emissions
coverage. Section 5 of the RIA for the
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final rule provides cost comparisons for
each alternative evaluated.
In evaluating the costs of self
certification with EPA verification and
third party verification, EPA conducted
a thorough review of relevant cost
information available. EPA also
considered cost data submitted in
public comments on the proposed rule.
EPA’s review of verification costs
included examining estimated Agency
costs for other EPA based reporting
programs, as well as a study conducted
by the California Air Resources Board
(CARB). The results of EPA’s review of
verification costs can be found in the
Memo on Verification Costs in the
docket. The final rule retains selfcertification with EPA verification.
EPA’s estimated cost for verification
activities is $7 million per year.
Additional comments and responses on
third party verification can be found in
Section II.N of this preamble. Section
5.1.6 of the RIA for the final rule
contains the full economic analysis of
verification costs and options.
C. What are the economic impacts of the
rule?
1. Summary of Economic Impacts
EPA prepared an economic impact
analysis to evaluate the impacts of the
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 rule.
To estimate the economic impacts of
the 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 is 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 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 rule, rather than
modeling market responses and using
the resulting measures of social cost.
Table VII–4 of this preamble
summarizes cost-to-sales ratios for
affected industries.
TABLE VII–4—ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES
Average cost
per entity
($1,000/entity)
NAICS
NAICS description
211 ............................................
221 ............................................
322 ............................................
324 ............................................
325 ............................................
327 ............................................
331 ............................................
486 ............................................
562 ............................................
325199 ......................................
325311 ......................................
327310 ......................................
331112 ......................................
3272 ..........................................
325120 ......................................
331112 ......................................
3314 ..........................................
327410 ......................................
325311 ......................................
324110 ......................................
325312 ......................................
322110 ......................................
324110 ......................................
327910 ......................................
3251 ..........................................
325188 ......................................
3314 ..........................................
Oil and Gas Extraction .....................................................................................
SF6 from Electrical Systems ............................................................................
Pulp & Paper Manufacturing ............................................................................
Petroleum and Coal Products ..........................................................................
Chemical Manufacturing ...................................................................................
Cement & Other Mineral Production ................................................................
Primary Metal Manufacturing ...........................................................................
Oil & Natural Gas Transportation .....................................................................
Waste Management and Remediation Services ..............................................
Adipic Acid ........................................................................................................
Ammonia ..........................................................................................................
Cement .............................................................................................................
Ferroalloys ........................................................................................................
Glass ................................................................................................................
Hydrogen Production ........................................................................................
Iron and Steel ...................................................................................................
Lead Production ...............................................................................................
Lime Manufacturing ..........................................................................................
Nitric Acid .........................................................................................................
Petrochemical ...................................................................................................
Phosphoric Acid ...............................................................................................
Pulp and Paper ................................................................................................
Refineries .........................................................................................................
Silicon Carbide .................................................................................................
Soda Ash Manufacturing ..................................................................................
Titanium Dioxide ...............................................................................................
Zinc Production ................................................................................................
sroberts on DSKD5P82C1PROD with RULES
1 This
Average entity
cost-to-sales
ratio 1
(percent)
$2
5
20
21
14
50
26
4
5
24
17
63
9
8
3
30
10
60
20
27
60
20
41
10
16
10
13
<0.1
<0.1
<0.1
<0.1
<0.1
0.8
<0.1
<0.1
0.2
<0.1
<0.1
0.2
<0.1
<0.1
<0.1
<0.1
<0.1
0.4
<0.1
<0.1
<0.1
<0.1
<0.1
<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.
2. Summary of Comments and
Responses
Comment: EPA received a number of
comments on the overall economic
impacts of the proposed rule. Some
commenters stated that the economic
impacts are understated, as costs will
not be passed on to consumers from
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17:39 Oct 29, 2009
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reporters. Other commenters stated that
large increases in operating costs
resulting from mandatory reporting of
GHGs would lead facilities to close or
move offshore.
Response: As described previously,
EPA conducted a thorough analysis of
available information and reviewed
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comments submitted on this issue, and
we have determined that this analysis
provides a reasonable characterization
of costs for facilities in each subpart and
that the documentation provides
adequate explanation of how the costs
were estimated. Our economic impact
analysis has been conducted without
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10,152 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 covered by
the rule, EPA has included simplified
emission estimation methods in the rule
where feasible (e.g., stationary
combustion equipment under a certain
rating can use a simplified calculation
approach as opposed to more rigorous
direct monitoring) to keep the burden of
reporting as low as possible. We
received many comments related to
monitoring and reporting requirements
in specific source categories, and made
many changes in response to reduce
burden on reporters. For information on
these issues, refer to the discussion of
each source category in this preamble
and the relevant volume of ‘‘Mandatory
Greenhouse Gas Reporting Rule: EPA’s
Response to Public Comments.’’ For
further detail on the rationale for
taking into account the fact that some
share of costs may be passed on to
customers of each affected sector.
Instead, facilities’ annualized costs were
compared to sales for entities in the
sector, overall and for small entities.
Even when all costs are absorbed by the
facility, the costs represent less than one
percent of sales and thus are not
expected to result in significant
hardship for affected firms.
D. What are the impacts of the rule on
small businesses?
1. Summary of Impacts on Small
Businesses
As required by the RFA and Small
Business Regulatory Enforcement and
Fairness ACT (SBREFA), EPA assessed
the potential impacts of the rule on
small entities (small businesses,
governments, and non-profit
organizations). (See Section VIII.C of
this preamble for definitions of small
entities.)
EPA has determined the selected
thresholds maximize the rule coverage
with 81 to 86 percent of U.S. GHG
emissions reported by approximately
excluding small entities through
threshold selection please see the
Thresholds TSD (EPA–HQ–OAR–2008–
0508–046) and Section III.C.3 of this
preamble.
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
rule as a percentage of sales and
determines whether the ratio exceeds
some level (e.g., one percent or three
percent).32 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 VII–5 of this preamble.
TABLE VII–5—ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a
Owned by enterprises with:
Industry
All enterprises
(percent)
<20 employees f
(percent)
20 to 99
employees
(percent)
100 to
499 employees
(percent)
500 to
749 employees
(percent)
750 to
999 employees
(percent)
1,000 to
1,499
employees
(percent)
0.0
0.2
0.0
0.0
0.0
0.0
0.0
5
0.0
0.2
0.0
0.0
0.0
0.0
0.0
500 to 750 ...
20
0.1
1.2
0.2
0.1
0.0
0.0
0.0
(c) ................
21
0.0
0.6
0.1
0.1
0.0
0.2
0.0
500 to 1,000
14
0.0
0.7
0.1
0.0
0.0
0.0
0.0
NAICS description
211
500 ..............
$2
221
Oil & gas extraction.
Utilities ..................
(b) ................
322
Paper mfg .............
324
Petroleum & coal
products mfg.
Chemical mfg .......
325199
Ammonia ...............
325311
Cement .................
Ferroalloys ............
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Average
cost per
entity
($1,000/
entity)
NAICS
Oil and Gas Extraction.
SF6 from Electrical
Systems.
Pulp & Paper Manufacturing.
Petroleum and
Coal Products.
Chemical Manufacturing.
Cement & Other
Mineral Production.
Primary Metal
Manufacturing.
Oil & Natural Gas
Transportation.
Waste Management and Remediation Services.
Adipic Acid ............
327310
331112
Glass .....................
3272
Hydrogen Production.
325
327
Nonmetallic mineral product mfg.
500 to 1,000
50
0.8
4.8
0.9
0.5
0.4
0.5
0.4
331
Primary metal mfg
500 to 1,000
26
0.1
2.1
0.3
0.1
0.1
0.0
0.0
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
(d)
................
4
0.0
0.0
0.2
0.1
NA
NA
NA
(e) ................
5
0.2
0.7
0.1
0.1
0.0
0.0
0.0
1,000 ...........
24
0.0
0.9
0.3
0.1
NA
0.0
NA
1,000 ...........
17
0.1
0.9
0.5
NA
NA
NA
NA
750 ..............
750 ..............
63
9
0.2
0.0
2.0
NA
1.5
NA
0.3
NA
NA
NA
NA
NA
0.1
NA
500 to 1,000
8
0.1
1.4
0.2
0.0
0.0
0.1
0.0
1,000 ...........
3
0.0
0.6
0.0
0.1
NA
NA
NA
486
562
325120
32 EPA’s RFA guidance for rule writers suggests
the ‘‘sales’’ test continues to be the preferred
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SBA size
standard (effective March
11, 2008)
17:39 Oct 29, 2009
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quantitative metric for economic impact screening
analysis.
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TABLE VII–5—ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a—Continued
Owned by enterprises with:
Industry
NAICS
NAICS description
Iron and Steel .......
331112
Lead Production ....
3314
Lime Manufacturing.
Nitric Acid ..............
327410
Electrometallurgical ferroalloy
product mfg.
Nonferrous metal
(except aluminum) production & processing.
Lime mfg ..............
Petrochemical .......
324110
Phosphoric Acid ....
325312
Pulp and Paper .....
Refineries ..............
322110
324110
Silicon Carbide ......
327910
Soda Ash Manufacturing.
Titanium Dioxide ...
3251
325188
Zinc Production .....
3314
325311
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.
SBA size
standard (effective March
11, 2008)
Average
cost per
entity
($1,000/
entity)
All enterprises
(percent)
750 ..............
30
750 to 1,000
<20 employees f
(percent)
20 to 99
employees
(percent)
100 to
499 employees
(percent)
500 to
749 employees
(percent)
750 to
999 employees
(percent)
1,000 to
1,499
employees
(percent)
0.1
NA
NA
NA
NA
NA
NA
10
0.0
0.6
0.1
0.0
NA
NA
0.0
500 ..............
60
0.4
16.5
1.2
NA
NA
NA
NA
1,000 ...........
20
0.1
1.0
0.6
NA
NA
NA
NA
(c) ................
27
0.0
0.4
0.0
0.0
0.0
NA
NA
500 ..............
60
0.1
10.1
NA
NA
NA
NA
NA
750 ..............
(c) ................
20
41
0.0
0.0
1.4
0.6
NA
0.0
NA
0.0
NA
0.0
NA
NA
NA
NA
500 ..............
10
0.1
0.8
0.2
0.1
NA
NA
NA
500 to 1,000
16
0.0
0.5
0.1
0.0
0.0
0.0
0.0
1,000 ...........
10
0.0
0.7
0.4
0.1
NA
NA
NA
750 to 1,000
13
0.1
0.9
0.1
0.0
NA
NA
0.0
sroberts on DSKD5P82C1PROD with RULES
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 four 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.
EPA was not able to calculate a costto-sales ratio for manure management
(NAICS 112) as Statistics of U.S.
Businesses ([SUSB]SBA, 2008a) data do
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
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17:39 Oct 29, 2009
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be $0.3 million with an average cost per
ton of CO2e reported of $0.07.
As shown, the cost-to-sales ratios are
less than one 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
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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
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these small businesses will be covered
by the rule, we performed several case
studies for manufacturing industries
where the cost-to-receipt ratio exceeded
one percent. For each industry, we used
and applied emission data from a recent
study examining emission thresholds 33.
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 one
percent.
For the other enterprise categories
identified with ratios between one
percent and three 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 will 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 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 one percent of revenue.
These impacts are likely representative
of ratios in industries where data
limitations do not allow EPA to
33 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.
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compute sales tests (e.g., general
stationary combustion and manure
management). Potential impacts of the
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 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 $18,000
per local government. Thus, for the
smallest group of local governments
(<10,000 people), cost-to-revenue ratio
is 0.7 percent. For the larger group of
governments less than 50,000, the costto-revenue ratio is 0.2 percent.
2. Summary of Comments and
Responses
Comment: Comments received on
small business impacts focused on the
economic burden to small businesses for
compliance with mandatory GHG
reporting. One commenter noted that
lowering the reporting threshold below
the proposed 25,000 metric ton CO2e
level would disproportionately affect
small businesses. Another commenter
stated that small businesses are not well
equipped to handle detailed
requirements for reporting and that the
proposed rule would impose a large
burden for monitoring, recordkeeping,
and reporting activities.
Additional comments received
requested that EPA establish a SBREFA
process to investigate the impacts that
the proposed rule would have on small
businesses.
Response: As summarized above, EPA
investigated alternative thresholds and
analyzed the marginal costs associated
with requiring smaller entities with
lower emissions to report. EPA
recognized the additional burden placed
on small entities at lower thresholds,
and had retained the hybrid method for
reporting that includes a 25,000 metric
ton CO2e level threshold. Under this
threshold, EPA has assessed the
economic impact of the final rule on
small entities and concluded that this
action will not have a significant
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economic impact on a substantial
number of small entities.
For this reason, EPA did not establish
a SBREFA panel process for the
rulemaking. The summary of the factual
basis for the certification is provided in
the preamble for the rule. Complete
documentation of the analysis can be
found in Section 5.2 of the RIA for the
final rule.
E. What are the benefits of the rule for
society?
1. Summary of Method Used To
Estimate Compliance Costs
EPA examined the potential benefits
of the GHG reporting rule. The benefits
of a reporting system are based on their
relevance to policy making,
transparency issues, and market
efficiency. Benefits are 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 will
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 will 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 will 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, and a better
understanding of their emission levels
and sources to identify opportunities to
reduce emissions. Such monitoring
allows for inclusion of standardized
GHG data into environmental
management systems, providing the
necessary information to achieve and
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disseminate their environmental
achievements.
Standardization will 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 will
also allow for facilities to benchmark
themselves against similar facilities to
understand better their relative standing
within their industry.
2. Summary of Comments and
Responses
Comment: Comments received on the
benefits of the mandatory reporting
program focused on the potential future
uses of the collected data. Additional
comments on the benefits of the
program were concerned that the
benefits of the rule are not quantified.
Response: The data collected under
this rule will provide comprehensive
and accurate data to inform future
climate change policies. Potential future
CAA and other 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
EPA does not know at this time the
specific policies that may be adopted,
the data reported through this rule
should be of sufficient quality to
support a range of approaches.
Section VI of the RIA for the final rule
summarizes the anticipated benefits of
the rule, which include providing the
government with sound data on which
to base future policies and providing
industry and the public independently
verified information documenting firms’
environmental performance. While EPA
has not quantified the benefits of the
mandatory reporting rule, EPA believes
that they are substantial and outweigh
the estimated costs.
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VIII. Statutory and Executive Order
Reviews
A. Executive Order 12866: Regulatory
Planning and Review
Under section 3(f)(1) of EO 12866 (58
FR 51735, October 4, 1993), this action
is an ‘‘economically significant
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
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associated with this action. A copy of
the analysis is available in Docket No.
EPA–HQ–OAR–2008–0508, the RIA for
the final rule, and is briefly summarized
in Section VII of this preamble.
B. Paperwork Reduction Act
The information collection
requirements in this rule have been
submitted for approval to the Office of
Management and Budget (OMB) under
the Paperwork Reduction Act, 44 U.S.C.
3501 et seq. The information collection
requirements are not enforceable until
OMB approves them. The ICR document
prepared by EPA has been assigned EPA
ICR number 2300.03.
EPA plans to collect complete and
accurate economy-wide data on facilitylevel GHG emissions. Accurate and
timely information on GHG 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 GHG 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 data collected
under CAA sections 114 and 208 cannot
generally be claimed as CBI and will be
made public.34
The projected cost and hour burden
for non-Federal respondents is $86.3
million and 1.21 million hours per year.
The estimated average burden per
response is two hours; the frequency of
response is annual for all respondents
34 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). As discussed in Section II.R of this preamble,
EPA will be initiating a separate notice and
comment process to make CBI determinations for
the data collected under this rulemaking.
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that must comply with the 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
16,725 35. 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 $9.1 million), a total
operation and maintenance component
(averaging $11.0 million per year), and
a labor cost component (averaging $66.1
million per year). Burden is defined at
5 CFR 1320.3(b). These cost numbers
differ from those shown elsewhere in
the RIA for the final rule because the
ICR costs represent the average cost over
the first three years of the rule, but costs
are reported elsewhere in the RIA for
the final rule for the first year of the rule
and for subsequent years of the rule. In
addition, the ICR focuses on respondent
burden, while the RIA for the final rule
includes EPA Agency costs.
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. When
this ICR is approved by OMB, the
Agency will publish a technical
amendment to 40 CFR part 9 in the
Federal Register to display the OMB
control number for the approved
information collection requirements
contained in this final rule.
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
35 EPA estimates that 30,000 facilities are
potentially affected by the rule. Of these, EPA
estimates that 10,152 facilities across various
sectors will be over their sector-specific reporting
threshold and thus required to report; the remaining
19,848 will determine during the first year that they
are beneath the threshold and do not need to report.
The average number of respondents is thus
(30,000+10,152+10,152)/3 = 16,768; excluding 43
Federal facilities, the number of private
respondents is 16,725.
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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 final rule on small
entities, I therefore certify that this final
rule will not have a significant
economic impact on a substantial
number of small entities.
The small entities directly regulated
by this final 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, because
they have stationary combustion units
on site that emit GHGs that must be
reported, or because they have fuel
supplier operations for which supply
quantities and GHG data must be
reported. Small governments and small
non-profits are generally affected
because they have regulated landfills or
stationary combustion units on site, or
because they own an 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 final rule as a percentage of
sales and determines whether the ratio
exceeds some level (e.g., one percent or
three percent). The cost-to-sales ratios
were constructed at the establishment
level (average compliance cost for the
establishment/average establishment
revenues). As shown in Table VII–5 of
this preamble, the cost-to-sales ratios are
less than one percent for establishments
owned by small businesses that EPA
considers most likely to be covered by
the reporting program, those with more
than 20 employees.36 For the few sectors
where the preliminary screening
showed a cost-to-sales ratio exceeding
one percent, EPA’s examination of firmspecific sales information showed that
no affected entity was likely to incur
costs exceeding one percent of sales.
36 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.
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The screening analysis thus indicates
that the final rule will not have a
significant economic impact on a
substantial number of small entities. See
Table VII–5 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 one percent of average
revenues for the smallest category of
governments (those with fewer than
10,000 people).
Although this final 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 prior to proposal of the rule,
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 prior to proposal of
the rule 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. After proposal, EPA
posted a guide for small businesses on
EPA’s GHG reporting rule Web site,
along with a general fact sheet for the
rule, information sheets for every source
category, and an FAQ document. EPA
also operated a hotline to answer
questions about the proposed rule. We
continued to meet with stakeholders
and entered documentation of all
meetings into the docket. We considered
public comments, including comments
from small businesses and organizations
that include small business members, in
developing the final rule.
During rule implementation, EPA will
maintain an ‘‘open door’’ policy for
stakeholders to ask questions about the
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rule or provide suggestions to EPA
about the types of compliance assistance
that would be useful to small
businesses. EPA intends to develop a
range of compliance assistance tools and
materials and conduct extensive
outreach for the final rule.
D. Unfunded Mandates Reform Act
(UMRA)
Title II of the Unfunded Mandates
Reform Act 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, and biologic). 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
$12.1 million per year, based on average
costs over the first three years of the
rule, including approximately $2
million during the first year of the rule
for governments 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.
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
organizations, and other State and local
government organizations. EPA
contacted several States and State and
regional organizations already involved
in GHG emissions reporting. EPA also
conducted several conference calls with
Tribal organizations during the proposal
phase. For example, EPA staff provided
information to tribes through conference
calls with multiple Tribal working
groups and organizations at EPA and
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through individual calls with two Tribal
board members of TRI. In addition, EPA
held meetings and conference calls with
groups such as TRI, National
Association of Clean Air Agencies
(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–2008–0508–055 for a
complete list of organizations and
groups that EPA contacted.
At proposal of the rule, EPA posted a
guide for State and local agencies on the
Web site, along with other information
sheets, to communicate key aspects of
the proposed rule to these agencies.
Several State and local agencies and
three Tribal organizations or
communities submitted written public
comments, and EPA carefully
considered these comments in
developing the final rule. EPA also
continued to meet with government
agencies or organizations with State
members such as California ARB,
Connecticut DEP, New Jersey DEP, New
Mexico ED, Washington DE,
Massachusetts DEP, Illinois EPA, Iowa
DNR, and TCR These meetings are
documented in the docket. EPA intends
to continue to work closely with State,
local, and Tribal agencies during rule
implementation.
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
GHG reporting rule, and has concluded
that the costs will fall mainly on the
private sector (approximately $77
million), with some costs incurred by
State, local, and Tribal governments that
must report their emissions (less than
$10.1 million) that own and operate
stationary combustion units, landfills,
or natural gas local distribution
companies (LDCs). EPA estimates that
an additional 2,034 facilities owned by
State, local, or Tribal governments will
incur approximately $2.0 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
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large industrial facilities, similar to
those affected by this rulemaking
operated by the private sector.
Initially, EPA estimates that costs of
complying with the final 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 $104 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 percent of
company sales in affected industries.
These costs are broadly distributed to a
variety of economic sectors and
represent approximately 0.001 percent
of 2008 Gross Domestic Product; overall,
EPA does not believe the final rule will
have a significant macroeconomic
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 final rule. EPA further expects
that benefits of the final rule will
include more and better information for
EPA and the private sector about
emissions of GHGs. This improved
information will 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,
to motor vehicle manufacturers, 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 GHGs
above threshold levels such as a landfill
or large stationary combustion source,
or LDC. 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
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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 final 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 final rule
relates to existing State programs, please
see Section II of the proposal preamble
(74 FR 16457 to 16461, April 10, 2009)
and Sections I.E. and II.C.2 of this
preamble.
This regulation applies directly to
facilities that supply fuel or chemicals
that when used emit greenhouse gases,
motor vehicle manufacturers, or
facilities that directly emit greenhouses
gases. It does not apply to governmental
entities unless the government entity
owns a facility that directly emits GHGs
above threshold levels such as a landfill,
large stationary combustion source, or
LDC, 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 solicited comments on the
proposed rule from State and local
officials. See Section VIII.D above, for
discussion of outreach activities to
State, local, or Tribal organizations.
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This final rule does not have Tribal
implications, as specified in EO 13175
(65 FR 67249, November 9, 2000). This
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regulation applies directly to facilities
that supply fuel or chemicals that when
used emit GHGs or facilities that
directly emit greenhouses gases.
Facilities expected to be affected by the
final rule are not expected to be owned
by Tribal governments. Thus, Executive
Order 13175 does not apply to this final
rule.
Although EO 13175 does not apply to
this final 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 during the proposal
phase. 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
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
participated in a conference call with
Tribal air coordinators in April 2009
and prepared a guidance sheet for Tribal
governments on the proposed rule. It
was posted on the MRR Web site and
published in the Tribal Air Newsletter.
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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.
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H. Executive Order 13211: Actions That
Significantly Affect Energy Supply,
Distribution, or Use
This final 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 final rule relates to
monitoring, reporting and
recordkeeping at facilities that supply
fuel or chemicals that when used emit
GHGs 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 rulemaking involves technical
standards. EPA will use more than 60
voluntary consensus standards from 10
different voluntary consensus standards
bodies, including the following: ASTM,
ASME, ISO, Gas Processors Association,
American Gas Association, and National
Lime Association. These voluntary
consensus standards will help facilities
monitor, report, and keep records of
GHG emissions. No new test methods
were developed for this rule. Instead,
from existing rules for source categories
and voluntary GHG programs, EPA
identified existing means of monitoring,
reporting, and keeping records of GHG
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
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incorporated by reference into the final
rule and are available as specified in 40
CFR 98.7.
By incorporating voluntary consensus
standards into this final rule, EPA is
both meeting the requirements of the
NTTAA and presenting multiple
options and flexibility for measuring
GHG emissions.
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 final
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 final rule does not
affect the level of protection provided to
human health or the environment
because it is a rule addressing
information collection and reporting
procedures.
K. Congressional Review Act
The Congressional Review Act, 5
U.S.C. 801 et seq., as added by the Small
Business Regulatory Enforcement
Fairness Act of 1996, generally provides
that before a rule may take effect, the
agency promulgating the rule must
submit a rule report, which includes a
copy of the rule, to each House of the
Congress and to the Comptroller General
of the United States. EPA will submit a
report containing this rule and other
required information to the U.S. Senate,
the U.S. House of Representatives, and
the Comptroller General of the U.S.
prior to publication of the rule in the
Federal Register. A major rule cannot
take effect until 60 days after it is
published in the Federal Register. This
action is a ‘‘major rule’’ as defined by
5 U.S.C. 804(2). This rule will be
effective December 29, 2009.
List of Subjects
40 CFR Part 86
Environmental protection,
Administrative practice and procedure,
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40 CFR Parts 1045, 1048, 1051, and
1054
Air pollution control, Reporting and
recordkeeping requirements, Motor
vehicle pollution.
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 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 1065
40 CFR Part 90
Dated: September 22, 2009.
Lisa P. Jackson,
Administrator.
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
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,
Air pollution control, Confidential
business information, Imports,
Incorporation by reference, Labeling,
Penalties, Reporting and recordkeeping
requirements, Warranties.
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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.
17:39 Oct 29, 2009
Jkt 220001
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:
■
Required data.
*
*
*
*
(n) Measure CO2, N2O, and CH4 with
each low-hour certification test for
heavy-duty engines using the
procedures specified in 40 CFR part
1065 as specified in this paragraph (n).
Report these values in your application
for certification. The requirements of
this paragraph (n) apply starting with
model year 2011 for CO2 and 2012 for
CH4. The requirements of this paragraph
(n) related to N2O emissions apply for
engine families that depend on NOx
aftertreatment to meet emission
standards starting with model year
2013. 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/bhphr.
(2) Round N2O to the nearest 0.001 g/
bhp-hr.
(3) Round CH4 to the nearest 0.001 g/
bhp-hr.
■ 3. Section 86.078–3 is amended by
removing the paragraph designation
‘‘(a)’’ and adding the abbreviations CH4
and N2O in alphanumeric order to read
as follows:
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*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
Subpart E—[Amended]
4. Section 86.403–78 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
■
§ 86.403–78
*
Abbreviations.
*
*
*
*
For the reasons stated in the preamble,
title 40, chapter I, of the Code of Federal
Regulations is amended as follows:
§ 86.007–23
Abbreviations.
*
*
■
*
Environmental protection,
Administrative practice and procedure,
Greenhouse gases, Incorporation by
reference, Suppliers, Reporting and
recordkeeping requirements.
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Environmental protection,
Administrative practice and procedure,
Incorporation by reference, Reporting
and recordkeeping requirements,
Research.
§ 86.078–3
56373
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
■ 5. Section 86.431–78 is amended by
adding paragraph (e) to read as follows:
§ 86.431–78
Data submission.
*
*
*
*
*
(e) Measure CO2, N2O, and CH4 as
described in this paragraph (e) 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 analytical equipment and
procedures specified in 40 CFR part
1065 as needed to measure N2O and
CH4. Report these values in your
application for certification. The
requirements of this paragraph (e) apply
starting with model year 2011 for CO2
and 2012 for CH4. The requirements of
this paragraph (e) related to N2O
emissions apply for engine families that
depend on NOX aftertreatment to meet
emission standards starting with model
year 2013. Small-volume manufacturers
(as defined in § 86.410–2006(e)) may
omit measurement of N2O and CH4;
other manufacturers may provide
appropriate data and/or information and
omit measurement of N2O and CH4 as
described in 40 CFR 1065.5. 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 0.001 g/
km.
PART 87—[AMENDED]
6. The authority citation for part 87 is
revised to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
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Subpart A—[Amended]
Subpart E—[Amended]
Subpart B—[Amended]
7. Section 87.2 is amended by revising
the section heading and adding the
abbreviation CO2 in alphanumeric order
to read as follows:
■
11. Section 89.407 is amended by
revising paragraph (d)(1) to read as
follows:
■
■
§ 87.2
*
*
*
*
*
CO2 Carbon dioxide.
*
*
*
*
*
8. Section 87.64 is revised to read as
follows:
■
§ 87.64 Sampling and analytical
procedures for measuring gaseous exhaust
emissions.
(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 January 1, 2011, report
CO2 values along with your emission
levels of regulated NOX to the
Administrator for engines of a type or
model of which the date of manufacture
of the first individual production model
was on or after January 1, 2011. By
January 1, 2011, report CO2 values along
with your emission levels of regulated
NOX to the Administrator for engines
currently in production and of a type or
model for which the date of
manufacture of the individual engine
was before January 1, 2011. Round CO2
to the nearest 1 g/kilonewton rO.
(c) Report CO2 by calculation from
fuel mass flow rate measurements in
Appendices 3 and 5 to ICAO Annex 16,
volume II or alternatively, according to
the measurement criteria of CO2 in
Appendices 3 and 5 to ICAO Annex 16,
volume II.
9. The authority citation for part 89
continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
10. Section 89.115 is amended by
revising paragraph (d)(9) to read as
follows:
■
Application for certificate.
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*
*
*
*
*
(d) * * *
(9) All test data obtained by the
manufacturer on each test engine,
including CO2 as specified in
§ 89.407(d)(1);
*
*
*
*
*
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17:39 Oct 29, 2009
*
*
*
*
(d) * * *
(1) Measure HC, CO, CO2, and NOx
concentrations in the exhaust sample.
Use the same units and modal
calculations as for your other results to
report a single weighted value for CO2;
round CO2 to the nearest 1 g/kW-hr.
*
*
*
*
*
12. The authority citation for part 90
continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart B—[Amended]
13. Section 90.107 is amended by
revising paragraph (d)(8) to read as
follows:
■
§ 90.107
Application for certification.
*
*
*
*
*
(d) * * *
(8) All test data obtained by the
manufacturer on each test engine,
including CO2 as specified in
§ 90.409(c)(1);
*
*
*
*
*
Subpart E—[Amended]
14. Section 90.409 is amended by
revising paragraph (c)(1) to read as
follows:
■
§ 90.409
Engine dynamometer test run.
*
*
*
*
*
(c) * * *
(1) Measure HC, CO, CO2, and NOX
concentrations in the exhaust sample.
Use the same units and modal
calculations as for your other results to
report a single weighted value for CO2;
round CO2 to the nearest 1 g/kW–hr.
*
*
*
*
*
Jkt 220001
15. The authority citation for part 94
continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart A—[Amended]
16. Section 94.3 is amended by adding
the abbreviation CH4 in alphanumeric
order to read as follows:
■
§ 94.3
*
Abbreviations.
*
*
CH4 methane.
*
*
*
*
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*
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§ 94.103 Test procedures for Category 1
marine engines.
*
*
*
*
*
(c) Measure CH4 as specified in 40
CFR 1042.235 starting in the 2012
model year.
■ 18. Section 94.104 is amended by
adding paragraph (e) to read as follows:
§ 94.104 Test procedures for Category 2
marine engines.
*
PART 90—[AMENDED]
PART 94—[AMENDED]
Subpart B—[Amended]
§ 89.115
Engine dynamometer test run.
*
Acronyms and abbreviations.
PART 89—[AMENDED]
§ 89.407
17. Section 94.103 is amended by
adding paragraph (c) to read as follows:
*
*
*
*
(e) Measure CO2 as described in 40
CFR 92.129 through the 2010 model
year. Measure CO2 as specified in 40
CFR 1042.235 starting in the 2011
model year. Measure CH4 as specified in
40 CFR 1042.235 starting in the 2012
model year.
Subpart C—[Amended]
19. Section 94.203 is amended by
revising paragraph (d)(10) to read as
follows:
■
§ 94.203
Application for certification.
*
*
*
*
*
(d) * * *
(10) All test data obtained by the
manufacturer on each test engine,
including CO2 and CH4 as specified in
40 CFR 89.407(d)(1) and § 94.103(c) for
Category 1 engines, § 94.104(e) for
Category 2 engines, and § 94.109(d) for
Category 3 engines. Small-volume
manufacturers may omit measurement
and reporting of CH4.
*
*
*
*
*
■ 20. Add part 98 to read as follows:
PART 98—MANDATORY
GREENHOUSE GAS REPORTING
Sec.
Subpart A—General Provisions
98.1 Purpose and scope.
98.2 Who must report?
98.3 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 is the report submitted?
98.6 Definitions.
98.7 What standardized methods are
incorporated by reference into this part?
98.8 What are the compliance and
enforcement provisions of this part?
98.9 Addresses.
Table A–1 to Subpart A of Part 98—Global
Warming Potentials (100-Year Time
Horizon)
Table A–2 to Subpart A of Part 98—Units of
Measure Conversions
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Subpart B—[RESERVED]
98.78
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 to Subpart C of Part 98—Default
CO2 Emission Factors and High Heat
Values for Various Types of Fuel
Table C–2 to Subpart C of Part 98—Default
CH4 and N2O Emission Factors for
Various Types of Fuel
Subpart H—Cement Production
98.80 Definition of the source category.
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 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.
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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.
Table F–1 to Subpart F of Part 98—Slope and
Overvoltage Coefficients for the
Calculation of PFC Emissions From
Aluminum Production
Table F–2 to Subpart F of Part 98—Default
Data Sources for Parameters Used for
CO2 Emissions
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.
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Definitions.
Subpart I—[RESERVED]
Subpart J—[RESERVED]
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 to Subpart K of Part 98—Electric
Arc Furnace (EAF) CH4 Emission Factors
Subpart L—[RESERVED]
Subpart M—[RESERVED]
Subpart N—Glass Production
98.140 Definition of the source category.
98.141 Reporting threshold.
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 to Subpart N of Part 98—CO2
Emission Factors for Carbonate-Based
Raw Materials
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.
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.
Table O–1 to Subpart O of Part 98—Emission
Factors for Equipment Leaks
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.
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98.166
98.167
98.168
56375
Data reporting requirements.
Records that must be retained.
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.
98.183 Calculating GHG emissions.
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.
98.197 Records that must be retained.
98.198 Definitions.
Table S–1 to Subpart S of Part 98—Basic
Parameters for the Calculation of
Emission Factors for Lime Production
Subpart T—[RESERVED]
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 to Subpart U of Part 98—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.
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Subpart W—[RESERVED]
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.
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.
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.
Table Z–1 to Subpart Z of Part 98—Default
Chemical Composition of Phosphate
Rock by Origin
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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 to Subpart AA of Part 98—Kraft
Pulping Liquor Emissions Factors for
Biomass-Based CO2, CH4, and N2O
Table AA–2 to Subpart AA of Part 98—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.
98.282 GHGs to report.
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.
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Subpart DD—[RESERVED]
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—[RESERVED]
Subpart Z—Phosphoric Acid Production
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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 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—Municipal Solid Waste
Landfills
98.340 Definition of the source category.
98.341 Reporting threshold.
98.342 GHGs to report.
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 to Subpart HH of Part 98—
Emissions Factors, Oxidation Factors
and Methods
Table HH–2 to Subpart HH of Part 98—U.S.
Per Capita Waste Disposal Rates
Table HH–3 to Subpart HH of Part 98—
Landfill Gas Collection Efficiencies
Subpart II—[RESERVED]
Subpart JJ—Manure Management
98.360 Definition of the source category.
98.361 Reporting threshold.
98.362 GHGs to report.
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.
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Table JJ–1 to Subpart JJ of Part 98—Animal
Population Threshold Level Below
which Facilities are not required to
report Emissions under Subpart JJ
Table JJ–2 to Subpart JJ of Part 98—Waste
Characteristics Data
Table JJ–3 to Subpart JJ of Part 98—StateSpecific Volatile Solids (VS) and
Nitrogen (N) Excretion Rates for Cattle
Table JJ–4 to Subpart JJ of Part 98—Volatile
Solids and Nitrogen Removal through
Solids Separation
Table JJ–5 to Subpart JJ of Part 98—Methane
Conversion Factors
Table JJ–6 to Subpart JJ of Part 98—Collection
Efficiencies of Anaerobic Digesters
Table JJ–7 to Subpart JJ of Part 98—Nitrous
Oxide Emission Factors (kg N2O–N/kg
Kjdl N)
Subpart KK—[RESERVED]
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 to Subpart MM—Default CO2
Factors for Petroleum Products
Table MM–2 to Subpart MM—Default Factors
for Biomass-Based Fuels and Biomass
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.
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 to Subpart NN of Part 98—
Default Factors for Calculation
Methodology 1 of this Subpart
Table NN–2 to Subpart NN of Part 98—
Lookup Default Values for Calculation
Methodology 2 of this Subpart
Subpart OO—Suppliers of Industrial
Greenhouse Gases
98.410 Definition of the source category.
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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 CO2 supply.
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) reporting
requirements for owners and operators
of certain facilities that directly emit
GHG as well as for certain fossil fuel
suppliers and industrial GHG suppliers.
For suppliers, the GHGs reported are the
quantity that would be emitted from
combustion or use of the products
supplied.
(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.
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§ 98.2
Who must report?
(a) The GHG reporting requirements
and related monitoring, recordkeeping,
and reporting requirements of this part
apply to the owners and operators of
any facility that is located in the United
States and 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 source
category (as defined in subparts C
through JJ of this part) that is listed in
this paragraph (a)(1) in any calendar
year starting in 2010. For these facilities,
the annual GHG report must cover all
source categories and GHGs for which
calculation methodologies are provided
in subparts C through JJ of this part.
(i) Electricity generation (units that
report CO2 emissions year-round
through 40 CFR part 75).
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(ii) Adipic acid production.
(iii) Aluminum production.
(iv) Ammonia manufacturing.
(v) Cement production.
(vi) HCFC–22 production.
(vii) 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.
(viii) Lime manufacturing.
(ix) Nitric acid production.
(x) Petrochemical production.
(xi) Petroleum refineries.
(xii) Phosphoric acid production.
(xiii) Silicon carbide production.
(xiv) Soda ash production.
(xv) Titanium dioxide production.
(xvi) Municipal solid waste landfills
that generate CH4 in amounts equivalent
to 25,000 metric tons CO2e or more per
year, as determined according to subpart
HH of this part.
(xvii) Manure management systems
with combined CH4 and N2O emissions
in amounts equivalent to 25,000 metric
tons CO2e or more per year, as
determined according to subpart JJ of
this part.
(2) A facility that contains any source
category (as defined in subparts C
through JJ of this part) that is listed in
this paragraph (a)(2) in any calendar
year starting in 2010 and 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. For these facilities, the
annual GHG report must cover all
source categories and GHGs for which
calculation methodologies are provided
in subparts C through JJ of this part.
(i) Ferroalloy Production.
(ii) Glass Production.
(iii) Hydrogen Production.
(iv) Iron and Steel Production.
(v) Lead Production.
(vi) Pulp and Paper Manufacturing.
(vii) Zinc Production.
(3) A 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 annual
GHG report must cover emissions from
stationary fuel combustion sources only.
(i) The facility does not meet the
requirements of either paragraph (a)(1)
or (a)(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 in combined
emissions from all stationary fuel
combustion sources.
(4) A supplier (as defined in subparts
KK through PP of this part) that
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provides products listed in this
paragraph (a)(4) in any calendar year
starting in 2010. For these suppliers, the
annual GHG report must cover all
applicable products for which
calculation methodologies are provided
in subparts KK through PP of this part.
(i) Coal-to-liquids suppliers, as
specified in this paragraph (a)(4)(i).
(A) All producers of coal-to-liquid
products.
(B) Importers of an annual quantity of
coal-to-liquid products that is
equivalent to 25,000 metric tons CO2e or
more.
(C) Exporters of an annual quantity of
coal-to-liquid products is equivalent to
25,000 metric tons CO2e or more.
(ii) Petroleum product suppliers, as
specified in this paragraph (a)(4)(ii):
(A) All petroleum refineries that
distill crude oil.
(B) Importers of an annual quantity of
petroleum products that is equivalent to
25,000 metric tons CO2e or more.
(C) Exporters of an annual quantity of
petroleum products that is equivalent to
25,000 metric tons CO2e or more.
(iii) Natural gas and natural gas
liquids suppliers, as specified in this
paragraph (a)(4)(iii):
(A) All natural gas fractionators.
(B) All local natural gas distribution
companies.
(iv) Industrial greenhouse gas
suppliers, as specified in this paragraph
(a)(4)(iv):
(A) All producers of industrial
greenhouse gases.
(B) Importers of industrial greenhouse
gases with annual bulk imports of N2O,
fluorinated GHG, and CO2 that in
combination are equivalent to 25,000
metric tons CO2e or more.
(C) Exporters of industrial greenhouse
gases with annual bulk exports of N2O,
fluorinated GHG, and CO2 that in
combination are equivalent to 25,000
metric tons CO2e or more.
(v) Carbon dioxide suppliers, as
specified in this paragraph (a)(4)(v).
(A) All producers of CO2.
(B) Importers of CO2 with annual bulk
imports of N2O, fluorinated GHG, and
CO2 that in combination are equivalent
to 25,000 metric tons CO2e or more.
(C) Exporters of CO2 with annual bulk
exports of N2O, fluorinated GHG, and
CO2 that in combination are equivalent
to 25,000 metric tons CO2e or more.
(5) Research and development
activities are not considered to be part
of any source category defined in this
part.
(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
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CO2e emissions, as described in
paragraphs (b)(1) through (b)(4) of this
section.
(1) Calculate the annual emissions of
CO2, CH4, N2O,and each fluorinated
GHG in metric tons from all applicable
source categories listed in paragraph
(a)(2) of this section. The GHG
emissions shall be calculated using the
calculation methodologies specified in
each applicable subpart and available
company records. Include emissions
from only those gases listed in Table A–
1 of this subpart.
(2) For each general stationary fuel
combustion unit, calculate the annual
CO2 emissions in metric tons using any
of the four calculation methodologies
specified in § 98.33(a). Calculate the
annual CH4 and N2O emissions from the
stationary fuel combustion sources in
metric tons using the appropriate
equation in § 98.33(c). Exclude carbon
dioxide emissions from the combustion
of biomass, but include emissions of
CH4 and N2O from biomass combustion.
(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), (b)(2), and (b)(3) of
this section for each GHG and calculate
metric tons of CO2e using Equation A–
1 of this section.
n
CO 2e = ∑ GHG i x GWPi
(Eq. A-1)
i =1
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2e = Carbon dioxide equivalent, metric
tons/year.
GHGi = Mass emissions of each greenhouse
gas listed in Table A–1 of this subpart,
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,
include in the emissions calculation any
CO2 that is captured for transfer off site.
(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, calculate
CO2, CH4, and N2O emissions from each
stationary fuel combustion unit by
following 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
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CO2 per year threshold for importers
and exporters of coal-to-liquid products
under paragraph (a)(4)(i) of this section,
calculate the mass in metric tons per
year of CO2 that would result from the
complete combustion or oxidation of the
quantity of coal-to-liquid products that
are imported during the reporting year
and that are exported during the
reporting year. Calculate the emissions
using the methodology specified in
subpart LL of this part.
(e) To calculate GHG quantities for
comparison to the 25,000 metric ton
CO2e per year threshold for importers
and exporters of petroleum products
under paragraph (a)(4)(ii) of this section,
calculate the mass in metric tons per
year of CO2 that would result from the
complete combustion or oxidation of the
volume of petroleum products and
natural gas liquids that are imported
during the reporting year and that are
exported during the reporting year.
Calculate the emissions using the
methodology specified in subpart MM
of this part.
(f) To calculate GHG quantities for
comparison to the 25,000 metric ton
CO2e per year threshold under
paragraph (a)(4) of this section for
importers and exporters of industrial
greenhouse gases and for importers and
exporters of CO2, the owner or operator
shall calculate the mass in metric tons
per year of CO2e imports and exports as
described in paragraphs (f)(1) through
(f)(3) of this section.
(1) Calculate the mass in metric tons
per year of CO2, N2O, and each
fluorinated GHG that is imported and
the mass in metric tons per year of CO2,
N2O, and each fluorinated GHG that is
exported during the year. Include only
those gases listed in Table A–1 of this
subpart.
(2) Convert the mass of each imported
and each GHG exported from paragraph
(f)(1) of this section to metric tons of
CO2e using Equation A–1 of this section.
(3) Sum the total annual metric tons
of CO2e in paragraph (f)(2) of this
section for all imported GHGs. Sum the
total annual metric tons of CO2e in
paragraph (f)(2) of this section for all
exported GHGs.
(g) If a capacity or generation
reporting threshold in paragraph (a)(1)
of this section applies, the owner or
operator shall review the appropriate
records and perform any necessary
calculations to determine whether the
threshold has been exceeded.
(h) An owner or operator of a facility
or supplier that does not meet the
applicability requirements of paragraph
(a) of this section is not subject to this
rule. Such owner or operator would
become subject to the rule and reporting
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requirements § 98.3(b)(3), if a facility or
supplier exceeds the applicability
requirements of paragraph (a) of this
section at a later time. Thus, the owner
or operator should reevaluate the
applicability to this part (including the
revising of any relevant emissions
calculations or other calculations)
whenever there is any change that could
cause a 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 material use, addition of
equipment, and facility expansion.
(i) Except as provided in this
paragraph, once a facility or supplier is
subject to the requirements of this part,
the owner or operator must continue for
each year thereafter to comply with all
requirements of this part, including the
requirement to submit annual GHG
reports, even if the facility or supplier
does not meet the applicability
requirements in paragraph (a) of this
section in a future year.
(1) If reported emissions are less than
25,000 metric tons CO2e per year for five
consecutive years, then the owner or
operator may discontinue complying
with this part provided that the owner
or operator submits a notification to the
Administrator that announces the
cessation of reporting and explains the
reasons for the reduction in emissions.
The notification shall be submitted no
later than March 31 of the year
immediately following the fifth
consecutive year of emissions less than
25,000 tons CO2e per year. The owner
or operator must maintain the
corresponding records required under
§ 98.3(g) for each of the five consecutive
years and retain such records for three
years following the year that reporting
was discontinued. The owner or
operator must resume reporting if
annual emissions in any future calendar
year increase to 25,000 metric tons CO2e
per year or more.
(2) If reported emissions are less than
15,000 metric tons CO2e per year for
three consecutive years, then the owner
or operator may discontinue complying
with this part provided that the owner
or operator submits a notification to the
Administrator that announces the
cessation of reporting and explains the
reasons for the reduction in emissions.
The notification shall be submitted no
later than March 31 of the year
immediately following the third
consecutive year of emissions less than
15,000 tons CO2e per year. The owner
or operator must maintain the
corresponding records required under
§ 98.3(g) for each of the three
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consecutive years and retain such
records for three years following the
year that reporting was discontinued.
The owner or operator must resume
reporting if annual emissions in any
future calendar year increase to 25,000
metric tons CO2e per year or more.
(3) If the operations of a facility or
supplier are changed such that all
applicable GHG-emitting processes and
operations listed in paragraphs (a)(1)
through (a)(4) of this section cease to
operate, then the owner or operator is
exempt from reporting in the years
following the year in which cessation of
such operations occurs, provided that
the owner or operator submits a
notification to the Administrator that
announces the cessation of reporting
and certifies to the closure of all GHGemitting processes and operations. This
paragraph (i)(2) does not apply to
seasonal or other temporary cessation of
operations. This paragraph (i)(2) does
not apply to facilities with municipal
solid waste landfills. The owner or
operator must resume reporting for any
future calendar year during which any
of the GHG-emitting processes or
operations resume operation.
(j) Table A–2 of this subpart provides
a conversion table for some of the
common units of measure used in part
98.
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§ 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 reports to the Administrator, as
specified in this section.
(a) General. Except as provided in
paragraph (d) of this section, follow the
procedures for emission calculation,
monitoring, quality assurance, missing
data, recordkeeping, and reporting that
are specified in each relevant subpart of
this part.
(b) Schedule. The annual GHG report
must be submitted no later than March
31 of each calendar year for GHG
emissions in the previous calendar year.
(1) For an existing facility or supplier
that began operation before January 1,
2010, report emissions for calendar year
2010 and each subsequent calendar
year.
(2) For a new facility or supplier that
begins operation on or after January 1,
2010, report emissions 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.
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(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, 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. For
a facility or supplier that becomes
subject to this rule solely because of an
increase in hours of operation or level
of production, the first month of the
change is the month in which the
increased hours of operation or level of
production, if maintained for the
remainder of the year, would cause the
facility or supplier to exceed the
applicable threshold. 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 report
shall contain the following information:
(1) Facility name or supplier name (as
appropriate) and physical street address
including the city, state, and zip code.
(2) Year and months covered by the
report.
(3) Date of submittal.
(4) For facilities, report annual
emissions of CO2, CH4, N2O, and each
fluorinated GHG (as defined in § 98.6) as
follows:
(i) Annual emissions (excluding
biogenic CO2) aggregated for all GHG
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) Annual emissions of biogenic CO2
aggregated for all applicable source
categories in subparts C through JJ of
this part.
(iii) Annual emissions from each
applicable source category in subparts C
through JJ of this part, expressed in
metric tons of each GHG listed in
paragraphs (c)(4)(iii)(A) through
(c)(4)(iii)(E) of this section.
(A) Biogenic CO2.
(B) CO2 (excluding biogenic CO2).
(C) CH4.
(D) N2O.
(E) Each fluorinated GHG (including
those not listed in Table A–1 of this
subpart).
(iv) Emissions and other data for
individual units. processes, activities,
and operations as specified in the ‘‘Data
reporting requirements’’ section of each
applicable subpart of this part.
(5) For suppliers, report annual
quantities of CO2, CH4, N2O, and each
fluorinated GHG (as defined in § 98.6)
that would be emitted from combustion
or use of the products supplied,
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56379
imported, and exported during the year.
Calculate and report quantities at the
following levels:
(i) Total quantity of GHG aggregated
for all GHG 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.
(ii) Quantity of each GHG from each
applicable supply category in subparts
KK through PP of this part, expressed in
metric tons of each GHG. For
fluorinated GHG, report emissions of all
fluorinated GHG, including those not
listed in Table A–1 of this subpart.
(iii) Any other data specified in the
‘‘Data reporting requirements’’ section
of each applicable subpart of this part.
(6) A written explanation, as required
under § 98.3(e), if you change emission
calculation methodologies during the
reporting period.
(7) A brief description of each ‘‘best
available monitoring method’’ used
according to paragraph (d) of this
section, the parameter measured using
the method, and the time period during
which the ‘‘best available monitoring
method’’ was used.
(8) Each data element for which a
missing data procedure was used
according to the procedures of an
applicable subpart and the total number
of hours in the year that a missing data
procedure was used for each data
element.
(9) 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) Special provisions for reporting
year 2010.
(1) Best available monitoring
methods. During January 1, 2010
through March 31, 2010, owners or
operators may use best available
monitoring methods for any parameter
(e.g., fuel use, daily carbon content of
feedstock by process line) that cannot
reasonably be measured according to the
monitoring and QA/QC requirements of
a relevant subpart. The owner or
operator must use the calculation
methodologies and equations in the
‘‘Calculating GHG Emissions’’ sections
of each relevant subpart, but may use
the best available monitoring method for
any parameter for which it is not
reasonably feasible to acquire, install,
and operate a required piece of
monitoring equipment by January 1,
2010. Starting no later than April 1,
2010, the owner or operator must
discontinue using best available
methods and begin following all
applicable monitoring and QA/QC
requirements of this part, except as
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provided in paragraphs (d)(2) and (d)(3)
of this section. Best available
monitoring methods means any of the
following methods specified in this
paragraph:
(i) Monitoring methods currently used
by the facility that do not meet the
specifications of an relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use
of best available monitoring methods.
The owner or operator may submit a
request to the Administrator to use one
or more best available monitoring
methods beyond March 31, 2010.
(i) Timing of request. The extension
request must be submitted to EPA no
later than 30 days after the effective date
of the GHG reporting rule.
(ii) Content of request. Requests must
contain the following information:
(A) A list of specific item of
monitoring instrumentation for which
the request is being made and the
locations where each piece of
monitoring instrumentation will be
installed.
(B) Identification of the specific rule
requirements (by rule subpart, section,
and paragraph numbers) for which the
instrumentation is needed.
(C) A description of the reasons why
the needed equipment could not be
obtained and installed before April 1,
2010.
(D) If the reason for the extension is
that the equipment cannot be purchased
and delivered by April 1, 2010, include
supporting documentation such as the
date the monitoring equipment was
ordered, investigation of alternative
suppliers and the dates by which
alternative vendors promised delivery,
backorder notices or unexpected delays,
descriptions of actions taken to expedite
delivery, and the current expected date
of delivery.
(E) If the reason for the extension is
that the equipment cannot be installed
without a process unit shutdown,
include supporting documentation
demonstrating that it is not practicable
to isolate the equipment and install the
monitoring instrument without a full
process unit shutdown. Include the date
of the most recent process unit
shutdown, the frequency of shutdowns
for this process unit, and the date of the
next planned shutdown during which
the monitoring equipment can be
installed. If there has been a shutdown
or if there is a planned process unit
shutdown between promulgation of this
part and April 1, 2010, include a
justification of why the equipment
could not be obtained and installed
during that shutdown.
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(F) A description of the specific
actions the facility will take to obtain
and install the equipment as soon as
reasonably feasible and the expected
date by which the equipment will be
installed and operating.
(iii) Approval criteria. To obtain
approval, the owner or operator must
demonstrate to the Administrator’s
satisfaction that it is not reasonably
feasible to acquire, install, and operate
a required piece of monitoring
equipment by April 1, 2010. The use of
best available methods will not be
approved beyond December 31, 2010.
(3) Abbreviated emissions report for
facilities containing only general
stationary fuel combustion sources. 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 meets the
conditions of § 98.2 (a)(3) may submit
an abbreviated GHG report for the
facility for GHGs emitted in 2010. The
abbreviated report must be submitted by
March 31, 2011. An owner or operator
that submits an abbreviated report must
submit a full GHG report according to
the requirements of paragraph (c) of this
section beginning in calendar year 2011.
The abbreviated facility report must
include the following information:
(i) Facility name and physical street
address including the city, state and zip
code.
(ii) The year and months covered by
the report.
(iii) Date of submittal.
(iv) Total facility GHG emissions
aggregated for all stationary fuel
combustion units calculated according
to any method specified in § 98.33(a)
and expressed in metric tons of CO2,
CH4, N2O, and CO2e.
(v) Any facility operating data or
process information used for the GHG
emission calculations.
(vi) A signed and dated certification
statement provided by the designated
representative of the owner or operator,
according to the requirements of
paragraph (e)(1) of this section.
(e) Emission calculations. In
preparing the GHG report, you must use
the calculation methodologies specified
in the relevant subparts, except as
specified in paragraph (d) of this
section. For each source category, you
must use the same calculation
methodology throughout a reporting
period unless you provide a written
explanation of why a change in
methodology was required.
(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
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(d)(3)(vi) of this section and any other
credible evidence, in conjunction with a
comprehensive review of the GHG
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 GHGs
under this part must keep records as
specified in this paragraph. Retain all
required records for at least 3 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 the Administrator, the
records required under this section must
be made available to EPA. Records may
be retained off site if the records are
readily available for expeditious
inspection and review. 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
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. These data include but
are not limited to the following
information in this paragraph (g)(2):
(i) The GHG emissions calculations
and methods used.
(ii) Analytical results for the
development of site-specific emissions
factors.
(iii) The results of all required
analyses for high heat value, carbon
content, and other required fuel or
feedstock parameters.
(iv) Any facility operating data or
process information used for the GHG
emission calculations.
(3) The annual GHG reports.
(4) Missing data computations. For
each missing data event, also retain a
record of the duration of the event,
actions taken to restore malfunctioning
monitoring equipment, the cause of the
event, and the actions taken to prevent
or minimize occurrence in the future.
(5) A written GHG Monitoring Plan.
(i) At a minimum, the GHG
Monitoring Plan shall include the
elements listed in this paragraph
(g)(5)(i).
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(1) Except as provided paragraphs
(i)(4) through (i)(6) of this section, flow
meters and other devices (e.g., belt
scales) that measure data used to
calculate GHG emissions shall be
calibrated prior to April 1, 2010 using
the procedures specified in this
paragraph and each relevant subpart of
this part. All measurement devices must
be calibrated according to the
manufacturer’s recommended
procedures, an appropriate industry
consensus standard, or a method
specified in a relevant subpart of this
part. All measurement devices shall be
calibrated to an accuracy of 5 percent.
For facilities and suppliers that become
subject to this part after April 1, 2010,
the initial calibration shall be conducted
on the date that data collection is
required to begin. Subsequent
calibrations shall be performed at the
frequency specified in each applicable
subpart.
(2) For flow meters, perform all
calibrations at measurement points that
are representative of normal operation
of the meter. Except for the orifice,
nozzle, and venturi flow meters
described in paragraph (i)(3) of this
section, calculate the calibration error at
each measurement point using Equation
A–2 of this section. The terms ‘‘R’’ and
‘‘A’’ in Equation A–2 must be expressed
in consistent units of measure (e.g.,
gallons/minute, ft 3/min). The
calibration error at each measurement
point shall not exceed 5.0 percent of the
reference value.
CE =
R −A
x 100
R
(Eq. A-2)
Where:
CE = Calibration error (%)
R = Reference value
A = Flow meter response to the reference
value
(3) For orifice, nozzle, and venturi
flow meters, the initial quality
assurance consists of in-situ calibration
of the differential pressure (delta-P),
total pressure, and temperature
transmitters. Calibrate each transmitter
at a zero point and at least one upscale
point. Fixed reference points, such as
the freezing point of water, may be used
for temperature transmitter calibrations.
Calculate the calibration error of each
transmitter at each measurement point,
using Equation A–3 of this subpart. The
terms ‘‘R’’, ‘‘A’’, and ‘‘FS’’ in Equation
A–3 of this subpart must be in
consistent units of measure (e.g.,
milliamperes, inches of water, psi,
degrees). For each transmitter, the CE
value at each measurement point shall
not exceed 2.0 percent of full-scale.
Alternatively, the results are acceptable
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if the sum of the calculated CE values
for the three transmitters at each
calibration level (i.e., at the zero level
and at each upscale level) does not
exceed 5.0 percent.
CE =
R −A
x 100
FS
(Eq. A-3)
Where:
CE = Calibration error (%)
R = Reference value
A = Transmitter response to the reference
value
FS = Full-scale value of the transmitter
(4) Fuel billing meters are exempted
from the calibration requirements of this
section, provided that the fuel supplier
and any unit combusting the fuel do not
have any common owners and are not
owned by subsidiaries or affiliates of the
same company.
(5) For a flow meter or other
measurement device that has been
previously calibrated in accordance
with this part, an initial calibration is
not required by the date specified in
paragraph (i)(1) of this section if, as of
the date required for the initial
calibration, the previous calibration is
still active (i.e., the device is not yet due
for recalibration because the time
interval between successive
calibrations, as required by this part, has
not elapsed).
(6) For units and processes that
operate continuously with infrequent
outages, it may not be possible to meet
the April 1, 2010 deadline for the initial
calibration of a flow meter or other
measurement device without removing
the device from service and shipping it
to a remote location, thereby disrupting
normal process operation. In such cases,
the owner or operator may postpone the
initial calibration until the next
scheduled maintenance outage, and may
similarly postpone the subsequent
recalibrations. Such postponements
shall be documented in the monitoring
plan that is required under § 98.3(g)(5).
§ 98.4 Authorization and responsibilities of
the designated representative.
(a) General. Except as provided under
paragraph (f) of this section, each
facility, and each supplier, that is
subject to this part, shall have one and
only one designated representative, who
shall be responsible for certifying,
signing, and submitting GHG emissions
reports and any other submissions for
such facility and supplier respectively
to the Administrator under this part. If
the facility is required under any other
part of title 40 of the Code of Federal
Regulations to submit to the
Administrator any other emission report
that is subject to any requirement in 40
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ER30OC09.002</MATH>
(A) Identification of positions of
responsibility (i.e., job titles) for
collection of the emissions data.
(B) Explanation of the processes and
methods used to collect the necessary
data for the GHG calculations.
(C) Description of the procedures and
methods that are used for quality
assurance, maintenance, and repair of
all continuous monitoring systems, flow
meters, and other instrumentation used
to provide data for the GHGs reported
under this part.
(ii) The GHG Monitoring Plan may
rely on references to existing corporate
documents (e.g., standard operating
procedures, quality assurance programs
under appendix F to 40 CFR part 60 or
appendix B to 40 CFR part 75, and other
documents) provided that the elements
required by paragraph (g)(5)(i) of this
section are easily recognizable.
(iii) The owner or operator shall
revise the GHG Monitoring Plan as
needed to reflect changes in production
processes, monitoring instrumentation,
and quality assurance procedures; or to
improve procedures for the maintenance
and repair of monitoring systems to
reduce the frequency of monitoring
equipment downtime.
(iv) Upon request by the
Administrator, the owner or operator
shall make all information that is
collected in conformance with the GHG
Monitoring Plan available for review
during an audit. Electronic storage of
the information in the plan is
permissible, provided that the
information can be made available in
hard copy upon request during an audit.
(6) The results of all required
certification and quality assurance tests
of continuous monitoring systems, fuel
flow meters, and other instrumentation
used to provide data for the GHGs
reported under this part.
(7) Maintenance records for all
continuous monitoring systems, flow
meters, and other instrumentation used
to provide data for the GHGs reported
under this part.
(h) Annual GHG report revisions. The
owner or operator shall submit a revised
report within 45 days of discovering or
being notified by EPA of errors in an
annual GHG report. The revised report
must correct all identified errors. The
owner or operator shall retain
documentation for 3 years to support
any revisions made to an annual GHG
report.
(i) Calibration accuracy requirements.
The owner or operator of a facility or
supplier that is subject to the
requirements of this part must meet the
calibration accuracy requirements of
this paragraph (i).
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CFR part 75, the same individual shall
be the designated representative
responsible for certifying, signing, and
submitting the GHG emissions reports
and all such other emissions reports
under this part.
(b) Authorization of a designated
representative. The designated
representative of the facility or supplier
shall be an individual selected by an
agreement binding on the owners and
operators of such facility or supplier
and shall act in accordance with the
certification statement in paragraph
(i)(4)(iv) of this section.
(c) Responsibility of the designated
representative. Upon receipt by the
Administrator of a complete certificate
of representation under this section for
a facility or supplier, the designated
representative identified in such
certificate of representation shall
represent and, by his or her
representations, actions, inactions, or
submissions, legally bind each owner
and operator of such facility or supplier
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 for
a facility or supplier will be accepted
until the Administrator has received a
complete certificate of representation
under this section for a designated
representative of the facility or supplier.
Such certificate of representation shall
be submitted at least 60 days before the
deadline for submission of the facility’s
or supplier’s initial emission report
under this part.
(e) Certification of the GHG emissions
report. Each GHG emission report and
any other submission under this part for
a facility or supplier shall be certified,
signed, and submitted by the designated
representative or any alternate
designated representative of the facility
or supplier in accordance with this
section and § 3.10 of this chapter.
(1) Each such submission shall
include the following certification
statement signed by the designated
representative or any alternate
designated representative: ‘‘I am
authorized to make this submission on
behalf of the owners and operators of
the facility or supplier, as applicable, 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
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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 for a facility or supplier
under this part only if the submission is
certified, signed, and submitted in
accordance with this section.
(f) Alternate designated
representative. A certificate of
representation under this section for a
facility or supplier may designate one
alternate designated representative, who
shall be an individual selected by an
agreement binding on the owners and
operators, and may act on behalf of the
designated representative, of such
facility or supplier. 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 for a
facility or supplier identifying an
alternate designated representative.
(i) The alternate designated
representative may act on behalf of the
designated representative for such
facility or supplier.
(ii) 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 in this part, 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 identified in a complete
certificate of representation under this
section for a facility or supplier received
by the Administrator may be changed at
any time upon receipt by the
Administrator of another later signed,
complete certificate of representation
under this section for the facility or
supplier. Notwithstanding any such
change, all representations, actions,
inactions, and submissions by the
previous designated representative or
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the previous alternate designated
representative of the facility or supplier
before the time and date when the
Administrator receives such later signed
certificate of representation shall be
binding on the new designated
representative and the owners and
operators of the facility or supplier.
(h) Changes in owners and operators.
In the event an owner or operator of the
facility or supplier is not included in
the list of owners and operators in the
certificate of representation under this
section for the facility or supplier, such
owner or operator shall be deemed to be
subject to and bound by the certificate
of representation, the representations,
actions, inactions, and submissions of
the designated representative and any
alternate designated representative of
the facility or supplier, as if the owner
or operator were included in such list.
Within 90 days after any change in the
owners and operators of the facility or
supplier (including the addition of a
new owner or operator), the designated
representative or any alternate
designated representative shall submit a
certificate of representation that is
complete under this section except that
such list shall be amended to reflect the
change. If the designated representative
or alternate designated representative
determines at any time that an owner or
operator of the facility or supplier is not
included in such list and such exclusion
is not the result of a change in the
owners and operators, the designated
representative or any alternate
designated representative shall submit,
within 90 days of making such
determination, a certificate of
representation that is complete under
this section except that such list shall be
amended to include such owner or
operator.
(i) Certificate of representation. A
certificate of representation shall be
complete if it includes the following
elements in a format prescribed by the
Administrator in accordance with this
section:
(1) Identification of the facility or
supplier 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 supplier identified in
paragraph (i)(1) of this section, provided
that, if the list includes the operators of
the facility or supplier and the owners
with control of the facility or supplier,
the failure to include any other owners
shall not make the certificate of
representation incomplete.
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(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 of the facility or supplier,
as applicable.’’
(ii) ‘‘I certify that I have all the
necessary authority to carry out my
duties and responsibilities under 40
CFR part 98 on behalf of the owners and
operators of the facility or supplier, as
applicable, 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 of the facility or supplier, as
applicable, shall be bound by any order
issued to me by the Administrator or a
court regarding the facility or supplier.’’
(iv) ‘‘If there are multiple owners and
operators of the facility or supplier, as
applicable, 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 each owner and
operator of the facility or supplier.’’
(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 for a facility or supplier has
been received, the Administrator will
rely on the certificate of representation
unless and until a later signed, complete
certificate of representation under this
section for the facility or supplier 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
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17:39 Oct 29, 2009
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representative or alternate designated
representative, or the finality of any
decision or order by the Administrator
under this part.
(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.
(m) Delegation by designated
representative and alternate designated
representative.
(1) A designated representative or an
alternate designated representative may
delegate his or her own authority, to one
or more individuals, to submit an
electronic submission to the
Administrator provided for or required
under this part, except for a submission
under this paragraph.
(2) In order to delegate his or her own
authority, to one or more individuals, to
submit an electronic submission to the
Administrator in accordance with
paragraph (m)(1) of this section, the
designated representative or alternate
designated representative must submit
electronically to the Administrator a
notice of delegation, in a format
prescribed by the Administrator, that
includes the following elements:
(i) The name, address, e-mail address
(if any), telephone number, and
facsimile transmission number (if any)
of such designated representative or
alternate designated representative.
(ii) The name, address, e-mail
address, telephone number, and
facsimile transmission number (if any)
of each such individual (referred to as
an ‘‘agent’’).
(iii) For each such individual, a list of
the type or types of electronic
submissions under paragraph (m)(1) of
this section for which authority is
delegated to him or her.
(iv) For each type of electronic
submission listed in accordance with
paragraph (m)(2)(iii) of this section, the
facility or supplier for which the
electronic submission may be made.
(v) The following certification
statements by such designated
representative or alternate designated
representative:
(A) ‘‘I agree that any electronic
submission to the Administrator that is
by an agent identified in this notice of
delegation and of a type listed, and for
a facility or supplier designated, for
such agent in this notice of delegation
and that is made when I am a
designated representative or alternate
designated representative, as applicable,
and before this notice of delegation is
superseded by another notice of
delegation under § 98.4(m)(3) shall be
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56383
deemed to be an electronic submission
certified, signed, and submitted by me.’’
(B) ‘‘Until this notice of delegation is
superseded by a later signed notice of
delegation under § 98.4(m)(3), I agree to
maintain an e-mail account and to
notify the Administrator immediately of
any change in my e-mail address unless
all delegation of authority by me under
§ 98.4(m) is terminated.’’
(vi) The signature of such designated
representative or alternate designated
representative and the date signed.
(3) A notice of delegation submitted
in accordance with paragraph (m)(2) of
this section shall be effective, with
regard to the designated representative
or alternate designated representative
identified in such notice, upon receipt
of such notice by the Administrator and
until receipt by the Administrator of
another such notice that was signed
later by such designated representative
or alternate designated representative,
as applicable. The later signed notice of
delegation may replace any previously
identified agent, add a new agent, or
eliminate entirely any delegation of
authority.
(4) Any electronic submission covered
by the certification in paragraph
(m)(2)(iv)(A) of this section and made in
accordance with a notice of delegation
effective under paragraph (m)(3) of this
section shall be deemed to be an
electronic submission certified, signed,
and submitted by the designated
representative or alternate designated
representative submitting such notice of
delegation.
§ 98.5
How is the report submitted?
Each GHG report and certificate of
representation for a facility or supplier
must be submitted electronically in
accordance with the requirements of
§ 98.4 and in a format specified by the
Administrator.
§ 98.6
Definitions.
All terms used in this part shall have
the same meaning given in the Clean Air
Act and in this section.
Accuracy of a measurement at a
specified level (e.g., one percent of full
scale or one percent of the value
measured) means that the mean of
repeat measurements made by a device
or technique are within 95 percent of
the range bounded by the true value
plus or minus the specified level.
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.
Administrator means the
Administrator of the United States
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Environmental Protection Agency or the
Administrator’s authorized
representative.
AGA means the American Gas
Association
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 system
where wastes are collected and
anaerobically digested in large
containment vessels or covered lagoons.
Anaerobic digesters stabilize waste by
the microbial reduction of complex
organic compounds to CO2 and CH4,
which is captured and may be flared or
used as fuel. Anaerobic digestion
systems, include but are not limited to
covered lagoon, complete mix, plug
flow, and fixed film digesters.
Anaerobic lagoon means a type of
liquid storage system component, either
at manure management system or a
wastewater treatment system, that is
designed and operated to stabilize
wastes using anaerobic microbial
processes. Anaerobic lagoons may be
designed for combined stabilization and
storage with varying lengths of retention
time (up to a year or greater), depending
on the climate region, the volatile solids
loading rate, and other operational
factors.
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.
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.
ASABE means the American Society
of Agricultural and Biological
Engineers.
ASME means the American Society of
Mechanical Engineers.
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ASTM means the American Society of
Testing and Materials.
Asphalt means a dark brown-to-black
cement-like material obtained by
petroleum processing and containing
bitumens as the predominant
component. It includes crude asphalt as
well as the following finished products:
cements, fluxes, the asphalt content of
emulsions (exclusive of water), and
petroleum distillates blended with
asphalt to make cutback asphalts.
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,
Standard Specification for Aviation
Gasolines (incorporated by reference,
see § 98.7).
B0 means the maximum CH4
producing capacity of a waste stream, kg
CH4/kg COD.
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.
bbl means barrel.
Biodiesel means a mono-akyl ester
derived from biomass and conforming to
ASTM D6751–08, Standard
Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels.
Biogenic CO2 means carbon dioxide
emissions generated as the result of
biomass combustion from combustion
units for which emission calculations
are required by an applicable part 98
subpart.
Biomass means non-fossilized and
biodegradable organic material
originating from plants, animals or
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
plant and is used for the production of
molten iron from iron ore pellets and
other iron bearing materials.
Blendstocks are petroleum products
used for blending or compounding into
finished motor gasoline. These include
RBOB (reformulated blendstock for
oxygenate blending) and CBOB
(conventional blendstock for oxygenate
blending), but exclude oxygenates,
butane, and pentanes plus.
Blendstocks—Others are products
used for blending or compounding into
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finished motor gasoline that are not
defined elsewhere. Excludes Gasoline
Treated as Blendstock (GTAB), Diesel
Treated as Blendstock (DTAB),
conventional blendstock for oxygenate
blending (CBOB), reformulated
blendstock for oxygenate blending
(RBOB), oxygenates (e.g. fuel ethanol
and methyl tertiary butyl ether), butane,
and pentanes plus.
Blowdown mean the act of emptying
or depressuring a vessel. This may also
refer to the discarded material such as
blowdown water from a boiler or
cooling tower.
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 and CO2 suppliers, means the
transfer of a product inside containers,
including but not limited to tanks,
cylinders, drums, and pressure vessels.
Bulk natural gas liquid or NGL refers
to mixtures of hydrocarbons that have
been separated from natural gas as
liquids through the process of
absorption, condensation, adsorption, or
other methods at lease separators and
field facilities. Generally, such liquids
consist of ethane, propane, butanes, and
pentanes plus. Bulk NGL is sold to
fractionators or to refineries and
petrochemical plants where the
fractionation takes place.
Butane, or n-Butane, is a paraffinic
straight-chain hydrocarbon with
molecular formula C4H10.
Butylene, or n-Butylene, is an olefinic
straight-chain hydrocarbon with
molecular formula C4H8.
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.
Calcination means the process of
thermally treating minerals to
decompose carbonates from ore.
Calculation methodology means a
methodology prescribed under the
section ‘‘Calculating GHG Emissions’’ in
any subpart of part 98.
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
greenhouse gas, and is calculated using
Equation A–1 of this subpart.
Carbon dioxide production well
means any hole drilled in the earth for
the primary purpose of extracting
carbon dioxide from a geologic
formation or group of formations which
contain deposits of carbon dioxide.
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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
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 if they
otherwise meet the definition.
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 percent of
total mass that carbon represents 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.
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
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fluid catalytic cracking units (FCCU),
and moving bed systems, which are also
referred to as thermal catalytic cracking
units. The unit includes the riser,
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.
Deep bedding systems for cattle swine
means a manure management system in
which, 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-Summer (conventional
blendstock for oxygenate blending)
means a petroleum product which,
when blended with a specified type and
percentage of oxygenate, meets the
definition of Conventional-Summer.
CBOB-Winter (conventional
blendstock for oxygenate blending)
means a petroleum product which,
when blended with a specified type and
percentage of oxygenate, meets the
definition of Conventional-Winter.
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.
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.
City gate means a location at which
natural gas ownership or control passes
from one party to another, neither of
which is the ultimate consumer. In this
rule, in keeping with common practice,
the term refers to a point or measuring
station at which a local gas distribution
utility receives gas from a natural gas
pipeline company or transmission
system. Meters at the city gate station
measure the flow of natural gas into the
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local distribution company system and
typically are used to measure local
distribution company system sendout to
customers.
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 (incorporated by
reference, see § 98.7).
COD means the chemical oxygen
demand as determined using methods
specified pursuant to 40 CFR part 136.
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.
Commercial applications means
executing a commercial transaction
subject to a contract. A commercial
application includes transferring
custody of a product from one facility to
another if it otherwise meets the
definition.
Company records means, in reference
to the amount of fuel consumed by a
stationary combustion unit (or by a
group of such units), a complete record
of the methods used, the measurements
made, and the calculations performed to
quantify fuel usage. Company records
may include, but are not limited to,
direct measurements of fuel
consumption by gravimetric or
volumetric means, tank drop
measurements, and calculated values of
fuel usage obtained by measuring
auxiliary parameters such as steam
generation or unit operating hours. Fuel
billing records obtained from the fuel
supplier qualify as company records.
Connector means 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 part.
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).
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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
operates continuously except during
periods of maintenance, malfunction,
control device installation,
reconstruction, or rebuilding.
Conventional-Summer refers to
finished gasoline formulated for use in
motor vehicles, the composition and
properties of which do not meet the
requirements of the reformulated
gasoline regulations promulgated by the
U.S. Environmental Protection Agency
under 40 CFR 80.40, but which meet
summer RVP standards required under
40 CFR 80.27 or as specified by the
state. Note: This category excludes
conventional gasoline for oxygenate
blending (CBOB) as well as other
blendstock.
Conventional-Winter refers to finished
gasoline formulated for use in motor
vehicles, the composition and
properties of which do not meet the
requirements of the reformulated
gasoline regulations promulgated by the
U.S. Environmental Protection Agency
under 40 CFR 80.40 or the summer RVP
standards required under 40 CFR 80.27
or as specified by the state. Note: This
category excludes conventional
blendstock for oxygenate blending
(CBOB) as well as other blendstock.
Crude oil means a mixture of
hydrocarbons that exists in the liquid
phase in the underground reservoir and
remains liquid at atmospheric pressure
after passing through surface separating
facilities.
Daily spread means a manure
management system component in
which manure is routinely removed
from a confinement facility and is
applied to cropland or pasture within 24
hours of excretion.
Day means any consistently
designated 24 hour period during which
an emission unit is operated.
Degradable organic carbon (DOC)
means the fraction of the total mass of
a waste material that can be biologically
degraded.
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. A
delayed coking unit consists of the coke
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drums and ancillary equipment
associated with a single fractionator.
Density means the mass contained in
a given unit volume (mass/volume).
Destruction means:
(1) With respect to landfills and
manure management, 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.
(2) 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. Destruction efficiency, or flaring
destruction efficiency, refers to the
fraction of the gas that leaves the flare
partially or fully oxidized. The
Destruction Efficiency is expressed in
Equation A–2 of this section:
DE = 1 −
tCO2eOUT
tCO2eIN
(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
Diesel—Other is any distillate fuel oil
not defined elsewhere, including Diesel
Treated as Blendstock (DTAB).
DIPE (diisopropyl ether,
(CH3)2CHOCH(CH3)2) is an ether as
described in ‘‘Oxygenates.’’
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
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and hydrotreating process units. The
generic term distillate fuel oil includes
kerosene, diesel fuels (Diesel Fuels No.
1, No. 2, and No. 4), and fuel oils (Fuel
Oils No. 1, No. 2, and No. 4).
Distillate Fuel No. 1 has a maximum
distillation temperature of 550 °F at the
90 percent recovery point and a
minimum flash point of 100 °F and
includes fuels commonly known as
Diesel Fuel No. 1 and Fuel Oil No. 1,
but excludes kerosene. This fuel is
further subdivided into categories of
sulfur content: High Sulfur (greater than
500 ppm), Low Sulfur (less than or
equal to 500 ppm and greater than 15
ppm), and Ultra Low Sulfur (less than
or equal to 15 ppm).
Distillate Fuel No. 2 has a minimum
and maximum distillation temperature
of 540 °F and 640 °F at the 90 percent
recovery point, respectively, and
includes fuels commonly known as
Diesel Fuel No. 2 and Fuel Oil No. 2.
This fuel is further subdivided into
categories of sulfur content: High Sulfur
(greater than 500 ppm), Low Sulfur (less
than or equal to 500 ppm and greater
than 15 ppm), and Ultra Low Sulfur
(less than or equal to 15 ppm).
Distillate Fuel No. 4 is a distillate fuel
oil made by blending distillate fuel oil
and residual fuel oil, with a minimum
flash point of 131 °F.
DOCf means the fraction of DOC that
actually decomposes under the
(presumably anaerobic) conditions
within the landfill.
Dry lot means a manure management
system component consisting of 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.
Electrothermic furnace means a
furnace that heats the charged materials
with electric arcs from carbon
electrodes.
Emergency generator means a
stationary combustion device, such as a
reciprocating internal combustion
engine or turbine 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
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facility. An emergency generator
operates only during emergency
situations, for training of personnel
under simulated emergency conditions,
as part of emergency demand response
procedures, or for standard performance
testing procedures as required by law or
by the generator manufacturer. A
generator that serves as a back-up power
source under 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
generator.
Emergency equipment means any
auxiliary fossil fuel-powered
equipment, such as a fire pump, that is
used only in emergency situations.
ETBE (ethyl tertiary butyl ether,
(CH3)3COC2H) is an ether as described
in ‘‘Oxygenates.’’
Ethane is a paraffinic hydrocarbon
with molecular formula C2H6.
Ethanol is an anhydrous alcohol with
molecular formula C2H5OH.
Ethylene is an olefinic hydrocarbon
with molecular formula C2H4.
Ex refinery gate means the point at
which a petroleum 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 any
such transport on behalf of the United
States military including foreign
military sales under the Arms Export
Control Act.
Exporter means any person, company
or organization of record that transfers
for sale or for other benefit, domestic
products from the United States to
another country or to an affiliate in
another country, excluding any such
transfers on behalf of the United States
military or military purposes including
foreign military sales under the Arms
Export Control Act. An exporter is not
the entity merely transporting the
domestic products, rather an exporter is
the entity deriving the principal benefit
from the transaction.
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
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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.
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.
Flat glass means glass made of sodalime recipe and produced into
continuous flat sheets and other
products listed in NAICS 327211.
Flowmeter means a device that
measures the mass or volumetric rate of
flow of a gas, liquid, or solid moving
through an open or closed conduit (e.g.
flowmeters include, but are not limited
to, rotameters, turbine meters, coriolis
meters, orifice meters, ultra-sonic
flowmeters, and vortex flowmeters).
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
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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
and substances with vapor pressures of
less than 1 mm of Hg absolute at 25
degrees C. With these exceptions,
‘‘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, including for example,
consumer products that are derived
from such materials and are combusted.
Fossil fuel-fired means powered by
combustion of fossil fuel, alone or in
combination with any other fuel,
regardless of the percentage of fossil fuel
consumed.
Fractionators means plants that
produce fractionated natural gas liquids
(NGLs) extracted from produced natural
gas and separate the NGLs individual
component products: ethane, propane,
butanes and pentane-plus (C5+). Plants
that only process natural gas but do not
fractionate NGLs further into
component products are not considered
fractionators. Some fractionators do not
process production gas, but instead
fractionate bulk NGLs received from
natural gas processors. Some
fractionators both process natural gas
and fractionate bulk NGLs received from
other plants.
Fuel means solid, liquid or gaseous
combustible material.
Fuel 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.
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
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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-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.
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 or liquid raw material into a gas.
Gasoline—Other is any gasoline that
is not defined elsewhere, including
GTAB (gasoline treated as blendstock).
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.
Glass produced means the weight of
glass exiting a glass melting furnace.
Global warming potential or GWP
means the ratio of the time-integrated
radiative forcing from the instantaneous
release of one kilogram of a trace
substance relative to that of one
kilogram- 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),
perfluorocarbons (PFCs), and other
fluorinated greenhouse gases as defined
in this section.
GTBA (gasoline-grade tertiary butyl
alcohol, (CH3)3COH), or t-butanol, is an
alcohol as described in ‘‘Oxygenates.’’
Heavy Gas Oils are petroleum
distillates with an approximate boiling
range from 651 °F to 1,000 °F.
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.
Hydrofluorocarbons or HFCs means a
class of GHGs consisting of hydrogen,
fluorine, and carbon.
Import means, to land on, bring into,
or introduce into, any place subject to
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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.
(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.
(4) Bringing fluorinated GHGs or
nitrous into U.S. jurisdiction
exclusively for U. S. military purposes.
Importer means any person, company,
or organization of record that for any
reason brings a product into the United
States from a foreign country, excluding
introduction into U.S. jurisdiction
exclusively for United States military
purposes. An importer is the person,
company, or organization primarily
liable for the payment of any duties on
the merchandise or an authorized agent
acting on their behalf. The term
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.
Industrial greenhouse gases means
nitrous oxide or any fluorinated
greenhouse gas.
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.
Isobutane is a paraffinic branch chain
hydrocarbon with molecular formula
C4H10.
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Isobutylene is an olefinic branch
chain hydrocarbon with molecular
formula C4H8.
Kerosene is a light petroleum
distillate with a maximum distillation
temperature of 400 °F at the 10-percent
recovery point, a final maximum boiling
point of 572 °F, a minimum flash point
of 100 °F, and a maximum freezing
point of ¥22 °F. Included are No. 1–K
and No. 2–K, distinguished by
maximum sulfur content (0.04 and 0.30
percent of total mass, respectively), as
well as all other grades of kerosene
called range or stove oil. Excluded is
kerosene-type jet fuel (see definition
herein).
Kerosene-type jet fuel means a
kerosene-based product used in
commercial and military turbojet and
turboprop aircraft. The product has a
maximum distillation temperature of
400 °F at the 10 percent recovery point
and a final maximum boiling point of
572 °F. Included are Jet A, Jet A–1,
JP–5, and JP–8.
Kiln means an oven, furnace, or
heated enclosure used for thermally
processing a mineral or mineral-based
substance.
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 40
CFR 257.2.
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.
Liquid/Slurry means a manure
management component in which
manure is stored as excreted or with
some minimal addition of water to
facilitate handling and is stored in
either tanks or earthen ponds, usually
for periods less than one year.
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
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pulp mills to replace chemicals lost in
the process.
Manure composting means the
biological oxidation of a solid waste
including manure usually with bedding
or another organic carbon source
typically at thermophilic temperatures
produced by microbial heat production.
There are four types of composting
employed for manure management:
Static, in vessel, intensive windrow and
passive windrow. Static composting
typically occurs in an enclosed channel,
with forced aeration and continuous
mixing. In vessel composting occurs in
piles with forced aeration but no
mixing. Intensive windrow composting
occurs in windrows with regular turning
for mixing and aeration. Passive
windrow composting occurs in
windrows with infrequent turning for
mixing and aeration.
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 charging rate of a
municipal waste combustor unit
expressed in tons per day of municipal
solid waste combusted, calculated
according to the procedures under 40
CFR 60.58b(j).
Mcf means thousand cubic feet.
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.
Methanol (CH3OH) is an alcohol as
described in ‘‘Oxygenates.’’
Midgrade gasoline has an octane
rating greater than or equal to 88 and
less than or equal to 90. This definition
applies to the midgrade categories of
Conventional-Summer, ConventionalWinter, Reformulated-Summer, and
Reformulated-Winter. For midgrade
categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the
expected octane rating of the finished
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gasoline after oxygenate has been added
to the RBOB or CBOB.
Miscellaneous products include all
refined petroleum products not defined
elsewhere. It includes, but is not limited
to, naphtha-type jet fuel (Jet B and JP–
4), petrolatum lube refining by-products
(aromatic extracts and tars), absorption
oils, ram-jet fuel, petroleum rocket fuels,
synthetic natural gas feedstocks, waste
feedstocks, and specialty oils. It
excludes organic waste sludges, tank
bottoms, spent catalysts, and sulfuric
acid.
MMBtu means million British thermal
units.
Motor gasoline (finished) means a
complex mixture of volatile
hydrocarbons, with or without
additives, suitably blended to be used in
spark ignition engines. 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.
Mscf means million standard cubic
feet.
MTBE (methyl tertiary butyl ether,
(CH3)3COCH3) is an ether as described
in ‘‘Oxygenates.’’
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 (40 CFR 257.2) 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, public roadways, or other
public right-of-ways. 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.
Naphthas (< 401 °F) is a generic term
applied to a petroleum fraction with an
approximate boiling range between 122
°F and 400 °F. The naphtha fraction of
crude oil is the raw material for gasoline
and is composed largely of paraffinic
hydrocarbons.
Natural gas means a naturally
occurring mixture of hydrocarbon and
non-hydrocarbon gases found in
geologic formations beneath the earth’s
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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 liquids (NGLs) means
those hydrocarbons in natural gas that
are separated from the gas as liquids
through the process of absorption,
condensation, adsorption, or other
methods at lease separators and field
facilities. Generally, such liquids consist
of ethane, propane, butanes, and
pentanes plus. Bulk NGLs refers to
mixtures of NGLs that are sold or
delivered as undifferentiated product
from natural gas processing plants.
Natural gasoline means a mixture of
liquid hydrocarbons (mostly pentanes
and heavier hydrocarbons) extracted
from natural gas. It includes isopentane.
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 any
petroleum product or natural gas liquid
that enters the refinery as a feedstock to
be further refined or otherwise used on
site.
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.
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 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.
Operational change means, for
purposes of § 98.3(b), a change in the
type of feedstock or fuel used, a change
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in operating hours, or a change in
process production rate.
Operator means any person who
operates or supervises a facility or
supplier.
Other oils (> 401 °F) are oils with a
boiling range equal to or greater than
401 °F that are generally intended for
use as a petrochemical feedstock and are
not defined elsewhere.
Owner means any person who has
legal or equitable title to, has a
leasehold interest in, or control of a
facility or supplier, except a person
whose legal or equitable title to or
leasehold interest in the facility or
supplier arises solely because the
person is a limited partner in a
partnership that has legal or equitable
title to, has a leasehold interest in, or
control of the facility or supplier shall
not be considered an ‘‘owner’’ of the
facility or supplier.
Oxygenates means substances which,
when added to gasoline, increase the
oxygen content of the gasoline. Common
oxygenates are ethanol, methyl tertiary
butyl ether (MTBE), ethyl tertiary butyl
ether (ETBE), tertiary amyl methyl ether
(TAME), diisopropyl ether (DIPE), and
methanol.
Pasture/Range/Paddock means the
manure from pasture and range grazing
animals is allowed to lie as deposited,
and is not managed.
Pentanes plus, or C5+, is a mixture of
hydrocarbons that is a liquid at ambient
temperature and pressure, and consists
mostly of pentanes (five carbon chain)
and higher carbon number
hydrocarbons. Pentanes plus includes,
but is not limited to, normal pentane,
isopentane, hexanes-plus (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,
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
naphthas 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), has
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low ash content, and may be used as a
feedstock in coke ovens. This product is
also known as marketable coke or
catalyst coke.
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, but not including plastics or
plastic products. 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
waxes.
Pit storage below animal confinement
(deep pits) means the collection and
storage of manure typically below a
slatted floor in an enclosed animal
confinement facility. This usually
occurs with little or no added water for
periods less than one year.
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 any one of the following
conditions exists:
(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
circumvent the portable residence time
requirements of this definition.
Poultry manure with litter means a
manure management system component
that is similar to cattle and swine deep
bedding except usually not combined
with a dry lot or pasture. The system is
typically used for poultry breeder flocks
and for the production of meat type
chickens (broiler) and other fowl.
Poultry manure without litter means a
manure management system component
that 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
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manure composting when designed and
operated properly.
Precision of a measurement at a
specified level (e.g., one percent of full
scale or one percent of the value
measured) means that 95 percent of
repeat measurements made by a device
or technique are within the range
bounded by the mean of the
measurements plus or minus the
specified level.
Premium grade gasoline is gasoline
having an antiknock index, i.e., octane
rating, greater than 90. This definition
applies to the premium grade categories
of Conventional-Summer, ConventionalWinter, Reformulated-Summer, and
Reformulated-Winter. For premium
grade categories of RBOB-Summer,
RBOB-Winter, CBOB-Summer, and
CBOB-Winter, this definition refers to
the expected octane rating of the
finished gasoline after oxygenate has
been added to the RBOB or CBOB.
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 is but 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.
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 unit means the equipment
assembled and connected by pipes and
ducts to process raw materials and to
manufacture either a final product or an
intermediate used in the onsite
production of other products. The
process unit also includes the
purification of recovered byproducts.
Process vent means means a gas
stream that: Is discharged through a
conveyance to the atmosphere either
directly or after passing through a
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control device; originates from a unit
operation, including but not limited to
reactors (including reformers, crackers,
and furnaces, and separation equipment
for products and recovered byproducts);
and contains or has the potential to
contain GHG that is generated in the
process. Process vent does not include
safety device discharges, equipment
leaks, gas streams routed to a fuel gas
system or to a flare, discharges from
storage tanks.
Propane is a paraffinic hydrocarbon
with molecular formula C3H8.
Propylene is an olefinic hydrocarbon
with molecular formula C3H6.
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.
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,
a raw material dryer. The raw mill also
includes the air separator associated
with the raw mill.
RBOB-Summer (reformulated
blendstock for oxygenate blending)
means a petroleum product which,
when blended with a specified type and
percentage of oxygenate, meets the
definition of Reformulated-Summer.
RBOB-Winter (reformulated
blendstock for oxygenate blending)
means a petroleum product which,
when blended with a specified type and
percentage of oxygenate, meets the
definition of Reformulated-Winter.
Reformulated-Summer refers to
finished gasoline formulated for use in
motor vehicles, the composition and
properties of which meet the
requirements of the reformulated
gasoline regulations promulgated by the
U.S. Environmental Protection Agency
under 40 CFR 80.40 and 40 CFR 80.41,
and summer RVP standards required
under 40 CFR 80.27 or as specified by
the state. Reformulated gasoline
excludes Reformulated Blendstock for
Oxygenate Blending (RBOB) as well as
other blendstock.
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Reformulated-Winter refers to
finished gasoline formulated for use in
motor vehicles, the composition and
properties of which meet the
requirements of the reformulated
gasoline regulations promulgated by the
U.S. Environmental Protection Agency
under 40 CFR 80.40 and 40 CFR 80.41,
but which do not meet summer RVP
standards required under 40 CFR 80.27
or as specified by the state. Note: This
category includes Oxygenated Fuels
Program Reformulated Gasoline (OPRG).
Reformulated gasoline excludes
Reformulated Blendstock for Oxygenate
Blending (RBOB) as well as other
blendstock.
Regular grade gasoline is gasoline
having an antiknock index, i.e., octane
rating, greater than or equal to 85 and
less than 88. This definition applies to
the regular grade categories of
Conventional-Summer, ConventionalWinter, Reformulated-Summer, and
Reformulated-Winter. For regular grade
categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the
expected octane rating of the finished
gasoline after oxygenate has been added
to the RBOB or CBOB.
Rendered animal fat, or tallow, means
fats extracted from animals which are
generally used as a feedstock in making
biodiesel.
Research and development means
those activities conducted in process
units or at laboratory bench-scale
settings whose purpose is to conduct
research and development for new
processes, technologies, or products and
whose purpose is not for the
manufacture of products for commercial
sale, except in a de minimis manner.
Residual Fuel Oil No. 5 (Navy
Special) is a classification for the
heavier fuel oil generally used in steam
powered vessels in government service
and inshore power plants. It has a
minimum flash point of 131 °F.
Residual Fuel Oil No. 6 (a.k.a. Bunker
C) is a classification for the heavier fuel
oil generally used for the production of
electric power, space heating, vessel
bunkering and various industrial
purposes. It has a minimum flash point
of 140 °F.
Residuum is residue from crude oil
after distilling off all but the heaviest
components, with a boiling range
greater than 1,000 °F.
Road oil is any heavy petroleum oil,
including residual asphaltic oil used as
a dust palliative and surface treatment
on roads and highways. It is generally
produced in six grades, from 0, the most
liquid, to 5, the most viscous.
Rotary lime kiln means a unit with an
inclined rotating drum that is used to
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produce a lime product from limestone
by calcination.
Safety device means a closure device
such as a pressure relief valve, frangible
disc, fusible plug, or any other type of
device which functions exclusively to
prevent physical damage or permanent
deformation to a unit or its air emission
control equipment by venting gases or
vapors directly to the atmosphere
during unsafe conditions resulting from
an unplanned, accidental, or emergency
event. A safety device is not used for
routine venting of gases or vapors from
the vapor headspace underneath a cover
such as during filling of the unit or to
adjust the pressure in response to
normal daily diurnal ambient
temperature fluctuations. A safety
device is designed to remain in a closed
position during normal operations and
open only when the internal pressure,
or another relevant parameter, exceeds
the device threshold setting applicable
to the air emission control equipment as
determined by the owner or operator
based on manufacturer
recommendations, applicable
regulations, fire protection and
prevention codes and practices, or other
requirements for the safe handling of
flammable, combustible, explosive,
reactive, or hazardous materials.
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.
Sendout means, in the context of a
local distribution company, the total
deliveries of natural gas to customers
over a specified time interval (typically
hour, day, month, or year). Sendout is
the sum of gas received through the city
gate, gas withdrawn from on-system
storage or peak shaving plants, and gas
produced and delivered into the
distribution system; and is net of any
natural gas injected into on-system
storage. It comprises gas sales,
exchange, deliveries, gas used by
company, and unaccounted for gas.
Sendout is measured at the city gate
station, and other on-system receipt
points from storage, peak shaving, and
production.
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.
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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.
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.
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 gas means any gas that contains
significant concentrations of hydrogen
sulfide. Sour gas may include untreated
fuel gas, amine stripper off-gas, or sour
water stripper gas.
Special naphthas means all finished
products with the naphtha boiling range
(290 ° to 470 °F) that are generally used
as paint thinners, cleaners or solvents.
These products are refined to a specified
flash point. Special naphthas include all
commercial hexane and cleaning
solvents conforming to ASTM
Specification D1836–07, Standard
Specification for Commercial Hexanes,
and D235–02 (Reapproved 2007),
Standard Specification for Mineral
Spirits (Petroleum Spirits) (Hydrocarbon
Dry Cleaning Solvent), respectively.
Naphthas to be blended or marketed as
motor gasoline or aviation gasoline, or
that are to be used as petrochemical and
synthetic natural gas (SNG) feedstocks
are excluded.
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
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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
68 degrees Fahrenheit and 14.7 pounds
per square inch absolute.
Steam reforming means a catalytic
process that involves a reaction between
natural gas or other light hydrocarbons
and steam. The result is a mixture of
hydrogen, carbon monoxide, carbon
dioxide, and water.
Still gas means any form or mixture
of gases produced in refineries by
distillation, cracking, reforming, and
other processes. The principal
constituents are methane, ethane,
ethylene, normal butane, butylene,
propane, and propylene.
Storage tank means a vessel
(excluding sumps) that is designed to
contain an accumulation of crude oil,
condensate, intermediate hydrocarbon
liquids, or produced water and that is
constructed entirely of non-earthen
materials (e.g., wood, concrete, steel,
plastic) that provide structural support.
Sulfur recovery plant means all
process units which recover sulfur or
produce sulfuric acid from hydrogen
sulfide (H2S) and/or sulfur dioxide
(SO2) from a common source of sour gas
at a petroleum refinery. The sulfur
recovery plant also includes sulfur pits
used to store the recovered sulfur
product, but it does not include
secondary sulfur storage vessels or
loading facilities downstream of the
sulfur pits. For example, a Claus sulfur
recovery plant includes: Reactor furnace
and waste heat boiler, catalytic reactors,
sulfur pits, and, if present, oxidation or
reduction control systems, or
incinerator, thermal oxidizer, or similar
combustion device. Multiple sulfur
recovery units are a single sulfur
recovery plant only when the units
share the same source of sour gas. Sulfur
recovery units that receive source gas
from completely segregated sour gas
treatment systems are separate sulfur
recovery plants.
Supplemental fuel means a fuel
burned within a petrochemical process
that is not produced within the process
itself.
Supplier means a producer, importer,
or exporter of a fossil fuel or an
industrial greenhouse gas.
Taconite iron ore processing means an
industrial process that separates and
concentrates iron ore from taconite, a
low grade iron ore, and heats the
taconite in an indurating furnace to
produce taconite pellets that are used as
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the primary feed material for the
production of iron in blast furnaces at
integrated iron and steel plants.
TAME means tertiary amyl methyl
ether, (CH3)2(C2H5)COCH3).
Trace concentrations means
concentrations of less than 0.1 percent
by mass of the process stream.
Transform means to use and entirely
consume (except for trace
concentrations) nitrous oxide or
fluorinated GHGs in the manufacturing
of other chemicals for commercial
purposes. Transformation does not
include burning of nitrous oxide.
Transshipment means the continuous
shipment of nitrous oxide or a
fluorinated GHG from a foreign state of
origin through the United States or its
territories to a second foreign state of
final destination, as long as the
shipment does not enter into United
States jurisdiction. A transshipment, as
it moves through the United States or its
territories, cannot be re-packaged, sorted
or otherwise changed in condition.
Trona means the raw material
(mineral) used to manufacture soda ash;
hydrated sodium bicarbonate carbonate
(e.g., Na2CO3.NaHCO3.2H2O).
Ultimate analysis means the
determination of the percentages of
carbon, hydrogen, nitrogen, sulfur, and
chlorine and (by difference) oxygen in
the gaseous products and ash after the
complete combustion of a sample of an
organic material.
Unfinished oils are all oils requiring
further processing, except those
requiring only mechanical blending.
United States means the 50 states, the
District of Columbia, and U.S.
possessions and territories.
Unstabilized crude oil means, for the
purposes of this part, crude oil that is
pumped from the well to a pipeline or
pressurized storage vessel for transport
to the refinery without intermediate
storage in a storage tank at atmospheric
pressures. Unstabilized crude oil is
characterized by having a true vapor
pressure of 5 pounds per square inch
absolute (psia) or greater.
Valve means any device for halting or
regulating the flow of a liquid or gas
through a passage, pipeline, inlet,
outlet, or orifice; including, but not
limited to, gate, globe, plug, ball,
butterfly and needle valves.
Vegetable oil means oils extracted
from vegetation that are generally used
as a feedstock in making biodiesel.
Volatile solids are the organic material
in livestock manure and consist of both
biodegradable and non-biodegradable
fractions.
Waelz kiln means an inclined rotary
kiln in which zinc-containing materials
are charged together with a carbon
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reducing agent (e.g., petroleum coke,
metallurgical coke, or anthracite coal).
Waxes means a solid or semi-solid
material at 77 °F consisting of a mixture
of hydrocarbons obtained or derived
from petroleum fractions, or through a
Fischer-Tropsch type process, in which
the straight chained paraffin series
predominates. This includes all
marketable wax, whether crude or
refined, with a congealing point
between 80 (or 85) and 240 °F and a
maximum oil content of 50 weight
percent.
Wool fiberglass means fibrous glass of
random texture, including fiberglass
insulation, and other products listed in
NAICS 327993.
You means an owner or operator
subject to Part 98.
Zinc smelters means a facility engaged
in the production of zinc metal, zinc
oxide, or zinc alloy products from zinc
sulfide ore concentrates, zinc calcine, or
zinc-bearing scrap and recycled
materials through the use of
pyrometallurgical techniques involving
the reduction and volatization of zincbearing feed materials charged to a
furnace.
sroberts on DSKD5P82C1PROD with RULES
§ 98.7 What standardized methods are
incorporated by reference into this part?
The materials listed in this section are
incorporated by reference in the
corresponding sections noted. These
incorporations by reference were
approved by the Director of Federal
Register in accordance with 5 U.S.C.
552(a) and 1 CFR part 51. These
materials are incorporated as they exist
on the date of approval, and a notice of
any change in the materials will be
published in the Federal Register. The
materials are available for purchase at
the corresponding address in this
section. The materials are available for
inspection at the EPA Docket Center,
Public Reading Room, EPA West
Building, Room 3334, 1301 Constitution
Avenue, NW., Washington, DC, phone
(202) 566–1744 and at the National
Archives and Records Administration
(NARA). For information on the
availability of this material at NARA,
call 202–741–6030, or go to: https://
www.archives.gov/federal_register/
code_of_federal_regulations/
ibr_locations.html.
(a) The following material is available
for purchase from the Association of
Fertilizer and Phosphate Chemists
(AFPC), P.O. Box 1645, Bartow, Florida
33831, https://afpc.net.
(1) Phosphate Mining States Methods
Used and Adopted by the Association of
Fertilizer and Phosphate Chemists
AFPC Manual 10th Edition 2009—
Version 1.9, incorporation by reference
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(IBR) approved for § 98.264(a) and
§ 98.264(b).
(2) [Reserved]
(b) The following material is available
for purchase from the American Gas
Association (AGA), 400 North Capitol
Street, NW., 4th Floor, Washington, DC
20001, (202) 824–7000, https://
www.aga.org.
(1) AGA Report No. 3 Orifice Metering
of Natural Gas and Other Related
Hydrocarbon Fluids Part 1: General
Equations & Uncertainty Guidelines
(1990), incorporation by reference (IBR)
approved for § 98.34(b) and § 98.244(b).
(2) AGA Report No. 3 Orifice Metering
of Natural Gas and Other Related
Hydrocarbon Fluids Part 2:
Specification and Installation
Requirements (2000), IBR approved for
§ 98.34(b) and § 98.244(b).
(3) AGA Report No. 11 Measurement
of Natural Gas by Coriolis Meter (2003),
IBR approved for § 98.244(b) and
§ 98.254(c).
(4) AGA Transmission Measurement
Committee Report No. 7 Measurement
of Natural Gas by Turbine Meter (2006)/
February, IBR approved for § 98.34(b)
and § 98.244(b).
(c) The following material is available
for purchase from the ASM
International, 9639 Kinsman Road,
Materials Park, OH 44073, (440) 338–
5151, https://www.asminternational.org.
(1) ASM CS–104 UNS No. G10460—
Alloy Digest April 1985 (Carbon Steel of
Medium Carbon Content), incorporation
by reference (IBR) approved for
§ 98.174(b).
(2) [Reserved]
(d) The following material is available
for purchase from the American Society
of Mechanical Engineers (ASME), Three
Park Avenue, New York, NY 10016–
5990, (800) 843–2763, https://
www.asme.org.
(1) ASME MFC–3M–2004
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi,
incorporation by reference (IBR)
approved for § 98.34(b), § 98.244(b),
§ 98.254(c), § 98.344(c), and § 98.364(e).
(2) ASME MFC–4M–1986 (Reaffirmed
1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for
§ 98.34(b), § 98.244(b), § 98.254(c),
§ 98.344(c), and § 98.364(e).
(3) ASME MFC–5M–1985 (Reaffirmed
1994) Measurement of Liquid Flow in
Closed Conduits Using Transit-Time
Ultrasonic Flowmeters, IBR approved
for § 98.34(b) and § 98.244(b).
(4) ASME MFC–6M–1998
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters, IBR approved
for § 98.34(b), § 98.244(b), § 98.254(c),
§ 98.344(c), and § 98.364(e).
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(5) ASME MFC–7M–1987 (Reaffirmed
1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles,
IBR approved for § 98.34(b), § 98.244(b),
§ 98.254(c), § 98.344(c), and § 98.364(e).
(6) ASME MFC–9M–1988 (Reaffirmed
2001) Measurement of Liquid Flow in
Closed Conduits by Weighing Method,
IBR approved for § 98.34(b) and
§ 98.244(b).
(7) ASME MFC–11M–2006
Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR
approved for § 98.244(b), § 98.254(c),
and § 98.344(c).
(8) ASME MFC–14M–2003
Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters, IBR
approved for § 98.244(b), § 98.254(c),
§ 98.344(c), and § 98.364(e).
(9) ASME MFC–16–2007
Measurement of Liquid Flow in Closed
Conduits with Electromagnetic
Flowmeters, IBR approved for
§ 98.244(b).
(10) ASME MFC–18M–2001
Measurement of Fluid Flow Using
Variable Area Meters, IBR approved for
§ 98.244(b), § 98.254(c),§ 98.344(c), and
§ 98.364(e).
(11) ASME MFC–22–2007
Measurement of Liquid by Turbine
Flowmeters, IBR approved for
§ 98.244(b).
(e) The following material is available
for purchase from the American Society
for Testing and Material (ASTM), 100
Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, Pennsylvania
19428–B2959, (800) 262–1373, https://
www.astm.org.
(1) ASTM C25–06 Standard Test
Method for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime, incorporation by reference (IBR)
approved for § 98.114(b), § 98.174(b),
§ 98.184(b), § 98.194(c), and § 98.334(b).
(2) ASTM C114–09 Standard Test
Methods for Chemical Analysis of
Hydraulic Cement, IBR approved for
§ 98.84(a), § 98.84(b), and § 98.84(c).
(3) ASTM D235–02 (Reapproved
2007) Standard Specification for
Mineral Spirits (Petroleum Spirits)
(Hydrocarbon Dry Cleaning Solvent),
IBR approved for § 98.6.
(4) ASTM D240–02 (Reapproved
2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter, IBR
approved for § 98.34(a) and § 98.254(e).
(5) ASTM D388–05 Standard
Classification of Coals by Rank, IBR
approved for § 98.6.
(6) ASTM D910–07a Standard
Specification for Aviation Gasolines,
IBR approved for § 98.6.
(7) ASTM D1298–99 (Reapproved
2005) Standard Test Method for Density,
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Relative Density (Specific Gravity), or
API Gravity of Crude Petroleum and
Liquid Petroleum Products by
Hydrometer Method, IBR approved for
§ 98.33(a).
(8) ASTM D1826–94 (Reapproved
2003) Standard Test Method for
Calorific (Heating) Value of Gases in
Natural Gas Range by Continuous
Recording Calorimeter, IBR approved
for § 98.34(a) and § 98.254(e).
(9) ASTM D1836–07 Standard
Specification for Commercial Hexanes,
IBR approved for § 98.6.
(10) ASTM D1945–03 Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography, IBR approved for
§ 98.34(b), § 98.74(c), § 98.164(b),
§ 98.244(b), § 98.254(d), and § 98.344(b).
(11) ASTM D1946–90 (Reapproved
2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography,
IBR approved for § 98.34(b), § 98.74(c),
§ 98.164(b), § 98.254(d), § 98.344(b), and
§ 98.364(c).
(12) ASTM D2013–07 Standard
Practice for Preparing Coal Samples for
Analysis, IBR approved for § 98.164(b).
(13) ASTM D2234/D2234M–07
Standard Practice for Collection of a
Gross Sample of Coal, IBR approved for
§ 98.164(b).
(14) ASTM D2502–04 Standard Test
Method for Estimation of Mean Relative
Molecular Mass of Petroleum Oils From
Viscosity Measurements, IBR approved
for § 98.34(b) and § 98.74(c).
(15) ASTM D2503–92 (Reapproved
2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of
Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure, IBR
approved for § 98.34(b) and § 98.74(c).
(16) ASTM D2505–88 (Reapproved
2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and
Carbon Dioxide in High-Purity Ethylene
by Gas Chromatography, IBR approved
for § 98.244(b).
(17) ASTM D2597–94 (Reapproved
2004) Standard Test Method for
Analysis of Demethanized Hydrocarbon
Liquid Mixtures Containing Nitrogen
and Carbon Dioxide by Gas
Chromatography, IBR approved for
§ 98.164(b).
(18) ASTM D3176–89 (Reapproved
2002) Standard Practice for Ultimate
Analysis of Coal and Coke, IBR
approved for § 98.74(c), § 98.164(b),
§ 98.244(b), § 98.254(i), § 98.284(c),
§ 98.284(d), § 98.314(c), § 98.314(d), and
§ 98.314(f).
(19) ASTM D3238–95 (Reapproved
2005) Standard Test Method for
Calculation of Carbon Distribution and
Structural Group Analysis of Petroleum
Oils by the n-d-M Method, IBR
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Jkt 220001
approved for § 98.34(b), § 98.74(c), and
§ 98.164(b).
(20) ASTM D3588–98 (Reapproved
2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels, IBR
approved for § 98.34(a) and § 98.254(e).
(21) ASTM D3682–01 (Reapproved
2006) Standard Test Method for Major
and Minor Elements in Combustion
Residues from Coal Utilization
Processes, IBR approved for § 98.144(b).
(22) ASTM D4057–06 Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products, IBR
approved for § 98.164(b).
(23) ASTM D4177–95 (Reapproved
2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products, IBR approved for § 98.164(b).
(24) ASTM D4809–06 Standard Test
Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method), IBR
approved for § 98.34(a) and § 98.254(e).
(25) ASTM D4891–89 (Reapproved
2006), Standard Test Method for
Heating Value of Gases in Natural Gas
Range by Stoichiometric Combustion,
IBR approved for § 98.34(a) and
§ 98.254(e).
(26) ASTM D5291–02 (Reapproved
2007) Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants, IBR approved
for § 98.34(b), § 98.74(c), § 98.164(b),
§ 98.244(b), § 98.254(i).
(27) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal, IBR
approved for § 98.34(b), § 98.74(c),
§ 98.114(b), § 98.164(b), § 98.174(b),
§ 98.184(b), § 98.244(b), § 98.254(i),
§ 98.274(b), § 98.284(c), § 98.284(d),
§ 98.314(c), § 98.314(d), § 98.314(f), and
§ 98.334(b).
(28) ASTM D5865–07a Standard Test
Method for Gross Calorific Value of Coal
and Coke, IBR approved for § 98.34(a).
(29) ASTM D6060–96 (Reapproved
2001) Standard Practice for Sampling of
Process Vents With a Portable Gas
Chromatograph, IBR approved for
§ 98.244(b).
(30) ASTM D6348–03 Standard Test
Method for Determination of Gaseous
Compounds by Extractive Direct
Interface Fourier Transform Infrared
(FTIR) Spectroscopy, IBR approved for
§ 98.54(b) and § 98.224(b).
(31) ASTM D6609–08 Standard Guide
for Part-Stream Sampling of Coal, IBR
approved for § 98.164(b).
(32) ASTM D6751–08 Standard
Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels,
IBR approved for § 98.6.
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(33) ASTM D6866–08 Standard Test
Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous
Samples Using Radiocarbon Analysis,
IBR approved for § 98.33(e), § 98.34(d),
§ 98.34(e), and § 98.36(e).
(34) ASTM D6883–04 Standard
Practice for Manual Sampling of
Stationary Coal from Railroad Cars,
Barges, Trucks, or Stockpiles, IBR
approved for § 98.164(b).
(35) ASTM D7430–08ae1 Standard
Practice for Mechanical Sampling of
Coal, IBR approved for § 98.164(b).
(36) ASTM D7459–08 Standard
Practice for Collection of Integrated
Samples for the Speciation of Biomass
(Biogenic) and Fossil-Derived Carbon
Dioxide Emitted from Stationary
Emissions Sources, IBR approved for
§ 98.33(e), § 98.34(d), § 98.34(e), and
§ 98.36(e).
(37) ASTM E359–00 (Reapproved
2005)e1 Standard Test Methods for
Analysis of Soda Ash (Sodium
Carbonate), IBR approved for § 98.294(a)
and § 98.294(b).
(38) ASTM E1019–08 Standard Test
Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel,
Iron, Nickel, and Cobalt Alloys by
Various Combustion and Fusion
Techniques, IBR approved for
§ 98.174(b).
(39) ASTM E1747–95 (Reapproved
2005) Standard Guide for Purity of
Carbon Dioxide Used in Supercritical
Fluid Applications, IBR approved for
98.424(b).
(40) ASTM E1915–07a Standard Test
Methods for Analysis of Metal Bearing
Ores and Related Materials by
Combustion Infrared-Absorption
Spectrometry, IBR approved for
§ 98.174(b).
(41) ASTM E1941–04 Standard Test
Method for Determination of Carbon in
Refractory and Reactive Metals and
Their Alloys, IBR approved for
§ 98.114(b), § 98.184(b), § 98.334(b).
(42) ASTM UOP539–97 Refinery Gas
Analysis by Gas Chromatography, IBR
approved for § 98.164(b), § 98.244(b),
and § 98.254(d), and § 98.344(b).
(f) The following material is available
for purchase from the Gas Processors
Association (GPA), 6526 East 60th
Street, Tulsa, Oklahoma 74143, (918)
493–3872, https://
www.gasprocessors.com.
(1) GPA 2172–09 Calculation of Gross
Heating Value, Relative Density,
Compressibility and Theoretical
Hydrocarbon Liquid Content for Natural
Gas Mixtures for Custody Transfer, IBR
approved for § 98.34(a).
(2) GPA 2261–00 Analysis for Natural
Gas and Similar Gaseous Mixtures by
Gas Chromatography, IBR approved for
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§ 98.34(a), § 98.164(b), § 98.254(d), and
§ 98.344(b).
(g) The following material is available
for purchase from the International
Standards Organization (ISO), 1, ch. de
la Voie-Creuse, Case postale 56, CH–
1211 Geneva 20, Switzerland, +41 22
749 01 11, https://www.iso.org/iso/
home.htm.
(1) ISO 3170: Petroleum liquids—
Manual sampling—Third Edition 2004–
02–01, IBR approved for § 98.164(b).
(2) ISO 3171: Petroleum Liquids—
Automatic pipeline sampling—Second
Edition 1988–12–01, IBR approved for
§ 98.164(b).
(3) ISO 8316: Measurement of Liquid
Flow in Closed Conduits— Method by
Collection of the Liquid in a Volumetric
Tank (1987–10–01)—First Edition, IBR
approved for § 98.244(b).
(4) ISO/TR 15349–1: 1998, Unalloyed
steel—Determination of low carbon
content. Part 1: Infrared absorption
method after combustion in an electric
resistance furnace (by peak separation)
(1998–10–15)—First Edition, IBR
approved for § 98.174(b).
(5) ISO/TR 15349–3: 1998, Unalloyed
steel—Determination of low carbon
content. Part 3: Infrared absorption
method after combustion in an electric
resistance furnace (with preheating)
(1998–10–15)—First Edition, IBR
approved for § 98.174(b).
(h) The following material is available
for purchase from the National Lime
Association (NLA), 200 North Glebe
Road, Suite 800, Arlington, Virginia
22203, (703) 243–5463, https://
www.lime.org.
(1) CO2 Emissions Calculation
Protocol for the Lime Industry—English
Units Version, February 5, 2008
Revision—National Lime Association,
incorporation by reference (IBR)
approved for § 98.194(c) and § 98.194(e).
(2) [Reserved]
(i) The following material is available
for purchase from the National Institute
of Standards and Technology (NIST),
100 Bureau Drive, Stop 1070,
Gaithersburg, MD 20899–1070, (800)
877–8339, https://www.nist.gov/
index.html.
(1) Specifications, Tolerances, and
Other Technical Requirements For
Weighing and Measuring Devices, NIST
Handbook 44 (2009), incorporation by
reference (IBR) approved for § 98.244(b),
§ 98.254(h), and § 98.344(a).
(2) [Reserved]
(j) The following material is available
for purchase from the Technical
Association of the Pulp and Paper
Industry (TAPPI), 15 Technology
Parkway South, Norcross, GA 30092,
(800) 332–8686, https://www.tappi.org.
(1) T650 om-05 Solids Content of
Black Liquor, TAPPI, incorporation by
reference (IBR) approved for § 98.276(c)
and § 98.277(d).
(2) T684 om-06 Gross Heating Value
of Black Liquor, TAPPI, incorporation
by reference (IBR) approved for
§ 98.274(b).
§ 98.8 What are the compliance and
enforcement provisions of this part?
Any violation of any requirement of
this part shall be a violation of the Clean
Air Act, including section 114 (42
U.S.C. 7414). A violation includes but is
not limited to failure to report GHG
emissions, failure to collect data needed
to calculate GHG emissions, failure to
continuously monitor and test as
required, failure to retain records
needed to verify the amount of GHG
emissions, and failure to calculate GHG
emissions following the methodologies
specified in this part. Each day of a
violation constitutes a separate
violation.
§ 98.9
Addresses.
All requests, notifications, and
communications to the Administrator
pursuant to this part, other than
submittal of the annual GHG report,
shall be submitted to the following
address:
(a) For U.S. mail. Director, Climate
Change Division, 1200 Pennsylvania
Ave., NW., Mail Code: 6207J,
Washington, DC 20460.
(b) For package deliveries. Director,
Climate Change Division, 1310 L St,
NW., Washington, DC 20005.
TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS
[100-Year Time Horizon]
sroberts on DSKD5P82C1PROD with RULES
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 ..............................................................
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) ...................................
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
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
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
Frm 00137
Fmt 4701
Chemical formula
CO2 ...........................................................................
CH4 ...........................................................................
N2O ...........................................................................
CHF3 .........................................................................
CH2F2 ........................................................................
CH3F .........................................................................
C2HF5 .......................................................................
C2H2F4 ......................................................................
CH2FCF3 ...................................................................
C2H3F3 ......................................................................
C2H3F3 ......................................................................
CH2FCH2F ................................................................
CH3CHF2 ..................................................................
CH3CH2F ..................................................................
C3HF7 ........................................................................
CH2FCF2CF3 .............................................................
CHF2CHFCF3 ...........................................................
C3H2F6 ......................................................................
C3H3F5 ......................................................................
CHF2CH2CF3 ............................................................
CH3CF2CH2CF3 ........................................................
CF3CFHCFHCF2CF3 ................................................
SF6 ............................................................................
SF5CF3 ......................................................................
NF3 ............................................................................
CF4 ............................................................................
C2F6 ..........................................................................
C3F8 ..........................................................................
Sfmt 4700
E:\FR\FM\30OCR2.SGM
30OCR2
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
6,300
560
1,030
794
1,300
23,900
17,700
17,200
6,500
9,200
7,000
56396
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS—Continued
[100-Year Time Horizon]
Name
CAS No.
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 .........................................................
HFE–569sf2 (HFE–7200) .........................................
Chemical blend .........................................................
Sevoflurane ...............................................................
HFE–356mm1 ...........................................................
HFE–338mmz1 .........................................................
(Octafluorotetramethy-lene)hydroxymethyl group ....
HFE–347mmy1 .........................................................
Bis(trifluoromethyl)-methanol ....................................
2,2,3,3,3-pentafluoropropanol ...................................
PFPMIE ....................................................................
Global warming
potential
(100 yr.)
Chemical formula
931–91–9
355–25–9
115–25–3
678–26–2
355–42–0
C-C3F6 ......................................................................
C4F10 .........................................................................
C-C4F8 ......................................................................
C5F12 .........................................................................
C6F14 .........................................................................
17,340
7,000
8,700
7,500
7,400
306–94–5
26675–46–7
E1730133
3822–68–2
1691–17–4
421–14–7
2356–62–9
78522–47–1
57041–67–5
20193–67–3
22410–44–2
84011–15–4
1885–48–9
425–88–7
460–43–5
67490–36–2
156053–88–2
188690–78–0
28523–86–6
E1730135
406–78–0
382–34–3
160620–20–2
E1730137
35042–99–0
378–16–5
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
22052–84–2
920–66–1
422–05–9
NA
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 .......................................................
X-(CF2)4CH(OH)-X ....................................................
CH3OCF(CF3)2 ..........................................................
(CF3)2CHOH .............................................................
CF3CF2CH2OH .........................................................
CF3OCF(CF3)CF2OCF2OCF3 ...................................
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
NA = not available.
TABLE A–2 TO SUBPART A OF PART 98—UNITS OF MEASURE CONVERSIONS
sroberts on DSKD5P82C1PROD with RULES
To convert from
To
Kilograms (kg) .......................................................................
Pounds (lbs) ..........................................................................
Pounds (lbs) ..........................................................................
Short tons ..............................................................................
Short tons ..............................................................................
Metric tons .............................................................................
Metric tons .............................................................................
Cubic meters (m3) .................................................................
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) .................................................................................
Pounds (lbs) .........................................................................
Kilograms (kg) ......................................................................
Metric tons ...........................................................................
Pounds (lbs) .........................................................................
Metric tons ...........................................................................
Short tons ............................................................................
Kilograms (kg) ......................................................................
Cubic feet (ft3) .....................................................................
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) ...............................................................
VerDate Nov<24>2008
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E:\FR\FM\30OCR2.SGM
Multiply by
30OCR2
2.20462
0.45359
4.53592 × 10¥4
2,000
0.90718
1.10231
1,000
35.31467
0.028317
3.78541
0.26417
0.15891
6.289
42
0.023810
0.0037854
0.001
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
56397
TABLE A–2 TO SUBPART A OF PART 98—UNITS OF MEASURE CONVERSIONS—Continued
To convert from
To
Multiply by
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) ................................................
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) ....................................................
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
Subpart C—General Stationary Fuel
Combustion Sources
§ 98.30
Definition of the source category.
(a) Stationary fuel combustion sources
are devices that combust solid, liquid,
or gaseous fuel, generally for the
purposes of producing electricity,
generating steam, or providing useful
heat or energy for industrial,
commercial, or institutional use, or
reducing the volume of waste by
removing combustible matter.
Stationary fuel combustion sources
include, but are not limited to, boilers,
simple and combined-cycle combustion
turbines, engines, incinerators, and
process heaters.
(b) This source category does not
include:
(1) Portable equipment, as defined in
§ 98.6.
(2) Emergency generators and
emergency equipment, as defined in
§ 98.6.
(3) Irrigation pumps at agricultural
operations.
(4) Flares, unless otherwise required
by provisions of another subpart of 40
CFR part 98 to use methodologies in this
subpart.
(5) Electricity generating units that are
subject to subpart D of this part.
(c) For a unit that combusts hazardous
waste (as defined in 40 CFR 261.3),
reporting of GHG emissions is not
required unless either of the following
conditions apply:
(1) Continuous emission monitors
(CEMS) are used to quantify CO2 mass
emissions.
(2) Any fuel listed in Table C–1 of this
subpart is also combusted in the unit. In
this case, report GHG emissions from
combustion of all fuels listed in Table
C–1 of this subpart.
§ 98.31
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains one or more stationary fuel
combustion sources and the facility
meets the applicability requirements of
either §§ 98.2(a)(1), 98.2(a)(2), or
98.2(a)(3).
sroberts on DSKD5P82C1PROD with RULES
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 as defined
in § 98.6 (express mass in short tons for
solid fuel, volume in standard cubic feet
for gaseous fuel, and volume in gallons
for liquid fuel).
HHV = Default high heat value of the fuel,
from Table C–1 of this subpart (mmBtu
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(2) Tier 2 Calculation Methodology.
Calculate the annual CO2 mass
emissions for each type of fuel by using
Frm 00139
Fmt 4701
Sfmt 4700
GHGs to report.
You must report CO2, CH4, and N2O
mass emissions from each stationary
fuel combustion unit.
§ 98.33
Calculating GHG emissions.
You must calculate CO2 emissions
according to paragraph (a) of this
section, and calculate CH4 and N2O
emissions according to paragraph (c) of
this section.
(a) CO2 emissions from fuel
combustion. Calculate CO2 emissions by
using one of the four calculation
methodologies in this paragraph (a)
subject to the conditions, requirements,
and restrictions set forth in paragraph
(b) of this section. If you co-fire biomass
fuels with fossil fuels, report CO2
emissions from the combustion of
biomass separately using the methods in
paragraph (e) of this section.
(1) Tier 1 Calculation Methodology.
Calculate the annual CO2 mass
emissions for each type of fuel by using
Equation C–1 of this section.
(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 × 10¥3 = Conversion factor from kilograms
to metric tons.
PO 00000
§ 98.32
either Equation C2a or C2c of this
section, as appropriate.
(i) Equation C–2a of this section
applies to any type of fuel listed in
Table C–1 of the subpart, except for
municipal solid waste (MSW). For MSW
combustion, use Equation C–2c of this
section.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.004</MATH>
Subpart B—[Reserved]
56398
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
CO2 = 1 x 10−3 ∗ Fuel ∗ HHV ∗ EF
Where:
CO2 = Annual CO2 mass emissions for a
specific fuel type (metric tons).
Fuel = Mass or volume of the fuel combusted
during the year, from company records
as defined in § 98.6 (express mass in
short tons for solid fuel, volume in
standard cubic feet for gaseous fuel, and
volume in gallons for liquid fuel).
HHV = Annual average high heat value of the
fuel from all valid samples for the year
(mmBtu per mass or volume). The
average HHV shall be calculated
(Eq. C-2a)
according to the requirements of
paragraph (a)(2)(ii) of this section.
EF = Fuel-specific default CO2 emission
factor, from Table C–1 of this subpart (kg
CO2/mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
(ii) The minimum number of HHV
samples for determining annual average
HHV is specified (e.g., monthly,
quarterly, semi-annually, or by lot) in
§ 98.34. The method for computing the
annual average HHV is a function of
how frequently you perform or receive
from the fuel supplier the results of fuel
sampling for HHV. The method is
specified in paragraph (a)(2)(ii)(A) or
(a)(2)(ii)(B) of this section, as applicable.
(A) If the results of fuel sampling are
received monthly or more frequently,
then the annual average HHV shall be
calculated using Equation C–2b of this
section. If multiple HHV determinations
are made in any month, average the
values for the month arithmetically.
n
∑ ( HHV )i ∗ ( Fuel )i
( HHV )annual = i =1
n
(Eq. C-2b)
∑ ( Fuel )i
i =1
n = Number of months in the year that fuel
is burned in the unit.
(B) If the results of fuel sampling are
received less frequently than monthly,
then the annual average HHV shall be
computed as the arithmetic average
HHV for all values for the year
(including valid samples and substitute
data values under § 98.35).
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific solid fuel
(metric tons).
Fuel = Annual mass of the solid fuel
combusted, from company records as
defined in § 98.6 (short tons).
17:39 Oct 29, 2009
Jkt 220001
(Eq. C-3)
CC = Annual average carbon content of the
solid fuel (percent by weight, expressed
as a decimal fraction, e.g., 95% = 0.95).
The annual average carbon content shall
be determined using the same
procedures as specified for HHV in
paragraph (a)(2)(ii) of this section.
CO 2 =
VerDate Nov<24>2008
44
∗ Fuel ∗ CC ∗ 0.91
12
PO 00000
44
∗ Fuel ∗ CC ∗ 0.001
12
Frm 00140
Fmt 4701
Sfmt 4725
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.91 = Conversion factor from short tons to
metric tons.
(ii) For a liquid fuel, use Equation C–
4 of this section.
(Eq. C-4)
E:\FR\FM\30OCR2.SGM
ER30OC09.009</MATH>
CO 2 =
(3) Tier 3 Calculation Methodology.
Calculate the annual CO2 mass
emissions for each fuel by using either
Equation C3, C4, or C5 of this section,
as appropriate.
(i) For a solid fuel, use Equation C–
3 of this section.
ER30OC09.008</MATH>
B = Ratio of the boiler’s maximum rated heat
input capacity to its design rated steam
output capacity (mmBtu/lb steam).
EF = Fuel-specific default CO2 emission
factor, from Table C–1 of this subpart (kg
CO2/mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
ER30OC09.007</MATH>
Where:
CO2 = Annual CO2 mass emissions from
MSW or solid fuel combustion (metric
tons).
Steam = Total mass of steam generated by
MSW or solid fuel combustion during
the reporting year (lb steam).
(Eq. C-2c)
ER30OC09.006</MATH>
CO 2 = 1 x 10−3 Steam ∗ B ∗ EF
(iii) For units that combust municipal
solid waste (MSW) and that produce
steam, use Equation C–2c of this
section. Equation C–2c of this section
may also be used for any other solid fuel
listed in Table C–1 of this subpart
provided that steam is generated by the
unit.
30OCR2
ER30OC09.005</MATH>
Where:
(HHV)annual = Weighted annual average high
heat value of the fuel (mmBtu per mass
or volume).
(HHV)i = High heat value of the fuel, for
month ‘‘i’’ (mmBtu per mass or volume).
(Fuel)i = Mass or volume of the fuel
combusted during month ‘‘i’’ (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. 209 / Friday, October 30, 2009 / Rules and Regulations
according to § 98.3(i). Fuel billing meters
may be used for this purpose. Tank drop
measurements may also be used.
CC = Annual average carbon content of the
liquid fuel (kg C per gallon of fuel). The
annual average carbon content shall be
determined using the same procedures as
(iv) Fuel flow meters that measure
mass flow rates may be used for liquid
fuels, provided that the fuel density is
used to convert the readings to
volumetric flow rates. The density shall
be measured at the same frequency as
the carbon content, using ASTM D1298–
99 (Reapproved 2005) ‘‘Standard Test
Method for Density, Relative Density
(Specific Gravity), or API Gravity of
Crude Petroleum and Liquid Petroleum
Products by Hydrometer Method’’
(incorporated by reference, see § 98.7).
(v) The following default density
values may be used for fuel oil, in lieu
of using the ASTM method in paragraph
(a)(3)(iv) of this section: 6.8 lb/gal for
No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/
gal for No. 6 oil.
(4) Tier 4 Calculation Methodology.
Calculate the annual CO2 mass
emissions from all fuels combusted in a
unit, by using quality-assured data from
continuous emission monitoring
systems (CEMS).
(i) This methodology requires a CO2
concentration monitor and a stack gas
volumetric flow rate monitor, except as
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. C-5)
otherwise provided in paragraph
(a)(4)(iv) of this section. Hourly
measurements of CO2 concentration and
stack gas flow rate are converted to CO2
mass emission rates in metric tons per
hour.
(ii) When the CO2 concentration is
measured on a wet basis, Equation C–6
of this section is used to calculate the
hourly CO2 emission rates:
CO2 = 5.18 x 10−7 ∗ CCO 2 ∗ Q (Eq. C-6)
Where:
CO2 = CO2 mass emission rate (metric tons/
hr).
CCO2 = Hourly average CO2 concentration (%
CO2).
Q = Hourly average stack gas volumetric flow
rate (scfh).
5.18 × 10¥7 = Conversion factor (metric tons/
scf/% CO2).
(iii) If the CO2 concentration is
measured on a dry basis, a correction for
the stack gas moisture content is
required. You shall either continuously
monitor the stack gas moisture content
as described in § 75.11(b)(2) of this
chapter or, for certain types of fuel, use
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:
⎛ 100 − % H 2O ⎞
*
CO2 = CO2 ⎜
⎟
100
⎝
⎠
(Eq. C-7)
Where:
CO2* = Hourly CO2 mass emission rate,
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from
Equation C-6 of this section, uncorrected
(metric tons/hr).
%H2O = Hourly moisture percentage in the
stack gas (measured or default value, as
appropriate).
(iv) An oxygen (O2) concentration
monitor may be used in lieu of a CO2
concentration monitor to determine the
hourly CO2 concentrations, in
accordance with Equation F–14a or F–
14b (as applicable) in appendix F to 40
CFR part 75, if the effluent gas stream
monitored by the CEMS consists solely
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Sfmt 4700
of combustion products (i.e., no process
CO2 emissions are mixed with the
combustion products) and if only fuels
that are listed in Table 1 in section 3.3.5
of appendix F to 40 CFR part 75 are
combusted in the unit. If the O2
monitoring option is selected, the Ffactors used in Equations F–14a and F–
14b shall be determined according to
section 3.3.5 or section 3.3.6 of
appendix F to 40 CFR part 75, 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.
(v) Each hourly CO2 mass emission
rate from Equation C–6 or C–7 of this
section is multiplied by the operating
time to convert it from metric tons per
hour to metric tons. The operating time
is the fraction of the hour during which
fuel is combusted (e.g., the unit
operating time is 1.0 if the unit operates
for the whole hour and is 0.5 if the unit
operates for 30 minutes in the hour). For
common stack configurations, the
operating time is the fraction of the hour
during which effluent gases flow
through the common stack.
(vi) The hourly CO2 mass emissions
are then summed over each calendar
quarter and the quarterly totals are
summed to determine the annual CO2
mass emissions.
(vii) If both biomass and fossil fuel are
combusted during the year, determine
and report the biogenic CO2 mass
emissions separately, as described in
paragraph (e) of this section.
(5) Alternative methods for units with
continuous monitoring systems. Units
not subject to the Acid Rain Program
that report data to EPA according to 40
CFR part 75 may use the alternative
methods in this paragraph in lieu of
using any of the four calculation
methodology tiers.
(i) For a unit that combusts only
natural gas and/or fuel oil, is not subject
to the Acid Rain Program, monitors and
reports heat input data year-round
according to appendix D to 40 CFR part
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.012</MATH>
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2 = Annual CO2 mass emissions from
combustion of the specific gaseous fuel
(metric tons).
Fuel = Annual volume of the gaseous fuel
combusted (scf). The volume of fuel
combusted must be measured directly,
using fuel flow meters calibrated
according to § 98.3(i). Fuel billing meters
may be used for this purpose.
CC = Annual average carbon content of the
liquid fuel (kg C per gallon of fuel). The
annual average carbon content shall be
determined using the same procedures as
specified for HHV in paragraph (a)(2)(ii)
of this section.
MW = Annual average molecular weight of
the gaseous fuel (kg/kg-mole). The
annual average carbon content shall be
determined using the same procedures as
specified for HHV in paragraph (a)(2)(ii)
of this section.
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions, as defined in § 98.6).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
44
MW
∗ Fuel ∗ CC ∗
∗ 0.001
12
MVC
(iii) For a gaseous fuel, use Equation
C–5 of this section.
ER30OC09.011</MATH>
CO2 =
specified for HHV in paragraph (a)(2)(ii)
of this section.
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
ER30OC09.010</MATH>
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific liquid fuel
(metric tons).
Fuel = Annual volume of the liquid fuel
combusted (gallons). The volume of fuel
combusted must be measured directly,
using fuel flow meters calibrated
56399
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75, but is not required by the applicable
40 CFR part 75 program to report CO2
mass emissions data, calculate the
annual CO2 mass emissions for the
purposes of this part as follows:
(A) Use the hourly heat input data
from appendix D to 40 CFR part 75,
together with Equation G–4 in appendix
G to 40 CFR part 75 to determine the
hourly CO2 mass emission rates, in units
of tons/hr;
(B) Use Equations F–12 and F–13 in
appendix F to 40 CFR part 75 to
calculate the quarterly and cumulative
annual CO2 mass emissions,
respectively, in units of short tons; and
(C) Divide the cumulative annual CO2
mass emissions value by 1.1 to convert
it to metric tons.
(ii) For a unit that combusts only
natural gas and/or fuel oil, is not subject
to the Acid Rain Program, monitors and
reports heat input data year-round
according to 40 CFR 75.19 of this
chapter but is not required by the
applicable 40 CFR part 75 program to
report CO2 mass emissions data,
calculate the annual CO2 mass
emissions for the purposes of this part
as follows:
(A) Calculate the hourly CO2 mass
emissions, in units of short tons, using
Equation LM–11 in 40 CFR
75.19(c)(4)(iii).
(B) Sum the hourly CO2 mass
emissions values over the entire
reporting year to obtain the cumulative
annual CO2 mass emissions, in units of
short tons.
(C) Divide the cumulative annual CO2
mass emissions value by 1.1 to convert
it to metric tons.
(iii) For a unit that is not subject to
the Acid Rain Program, uses flow rate
and CO2 (or O2) CEMS to report heat
input data year-round according to 40
CFR part 75, but is not required by the
applicable 40 CFR part 75 program to
report CO2 mass emissions data,
calculate the annual CO2 mass
emissions as follows:
(A) Use Equation F–11 or F–2 (as
applicable) in appendix F to 40 CFR
part 75 to calculate the hourly CO2 mass
emission rates from the CEMS data. If an
O2 monitor is used, convert the hourly
average O2 readings to CO2 using
Equation F–14a or F–14b in appendix F
to 40 CFR part 75 (as applicable), before
applying Equation F–11 or F–2.
(B) Use Equations F–12 and F–13 in
appendix F to 40 CFR part 75 to
calculate the quarterly and cumulative
annual CO2 mass emissions,
respectively, in units of short tons.
(C) Divide the cumulative annual CO2
mass emissions value by 1.1 to convert
it to metric tons.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(D) If both biomass and fossil fuel are
combusted during the year, determine
and report the biogenic CO2 mass
emissions separately, as described in
paragraph (e) of this section.
(b) Use of the four tiers. Use of the
four tiers of CO2 emissions calculation
methodologies described in paragraph
(a) of this section is subject to the
following conditions, requirements, and
restrictions:
(1) The Tier 1 Calculation
Methodology:
(i) May be used for any fuel listed in
Table C–1 of this subpart that is
combusted in a unit with a maximum
rated heat input capacity of 250 mmBtu/
hr or less.
(ii) May be used for MSW in a unit of
any size that does not produce steam, if
the use of Tier 4 is not required.
(iii) May be used for solid, gaseous, or
liquid biomass fuels in a unit of any size
provided that the fuel is listed in Table
C–1 of this subpart.
(iv) May not be used if you routinely
perform fuel sampling and analysis for
the fuel high heat value (HHV) or
routinely receive the results of HHV
sampling and analysis from the fuel
supplier at the minimum frequency
specified in § 98.34(a), or at a greater
frequency. In such cases, Tier 2 shall be
used.
(2) The Tier 2 Calculation
Methodology:
(i) May be used for the combustion of
any type of fuel in a unit with a
maximum rated heat input capacity of
250 mmBtu/hr or less provided that the
fuel is listed in Table C–1 of this
subpart.
(ii) May be used in a unit with a
maximum rated heat input capacity
greater than 250 mmBtu/hr for the
combustion of pipeline quality natural
gas and distillate fuel oil.
(iii) May be used for MSW in a unit
of any size that produces steam, if the
use of Tier 4 is not required.
(3) The Tier 3 Calculation
Methodology:
(i) May be used for a unit of any size
that combusts any type of fuel listed in
Table C–1 of this subpart (except for
MSW), unless the use of Tier 4 is
required.
(ii) Shall be used for a unit with a
maximum rated heat input capacity
greater than 250 mmBtu/hr that
combusts any type of fuel listed in Table
C–1 of this subpart (except MSW),
unless either of the following conditions
apply:
(A) The use of Tier 1 or 2 is permitted,
as described in paragraphs (b)(1)(iii) and
(b)(2)(ii) of this section.
(B) The use of Tier 4 is required.
(iii) Shall be used for a fuel not listed
in Table C–1 of this subpart if the fuel
PO 00000
Frm 00142
Fmt 4701
Sfmt 4700
is combusted in a unit with a maximum
rated heat input capacity greater than
250 mmBtu/hr provided that both of the
following conditions apply:
(A) The use of Tier 4 is not required.
(B) The fuel provides 10% or more of
the annual heat input to the unit or, if
§ 98.36(c)(3) applies, to a group of units
served by common supply pipe.
(4) The Tier 4 Calculation
Methodology:
(i) May be used for a unit of any size,
combusting any type of fuel.
(ii) Shall be used if the unit meets all
six of the conditions specified in
paragraphs (b)(4)(ii)(A) through
(b)(4)(ii)(F) of this section:
(A) The unit has a maximum rated
heat input capacity greater than 250
mmBtu/hr, or if the unit combusts
municipal solid waste and has a
maximum rated input capacity greater
than 250 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.
(E) The installed CEMS include a gas
monitor of any kind or a stack gas
volumetric flow rate monitor, or both
and the monitors have been certified,
either in accordance with the
requirements of 40 CFR part 75, part 60
of this chapter, or an applicable State
continuous monitoring program.
(F) The installed gas or stack gas
volumetric flow rate monitors are
required, either by an applicable Federal
or State regulation or by the unit’s
operating permit, to undergo periodic
quality assurance testing in accordance
with either appendix B to 40 CFR part
75, appendix F to 40 CFR part 60, 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
meets all of the following three
conditions:
(A) The unit has both a stack gas
volumetric flow rate monitor and a CO2
concentration monitor.
(B) The unit meets the conditions
specified in paragraphs (b)(4)(ii)(B)
through (b)(4)(ii)(D) of this section.
(C) The CO2 and stack gas volumetric
flow rate monitors meet the conditions
specified in paragraphs (b)(4)(ii)(E) and
(b)(4)(ii)(F) of this section.
E:\FR\FM\30OCR2.SGM
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(6) You may elect to use any
applicable higher tier for one or more of
the fuels combusted in a unit. For
example, if a 100 mmBtu/hr unit
combusts natural gas and distillate fuel
oil, you may elect to use Tier 1 for
natural gas and Tier 3 for the fuel oil,
even though Tier 1 could have been
used for both fuels. However, for units
that use either the Tier 4 or the
alternative calculation methodology
specified in paragraph (a)(5) of this
section, CO2 emissions from the
combustion of all fuels shall be based
solely on CEMS measurements.
CH 4 or N 2O = 1 x 10−3 ∗ Fuel ∗ HHV ∗ EF
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–2 of this
subpart (kg CH4 or N2O per mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
sroberts on DSKD5P82C1PROD with RULES
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
reports required under § 75.64 of this
chapter or, for Tier 4 units, from the best
available information as described in
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. C-9b)
B = Ratio of the boiler’s maximum rated heat
input capacity to its design rated steam
output (mmBtu/lb steam).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C–2 of this subpart (kg
CH4 or N2O per mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
CH 4 or N 2O = 0.001 ∗ (HI)A ∗ EF
Frm 00143
Fmt 4701
Sfmt 4700
(4) Use Equation C–10 of this section
for units in the Acid Rain Program,
units that monitor and report heat input
on a year-round basis according to 40
CFR part 75, and units that use the Tier
4 Calculation Methodology.
(Eq. C-10)
paragraph (c)(4)(ii) of this section
(mmBtu).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C–2 of this section (kg
CH4 or N2O per mmBtu).
0.001 = Conversion factor from kg to metric
tons.
PO 00000
(3) Use Equation C–9b of this section
to estimate CH4 and N2O emissions for
any fuels for which you use Equation
C–2c of this section to calculate the CO2
emissions. Use the same values for
steam generation and the ratio ‘‘B’’ that
you use for Equation C–2c.
(i) If only one type of fuel listed in
Table C–2 of this subpart is combusted
during normal operation, substitute the
cumulative annual heat input from
combustion of the fuel into Equation
C–10 of this section to calculate the
annual CH4 or N2O emissions.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.016</MATH>
Where:
CH4 or N2O = Annual CH4 or N2O emissions
from the combustion of a solid fuel
(metric tons).
Steam = Total mass of steam generated by
solid fuel combustion during the
reporting year (lb steam).
(Eq. C-9a)
reporting year (mmBtu per mass or
volume).
EF = Fuel-specific default emission factor for
CH4 or N2O, from Table C–2 of this
subpart (kg CH4 or N2O per mmBtu).
1 × 10¥3 = Conversion factor from kilograms
to metric tons.
CH 4 or N 2O = 1 x 10−3 Steam ∗ B ∗ EF
(2) Use Equation C–9a of this section
to estimate CH4 and N2O emissions for
any fuels for which you use the Tier 2
Equation C–2a of this section to estimate
CO2 emissions. Use the same values for
fuel combustion and HHV that you use
for the Tier 1 or Tier 3 calculation.
ER30OC09.015</MATH>
CH 4 or N 2O = 1 x 10−3 ∗ HHV ∗ EF ∗ Fuel
Where:
CH4 or N2O = Annual CH4 or N2O emissions
from the combustion of a particular type
of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted
during the reporting year.
HHV = High heat value of the fuel, averaged
for all valid measurements for the
(Eq. C-8)
ER30OC09.014</MATH>
Where:
CH4 or N2O = Annual CH4 or N2O emissions
from the combustion of a particular type
of fuel (metric tons).
Fuel = Mass or volume of the fuel combusted,
either from company records or directly
measured by a fuel flow meter, as
applicable (mass or volume per year).
(c) Calculation of CH4 and N2O
emissions from stationary combustion
sources. You must calculate annual CH4
and N2O mass emissions only for units
that are required to report CO2
emissions using the calculation
methodologies of this subpart and for
only those fuels that are listed in Table
C–2 of this subpart.
(1) Use Equation C–8 of this section
to estimate CH4 and N2O emissions for
any fuels for which you use the Tier 1
or Tier 3 calculation methodologies for
CO2. Use the same values for fuel
combustion that you use for the Tier 1
or Tier 3 calculation.
ER30OC09.013</MATH>
(5) The Tier 4 Calculation
Methodology shall be used beginning
on:
(i) January 1, 2010, for a unit that is
required to report CO2 mass emissions
beginning on that date, if all of the
monitors needed to measure CO2 mass
emissions have been installed and
certified by that date.
(ii) January 1, 2011, for a unit that is
required to report CO2 mass emissions
beginning on January 1, 2010, if all of
the monitors needed to measure CO2
mass emissions have not been installed
and certified by January 1, 2010. In this
case, you may use Tier 2 or Tier 3 to
report GHG emissions for 2010.
56401
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
engineering analysis) to estimate the
annual heat input from each type of
fuel.
(5) When multiple fuels are
combusted during the reporting year,
sum the fuel-specific results from
Equations C–8, C–9a, C–9b, or C–10 of
this section (as applicable) to obtain the
total annual CH4 and N2O emissions, in
metric tons.
⎛ MWCO 2 ⎞
CO2 = 0.91 ∗ S ∗ R ∗ ⎜
⎟
⎝ MWS ⎠
(2) The 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) CO2 emissions from combustion of
biomass. Use the procedures of this
paragraph (e) to estimate biogenic CO2
emissions from units that combust a
combination of biomass and fossil fuels.
Reporting of CO2 emissions from
combustion of biomass is required only
for those biomass fuels listed in Table
C–1 of this section, unless emissions are
measured using CEMS.
(1) If CEMS are not used to measure
CO2, use Equation C–1 of this subpart to
calculate the annual CO2 mass
emissions from the combustion of
biomass (except MSW) for a unit of any
size. Determine the mass of biomass
combusted using one of the following
procedures in this paragraph (e)(1), as
appropriate.
(i) Use company records.
(ii) Follow the procedures in
paragraph (e)(5) of this section.
(iii) For premixed fuels that contain
biomass and fossil fuels (e.g., mixtures
containing biodiesel), use best available
information to determine the mass of
biomass fuels and document the
VCO 2 h =
sroberts on DSKD5P82C1PROD with RULES
Where:
VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly average CO2 concentration,
measured by the CO2 concentration
monitor, or, if applicable, calculated
from the hourly average O2 concentration
(%CO2).
Qh = Hourly average stack gas volumetric
flow rate, measured by the stack gas
volumetric flow rate monitor (scfh).
th = Source operating time (decimal fraction
of the hour during which the source
combusts fuel, i.e., 1.0 for a full
operating hour, 0.5 for 30 minutes of
operation, etc.).
100 = Conversion factor from percent to a
decimal fraction.
(ii) Sum all of the hourly VCO2h values
for the reporting year, to obtain Vtotal,
the total annual volume of CO2 emitted.
(iii) Calculate the annual volume of
CO2 emitted from fossil fuel combustion
using Equation C–13 of this section. If
two or more types of fossil fuel are
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. C-11)
( %CO2 )h
100
∗ Qh ∗ th
(Eq. C-12)
combusted during the year, perform a
separate calculation with Equation C–13
of this section for each fuel and sum the
results.
Vff =
Fuel ∗ Fc ∗ HHV
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, as defined in § 98.6 (lb
for solid fuel, gallons for liquid fuel, and
scf for gaseous fuel).
Fc = Fuel-specific carbon based F-factor,
either a default value from Table 1 in
section 3.3.5 of appendix F to 40 CFR
part 75 or a site-specific value
determined under section 3.3.6 of
appendix F to 40 CFR part 75 (scf CO2/
mmBtu).
PO 00000
Frm 00144
Fmt 4701
procedure used in the GHG Monitoring
Plan required by § 98.3(g)(5).
(2) If a CO2 CEMS (or a surrogate O2
monitor) and a stack gas flow rate
monitor are used to determine the
annual CO2 mass emissions either
according to 40 CFR part 75, the Tier 4
Calculation Methodology, or the
alternative calculation methodology
specified in paragraph (a)(5)(iii); and if
both fossil fuel and biomass (except for
MSW) are combusted in the unit during
the reporting year, you may use the
following procedure to determine the
annual biogenic CO2 mass emissions. If
MSW is combusted in the unit, follow
the procedures in paragraph (e)(3) of
this section.
(i) For each operating hour, use
Equation C–12 of this section to
determine the volume of CO2 emitted.
Sfmt 4700
HHV = High heat value of the fossil fuel,
from fuel sampling and analysis (annual
average value in Btu/lb for solid fuel,
Btu/gal for liquid fuel and Btu/scf for
gaseous fuel, sampled as specified (e.g.,
monthly, quarterly, semi-annually, or by
lot) in § 98.34(a)(2)). The average HHV
shall be calculated according to the
requirements of paragraph (a)(2)(ii) of
this section.
106 = Conversion factor, Btu per mmBtu.
(iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biomass. If a CEMS is
being used to measure the combined
combustion and process emissions from
a unit that is subject to another subpart
of part 98, then also subtract CO2
process emissions from Vtotal to
determine Vbio. The CO2 process
emissions must be calculated according
to the requirements of the applicable
subpart.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.019</MATH>
Where:
CO2 = CO2 emitted from sorbent for the
reporting year (metric tons).
S = Limestone or other sorbent used in the
reporting year, from company records
(short tons).
R = 1.00, the calcium-to-sulfur stoichiometric
ratio.
MWCO2 = Molecular weight of carbon dioxide
(44).
MWS = Molecular weight of sorbent (100 if
calcium carbonate).
0.91 = Conversion factor from short tons to
metric tons.
(d) Calculation of CO2 from sorbent.
(1) When a unit is a fluidized bed
boiler, is equipped with a wet flue gas
desulfurization system, or uses other
acid gas emission controls with sorbent
injection, use Equation C–11 of this
section to calculate the CO2 emissions
from the sorbent, if those CO2 emissions
are not monitored by CEMS:
ER30OC09.018</MATH>
(ii) If more than one type of fuel listed
in Table C–2 of this subpart is
combusted during normal operation, use
Equation C–10 of this section separately
for each type of fuel. If flow rate and
diluent gas monitors are used to
measure the unit heat input, use the best
available information (e.g., fuel feed rate
measurements, fuel heating values,
ER30OC09.017</MATH>
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Vbio
Vtotal
(Eq. C-14)
(vi) Calculate the annual biogenic CO2
mass emissions, in metric tons, by
multiplying the results obtained from
Equation C–14 of this section by the
annual CO2 mass emissions in metric
tons, as determined:
(A) Under paragraph (a)(4)(vi) of this
section, for units using the Tier 4
Calculation Methodology.
(B) Under paragraph (a)(5)(iii)(B) of
this section, for units using the
alternative calculation methodology
specified in paragraph (a)(5)(iii).
(C) From the electronic data report
required under § 75.64 of this chapter,
for units in the Acid Rain Program and
other units using CEMS to monitor and
report CO2 mass emissions according to
40 CFR part 75. However, before
calculating the annual biogenic CO2
mass emissions, multiply the
cumulative annual CO2 mass emissions
by 0.91 to convert from short tons to
metric tons.
(3) For a unit that combusts MSW, the
annual biogenic CO2 emissions shall be
calculated using the procedures in this
paragraph (e)(3).
(i) If the Tier 1 or Tier 2 Calculation
Methodology is used to quantify CO2
mass emissions:
sroberts on DSKD5P82C1PROD with RULES
( Fuel ) p =
Where:
(Fuel)p = Quantity of biomass consumed
during the measurement period ‘‘p’’ (tons/
year or tons/month, as applicable).
H = Average enthalpy of the boiler steam for
the measurement period (Btu/lb).
S = Total boiler steam production for the
measurement period (lb/month or lb/year,
as applicable).
(HI)nb = Heat input from co-fired fossil fuels
and non-biomass-derived fuels for the
measurement period, based on company
records of fuel usage and default or
measured HHV values (Btu/month or Btu/
year, as applicable).
(HHV)bio = Default or measured high heat
value of the biomass fuel (Btu/lb).
(Eff)bio = Percent efficiency of biomass-toenergy conversion, expressed as a decimal
fraction.
2000 = Conversion factor (lb/ton).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
[ H ∗ S ] − ( HI ) nb
2000 ( HHV )bio (Eff )bio
(Eq. C-15)
§ 98.34 Monitoring and QA/QC
requirements.
The CO2 mass emissions data for
stationary fuel combustion sources shall
be monitored as follows:
(a) For the Tier 2 Calculation
Methodology:
(1) All fuel samples shall be taken at
a location in the fuel handling system
that provides a sample representative of
the fuel combusted. The fuel sampling
and analysis may be performed by either
the owner or operator or the supplier of
the fuel.
(2) The minimum required frequency
of the HHV sampling and analysis for
each type of fuel is specified in this
paragraph. When the specified
frequency is based on a specified time
period (i.e., weekly, monthly, quarterly,
or semiannually), fuel sampling and
analysis is required only for those
periods in which the unit operates.
PO 00000
Frm 00145
Fmt 4701
Sfmt 4700
numerator of Equation C–14 of this
section shall be the results of the
calculation performed under paragraph
(e)(3)(ii)(D) of this section.
(F) Calculate the annual biogenic CO2
mass emissions according to paragraph
(e)(2)(vi)(A) of this section.
(4) As an alternative to the procedures
in paragraph (e)(2) of this section, use
ASTM Methods D7459–08 and D6866–
08 to determine the biogenic portion of
the annual CO2 emissions, as described
in § 98.34(e). If this option is selected,
the results of each determination shall
be expressed as a decimal fraction (e.g.,
0.30, if 30 percent of the CO2 is
biogenic), and the values shall be
averaged over the reporting year. The
annual biogenic CO2 mass emissions
shall be calculated by multiplying the
the total annual CO2 mass emissions by
the annual average biogenic fraction
obtained from ASTM D6866–08 and
ASTM D7459–08.
(5) If Equation C–1 of this section is
selected to calculate the annual biogenic
mass emissions for wood, wood waste,
or other solid biomass-derived fuel,
Equation C–15 of this section may be
used to quantify biogenic fuel
consumption, provided that all of the
required input parameters are accurately
quantified. Similar equations and
calculation methodologies based on
steam generation and boiler efficiency
may be used, provided that they are
documented in the GHG Monitoring
Plan required by § 98.3(g)(5).
(i) For natural gas, semiannual
sampling and analysis is required (i.e.,
twice in a calendar year, with
consecutive samples taken at least four
months apart).
(ii) For coal and fuel oil, analysis of
at least one representative sample from
each fuel lot is required. For the
purposes of this section, a fuel lot is
defined as a shipment or delivery of a
single fuel (e.g., ship load, barge load,
group of trucks, group of railroad cars,
etc.).
(iii) For liquid fuels other than fuel
oil, for fossil fuel-derived gaseous fuels,
and for biogas; sampling and analysis is
required at least once per calendar
quarter. To the extent practicable,
consecutive quarterly samples shall be
taken at least 30 days apart.
(iv) For solid fuels other than coal and
MSW, weekly sampling is required to
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ER30OC09.021</MATH>
% Biogenic =
(A) Use Equation C–1 or C–2c of this
subpart, as appropriate, to calculate the
annual CO2 mass emissions from MSW
combustion.
(B) Determine the relative proportions
of biogenic and non-biogenic CO2
emissions on a quarterly basis using the
method specified in § 98.34(d).
(C) Determine the annual biogenic
CO2 mass emissions from MSW
combustion by multiplying the annual
CO2 mass emissions by the annual
average biogenic decimal fraction
obtained from § 98.34(d).
(ii) If the unit uses Tier 4 to quantify
CO2 emissions:
(A) Follow the procedures in
paragraphs (e)(2)(i) and (ii) of this
section, to determine Vtotal.
(B) If any fossil fuel was combusted
during the year, follow the procedures
in paragraph (e)(2)(iii) of this section, to
determine Vff.
(C) Subtract Vff from Vtotal, to obtain
VMSW, the annual volume of CO2
emissions from MSW combustion.
(D) Determine the annual volume of
biogenic CO2 emissions (Vbio) from
MSW combustion as follows. Multiply
the annual volume of CO2 emissions
from MSW combustion (VMSW) by the
annual average biogenic decimal
fraction obtained from ASTM D6866–08
and ASTM D7459–08.
(E) Calculate the biogenic percentage
of the annual CO2 emissions from the
unit, using Equation C–14 of this
section. For the purposes of this
calculation, the term ‘‘Vbio’’ in the
ER30OC09.020</MATH>
(v) Calculate the biogenic percentage
of the annual CO2 emissions,expressed
as a decimal fraction, using Equation C–
14 of this section:
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obtain composite samples, which are
then analyzed monthly.
(3) If different types of fuel (e.g.,
different ranks of coal or different
grades of fuel oil) are blended prior to
combustion, use one of the following
procedures in this paragraph.
(i) Use a weighted HHV value in the
emission calculations, based on the
relative proportions of each fuel in the
blend.
(ii) Take a representative sample of
the blend and analyze it for HHV.
(4) If, for a particular type of fuel,
HHV sampling and analysis is
performed more often than the
minimum frequency specified in
paragraph (a)(2) of this section, the
results of all valid fuel analyses shall be
used in the GHG emission calculations.
(5) If, for a particular type of fuel,
valid HHV values are obtained at less
than the minimum frequency specifed
in paragraph (a)(2) of this section,
appropriate substitute data values shall
be used in the emissions calculations, in
accordance with missing data
procedures of § 98.35.
(6) Use any applicable fuel sampling
and analysis methods in this paragraph
(a)(6) to determine the high heat values.
Alternatively, for gaseous fuels, the
HHV may be calculated using
chromatographic analysis together with
standard heating values of the fuel
constituents, provided that the gas
chromatograph is operated, maintained,
and calibrated according to the
manufacturer’s instructions.
(i) ASTM D4809–06 Standard Test
Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method)
(incorporated by reference, see § 98.7).
(ii) ASTM D240–02 (Reapproved
2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter
(incorporated by reference, see § 98.7).
(iii) ASTM D1826–94 (Reapproved
2003) Standard Test Method for
Calorific (Heating) Value of Gases in
Natural Gas Range by Continuous
Recording Calorimeter (incorporated by
reference, see § 98.7).
(iv) ASTM D3588–98 (Reapproved
2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels
(incorporated by reference, see § 98.7).
(v) ASTM D4891–89 (Reapproved
2006) Standard Test Method for Heating
Value of Gases in Natural Gas Range by
Stoichiometric Combustion
(incorporated by reference, see § 98.7).
(vi) GPA Standard 2172–09
Calculation of Gross Heating Value,
Relative Density, Compressibility and
Theoretical Hydrocarbon Liquid
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Content for Natural Gas Mixtures for
Custody Transfer (incorporated by
reference, see § 98.7).
(vii) GPA Standard 2261–00, Analysis
for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography
(incorporated by reference, see § 98.7).
(viii) ASTM D5865–07a, Standard
Test Method for Gross Calorific Value of
Coal and Coke (incorporated by
reference, see § 98.7).
(b) For the Tier 3 Calculation
Methodology:
(1) Calibrate each oil and gas flow
meter according to § 98.3(i) and the
provisions of this paragraph (b).
(i) Perform calibrations using any of
the test methods and procedures in this
paragraph (b)(1)(i):
(A) An applicable flow meter test
method listed in paragraphs (b)(4)(i)
through (b)(4)(viii) of this section.
(B) The calibration procedures
specified by the flow meter
manufacturer.
(C) An industry-accepted or industry
standard calibration practice.
(ii) In addition to the initial
calibration required by § 98.3(i),
recalibrate each fuel flow meter (except
for qualifying billing meters under
paragraph (b)(1)(iii) of this section)
either annually, at the minimum
frequency specified by the
manufacturer, or at the interval
specified by the industry consensus
standard practice used.
(iii) Fuel billing meters are exempted
from the initial and ongoing calibration
requirements of this paragraph,
provided that the fuel supplier and the
unit combusting the fuel do not have
any common owners and are not owned
by subsidiaries or affiliates of the same
company.
(iv) For the initial calibration of an
orifice, nozzle, or venturi meter; in-situ
calibration of the transmitters is
sufficient. A primary element inspection
(PEI) shall be performed at least once
every three years.
(v) For the continuously-operating
units and processes described in
§ 98.3(i)(6), the required flow meter
recalibrations and, if necessary, the PEIs
may be postponed until the next
scheduled maintenance outage.
(vi) If a mixture of fuels is transported
by a common pipe (e.g., still gas and
supplementary natural gas), you must
either separately meter each of the fuels
prior to mixing using flow meters
calibrated according to § 98.3(i), or use
flow meters calibrated according to
§ 98.3(i) to measure the mixed fuel at
the common pipe and to separately
meter an appropriate subset of the fuels
prior to mixing. If the latter option is
chosen, quantify the fuels that are not
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measured prior to mixing by subtracting
out the fuels measured prior to mixing
from the fuel measured at the common
pipe.
(2) Oil tank drop measurements (if
used to determine liquid fuel use
volume) shall be performed according to
any an appropriate method published
by a consensus-based standards
organization (e.g., the American
Petroleum Institute).
(3) The carbon content and, if
applicable, molecular weight of the
fuels shall be determined according to
the procedures in this paragraph (b)(3).
(i) All fuel samples shall be taken at
a location in the fuel handling system
that provides a sample representative of
the fuel combusted. The fuel sampling
and analysis may be performed by either
the owner or operator or by the supplier
of the fuel.
(ii) At a minimum, fuel samples shall
be collected at the frequency specified
in this paragraph. When sampling is
required at a specified time interval
(e.g., weekly, monthly, quarterly, or
semiannually), fuel sampling and
analysis is required for only those
specified periods in which the unit
operates.
(A) For natural gas, semiannual
sampling and analysis is required (i.e.,
twice in a calendar year, with
consecutive samples taken at least four
months apart).
(B) For coal and fuel oil, analysis of
at least one representative sample from
each fuel lot is required. For the
purposes of this section, a fuel lot is
defined as a shipment or delivery of a
single fuel (e.g., ship load, barge load,
group of trucks, group of railroad cars,
etc.).
(C) For other liquid fuels other than
fuel oil, for fossil fuel-derived gaseous
fuels, and for biogas; sampling and
analysis is required at least once per
calendar quarter. To the extent
practicable, consecutive quarterly
samples shall be taken at least 30 days
apart.
(D) For solid fuels other than coal,
weekly sampling is required to obtain
composite samples, which are then
analyzed monthly.
(E) For gaseous fuels other than
natural gas and biogas (e.g., refinery
gas), daily sampling and analysis to
determine the carbon content and
molecular weight of the fuel is required
if the necessary equipment is in place to
make these measurements. Otherwise,
weekly sampling and analysis shall be
performed.
(iii) If, for a particular type of fuel,
sampling and analysis for carbon
content and molecular weight is
performed more often than the
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minimum frequency specified in
paragraph (b)(3) of this section, the
results of all valid fuel analyses shall be
used in the GHG emission calculations.
(iv) If, for a particular type of fuel,
sampling and analysis for carbon
content and molecular weight is
performed at less than the minimum
frequency specified in paragraph (b)(3)
of this section, appropriate substitute
data values shall be used in the
emissions calculations, in accordance
with the missing data procedures of
§ 98.35.
(v) The procedures of paragraph (a)(3)
of this section apply to carbon content
and molecular weight determinations.
(4) Use any applicable standard
method from the following list to
quality assure the data from each fuel
flow meter.
(i) AGA Report No. 3, Orifice
Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Part 1:
General Equations and Uncertainty
Guidelines (1990) and Part 2:
Specification and Installation
Requirements (2000) (incorporated by
reference, see § 98.7).
(ii) AGA Transmission Measurement
Committee Report No. 7, Measurement
of Gas by Turbine Meters (2006)
(incorporated by reference, see § 98.7).
(iii) ASME MFC–3M–2004
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi
(incorporated by reference, see § 98.7).
(iv) ASME MFC–4M–1986
(Reaffirmed 1997), Measurement of Gas
Flow by Turbine Meters (incorporated
by reference, see § 98.7).
(v) ASME MFC–5M–1985 (Reaffirmed
1994), Measurement of Liquid Flow in
Closed Conduits Using Transit-Time
Ultrasonic Flowmeters (incorporated by
reference, see § 98.7).
(vi) ASME MFC–6M–1998
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters (incorporated
by reference, see § 98.7).
(vii) ASME MFC–7M–1987
(Reaffirmed 1992), Measurement of Gas
Flow by Means of Critical Flow Venturi
Nozzles (incorporated by reference, see
§ 98.7).
(viii) ASME MFC–9M–1988
(Reaffirmed 2001), Measurement of
Liquid Flow in Closed Conduits by
Weighing Method (incorporated by
reference, see § 98.7).
(5) Use any applicable methods from
the following list to determine the
carbon content and molecular weight
(for gaseous fuel) of the fuel.
Alternatively, the results of
chromatographic analysis of the fuel
may be used, provided that the gas
chromatograph is operated, maintained,
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and calibrated according to the
manufacturer’s instructions.
(i) ASTM D1945–03 Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(ii) ASTM D1946–90 (Reapproved
2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference, see § 98.7).
(iii) ASTM D2502–04 (Reapproved
2002) Standard Test Method for
Estimation of Molecular Weight
(Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements
(incorporated by reference, see § 98.7).
(iv) ASTM D2503–92 (Reapproved
2007) Standard Test Method for Relative
Molecular Mass (Relative Molecular
Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor
Pressure (incorporated by reference, see
§ 98.7).
(v) ASTM D3238–95 (Reapproved
2005) Standard Test Method for
Calculation of Carbon Distribution and
Structural Group Analysis of Petroleum
Oils by the n-d-M Method (incorporated
by reference, see § 98.7).
(vi) ASTM D5291–02 (Reapproved
2007) Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants (incorporated
by reference, see § 98.7).
(vii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
(c) For the Tier 4 Calculation
Methodology, the CO2 and flow rate
monitors must be certified prior to the
applicable deadline specified in
§ 98.33(b)(5).
(1) For initial certification, you may
use any one of the following three
procedures in this paragraph.
(i) § 75.20(c)(2) and (4) and appendix
A to 40 CFR part 75.
(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 40 CFR part
75, 40 CFR part 60, 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.
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(3) For ongoing quality assurance,
follow the applicable procedures in
either appendix B to 40 CFR part 75,
appendix F to 40 CFR part 60, or an
applicable State continuous monitoring
program. If appendix F to 40 CFR part
60 is selected for on-going quality
assurance, perform daily calibration
drift assessments for both the CO2
monitor (or surrogate O2 monitor) and
the flow rate monitor, conduct cylinder
gas audits of the CO2 concentration
monitor in three of the four quarters of
each year (except for non-operating
quarters), and perform annual RATAs of
the CO2 concentration monitor and the
CERMS.
(4) For the purposes of this part, the
stack gas volumetric flow rate monitor
RATAs required by appendix B to 40
CFR part 75 and the annual RATAs of
the CERMS required by appendix F to
40 CFR part 60 need only be done at one
operating level, representing normal
load or normal process operating
conditions, both for initial certification
and for ongoing quality assurance.
(5) If, for any source operating hour,
quality assured data are not obtained
with a CO2 monitor (or surrogate O2
monitor), flow rate monitor, or (if
applicable) moisture monitor, use
appropriate substitute data values in
accordance with the missing data
provisions of § 98.35.
(d) When municipal solid waste
(MSW) is combusted in a unit,
determine the biogenic portion of the
CO2 emissions from MSW combustion
using ASTM D6866–08 Standard Test
Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous
Samples Using Radiocarbon Analysis
(incorporated by reference, see § 98.7)
and ASTM D7459–08 Standard Practice
for Collection of Integrated Samples for
the Speciation of Biomass (Biogenic)
and Fossil-Derived Carbon Dioxide
Emitted from Stationary Emissions
Sources (incorporated by reference, see
§ 98.7). Perform the ASTM D7459–08
sampling and the ASTM D6866–08
analysis at least once in every calendar
quarter in which MSW is combusted in
the unit. Collect each gas sample during
normal unit operating conditions while
MSW is the only fuel being combusted
for at least 24 consecutive hours or for
as long as is necessary to obtain a
sample large enough to meet the
specifications of ASTM D6866–08.
Separate CO2 emissions into the
biogenic and non-biogenic fraction
using the average proportion of biogenic
emissions of all samples analyzed
during the reporting year. Express the
results as a decimal fraction (e.g., 0.30,
if 30 percent of the CO2 from MSW
combustion is biogenic). If there is a
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common fuel source of MSW that feeds
multiple units at the facility, performing
the testing at only one of the units is
sufficient.
(e) For units that use CEMS to
measure the total CO2 mass emissions
and combust a combination of biogenic
fuels (other than MSW) with a fossil
fuel, ASTM D6866–08 and ASTM
D7459–08 may be used to determine the
biogenic portion of the CO2 emissions.
Perform the ASTM D7459–08 sampling
and the ASTM D6866–08 analysis at
least once in every calendar quarter in
which biogenic and non-biogenic fuels
are co-fired in the unit. The relative
proportions of the biogenic and nonbiogenic fuels during the sampling shall
be representative of the average fuel
blend for a typical operating year.
Collect each gas sample using ASTM
D7459–08 during normal unit operation
for at least 24 consecutive hours or for
as long as is necessary to obtain a
sample large enough to meet the
specifications of ASTM D6866–08.
(f) Whenever company records are
used in the calculation of CO2
emissions, the records required under
§ 98.3(g) shall include both the company
records and an explanation of how those
records are used to estimate the
following parameters:
(1) Fuel consumption, when the Tier
1 and Tier 2 Calculation Methodologies
are used.
(2) Fuel consumption, when solid fuel
is combusted and the Tier 3 Calculation
Methodology is used.
(3) Fossil fuel consumption when
§ 98.33(e) applies to a unit that uses
CEMS to quantify CO2 emissions and
that combusts both fossil and biomass
fuels.
(4) Sorbent usage, when § 98.33(d)
applies.
(5) Quantity of steam generated by a
unit when § 98.33(a)(2) applies.
(6) Biogenic fuel consumption under
§ 98.33(e)(5).
(g) As part of the GHG Monitoring
Plan required under § 98.3(g)(5), you
must document the procedures used to
ensure the accuracy of the estimates of
fuel usage, sorbent usage, steam
production, and boiler efficiency (as
applicable) in paragraph (f) of this
section, including but not limited to
calibration of weighing equipment, fuel
flow meters, steam flow meters, and
other measurement devices. The
estimated accuracy of measurements
made with these devices shall also be
recorded, and the technical basis for
these estimates shall be provided.
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§ 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,
and all other stationary combustion
units subject to the requirements of this
part that monitor and report emissions
and heat input data in accordance with
40 CFR part 75, the missing data
substitution procedures in 40 CFR part
75 shall be followed for CO2
concentration, stack gas flow rate, fuel
flow rate, high heating value, and fuel
carbon content.
(b) For units that use the Tier 1, Tier
2, Tier 3, and Tier 4 Calculation
Methodologies, perform missing data
substitution as follows for each
parameter:
(1) For each missing value of the high
heating value, carbon content, or
molecular weight of the fuel, substitute
the arithmetic average of the qualityassured values of that parameter
immediately preceding and immediately
following the missing data incident. If
the ‘‘after’’ value has not been obtained
by the time that the GHG emissions
report is due, you may use the ‘‘before’’
value for missing data substitution or
the best available estimate of the
parameter, based on all available
process data (e.g., electrical load, steam
production, operating hours). If, for a
particular parameter, no quality-assured
data are available prior to the missing
data incident, the substitute data value
shall be the first quality-assured value
obtained after the missing data period.
(2) For missing records of CO2
concentration, stack gas flow rate,
percent moisture, fuel usage, and
sorbent usage, the substitute data value
shall be the best available estimate of
the parameter, based on all available
process data (e.g., electrical load, steam
production, operating hours, etc.). You
must document and retain records of the
procedures used for all such estimates.
§ 98.36
Data reporting requirements.
(a) In addition to the facility-level
information required under § 98.3, the
annual GHG emissions report shall
contain the unit-level or process-level
emissions data in paragraphs (b)
through (d) of this section (as
applicable) and the emissions
verification data in paragraph (e) of this
section.
(b) Units that use the four tiers. You
shall report the following information
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for stationary combustion units that use
the Tier 1, Tier 2, Tier 3, or Tier 4
methodology in § 98.33(a) to calculate
CO2 emissions, except as otherwise
provided in paragraphs (c) and (d) of
this section:
(1) The unit ID number.
(2) A code representing the type of
unit.
(3) Maximum rated heat input
capacity of the unit, in mmBtu/hr for
boilers and process heaters only and
relevant units of measure for other
combustion sources.
(4) Each type of fuel combusted in the
unit during the report year.
(5) The tier used to calculate the CO2
emissions for each type of fuel
combusted (i.e., Tier 1, 2, 3, or 4).
(6) For a unit that uses Tiers 1, 2, and
3; the CO2, CH4, and N2O emissions for
each type of fuel combusted, expressed
in metric tons of each gas and in metric
tons of CO2e.
(7) For a unit that uses Tier 4:
(i) For units that burn fossil fuels
only, the annual CO2 emissions for all
fuels combined. Reporting CO2
emissions by type of fuel is not
required.
(ii) For units that burn both fossil
fuels and biomass, the annual CO2
emissions from combustion of all fossil
fuels combined and the annual CO2
emissions from combustion of all
biomass fuels combined. Reporting CO2
emissions by type of fuel is not
required.
(iii) Annual CH4 and N2O emissions
for each type of fuel combusted
expressed in metric tons of each gas and
in metric tons of CO2e.
(8) Annual CO2 emissions from
sorbent (if calculated using Equation C–
11 of this subpart), expressed in metric
tons.
(9) Annual GHG emissions from all
fossil fuels burned in the unit (i.e., the
sum of the CO2, CH4, and N2O
emissions), expressed in metric tons of
CO2e.
(10) Customer meter number for units
that combust natural gas.
(c) Reporting alternatives for units
using the four Tiers. You may use any
of the applicable reporting alternatives
of this paragraph to simplify the unitlevel reporting required under
paragraph (b) of this section:
(1) Aggregation of units. If a facility
contains two or more units (e.g., boilers
or combustion turbines), each of which
has a maximum rated heat input
capacity of 250 mmBtu/hr or less, you
may report the combined GHG
emissions for the group of units in lieu
of reporting GHG emissions from the
individual units, provided that the use
of Tier 4 is not required or elected for
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any of the units and the units use the
same tier for any common fuels
combusted. If this option is selected, the
following information shall be reported
instead of the information in paragraph
(b) of this section:
(i) Group ID number, beginning with
the prefix ‘‘GP’’.
(ii) An identification number for each
unit in the group.
(iii) Cumulative maximum rated heat
input capacity of the group (mmBtu/hr).
(iv) The highest maximum rated heat
input capacity of any unit in the group
(mmBtu/hr).
(v) Each type of fuel combusted in the
group of units during the reporting year.
(vi) Annual CO2, CH4, and N2O mass
emissions aggregated 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. If any of the units burn both fossil
fuels and biomass, report also the
annual CO2 emissions from combustion
of all fossil fuels combined and annual
CO2 emissions from combustion of all
biomass fuels combined, expressed in
metric tons.
(vii) The tier used to calculate the CO2
mass emissions for each type of fuel
combusted in the units (i.e., Tier 1, Tier
2, or Tier 3).
(viii) The calculated CO2 mass
emissions (if any) from sorbent.
(ix) Annual GHG emissions from all
fossil fuels burned in the group (i.e., the
sum of the CO2, CH4, and N2O
emissions), expressed in metric tons of
CO2e.
(2) Monitored common stack or duct
configurations. When the flue gases
from two or more stationary combustion
units at a facility are discharged through
a common stack or duct before exiting
to the atmosphere and if CEMS are used
to continuously monitor CO2 mass
emissions at the common stack or duct
according to the Tier 4 Calculation
Methodology, you may report the
combined emissions from the units
sharing the common stack or duct, in
lieu of separately reporting the GHG
emissions from the individual units.
The following information shall be
reported instead of the information in
paragraph (b) of this section:
(i) Common stack or duct
identification number, beginning with
the prefix ‘‘CS’’.
(ii) Identification numbers of the units
sharing the common stack or duct.
(iii) Maximum rated heat input
capacity of each unit sharing the
common stack or duct (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., Tier 4.
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(vi) If the any of the units burn both
fossil fuels and biomass, annual CO2
mass emissions, annual CO2 emissions
from combustion of fossil fuels, and
annual CO2 emissions from combustion
of biomass measured at the common
stack or duct, expressed in metric tons.
(vii) The annual CH4 and N2O
emissions from the units sharing the
common stack or duct, expressed in
metric tons of each gas and in metric
tons of CO2e.
(viii) Annual GHG emissions from all
fossil fuels burned in the group (i.e., the
sum of the CO2, CH4, and N2O
emissions), expressed in metric tons of
CO2e.
(3) Common pipe configurations.
When two or more liquid-fired or
gaseous-fired stationary combustion
units at a facility combust the same type
of fuel and the fuel is fed to the
individual units through a common
supply line or pipe, you may report the
combined emissions from the units
served by the common supply line, in
lieu of separately reporting the GHG
emissions from the individual units,
provided that the total amount of fuel
combusted by the units is accurately
measured at the common pipe or supply
line using a fuel flow meter that is
calibrated in accordance with § 98.34(a).
If a portion of the fuel measured at the
common pipe is diverted to a chemical
or industrial process where it is used
but not combusted, you may subtract
the diverted fuel from the fuel measured
at the common pipe prior to performing
the GHG emissions calculations,
provided that the amount of fuel
diverted is also measured with a
calibrated flow meter per § 98.3(i). If the
common pipe option is selected, the
applicable tier shall be used based on
the maximum rated heat input capacity
of the largest unit served by the
common pipe configuration. The
following information shall be reported
instead of the information in paragraph
(b) of this section:
(i) Common pipe identification
number, beginning with the prefix
‘‘CP’’.
(ii) The identification 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).
(iv) The fuels combusted in the units
during the reporting year.
(v) The methodology used to calculate
the CO2 mass emissions (i.e., Tier 1, Tier
2, or Tier 3).
(vi) If the any of the units burns both
fossil fuels and biomass, the annual CO2
mass emissions from combustion of all
fossil fuels and annual CO2 emissions
from combustion of all biomass fuels
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56407
from the units served by the common
pipe, expressed in metric tons.
(vii) 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) Annual GHG emissions from all
fossil fuels burned in units served by
the common pipe (i.e., the sum of the
CO2, CH4, and N2O emissions),
expressed in metric tons of CO2e.
(d) Units subject to 40 CFR part 75.
(1) For stationary combustion units
that are either subject to the Acid Rain
Program or not in the Acid Rain
Program but monitor and report CO2
mass emissions year-round according to
40 CFR part 75, you shall report the
following unit-level information:
(i) Unit or stack identification
numbers. Use exact same unit, common
stack, or multiple stack identification
numbers that represent the monitored
locations (e.g., 1, 2, CS001, MS1A, etc.)
that are reported under § 75.64 of this
chapter.
(ii) Annual CO2, CH4, and N2O
emissions at each monitored location,
expressed in metric tons of CO2e.
(iii) Identification of the Part 75
methodology used to determine the CO2
mass emissions.
(2) For units that use the alternative
CO2 mass emissions calculation
methods for units with continuous
monitoring systems provided in
§ 98.33(a)(5), you shall report the
following unit-level information:
(i) Unit, stack, or pipe ID numbers.
Use exact same unit, common stack, or
multiple stack identification numbers
that represent the monitored locations
(e.g., 1, 2, CS001, MS1A, etc.) that are
reported under § 75.64 of this chapter.
(ii) For units that use the alternative
methods specified in § 98.33(a)(5)(i) and
(ii) to monitor and report heat input
data year-round according to appendix
D to 40 CFR part 75 or 40 CFR 75.19:
(A) Each type of fuel combusted in the
unit during the reporting year.
(B) The methodology used to calculate
the CO2 mass emissions for each fuel
type.
(C) A code or flag to indicate whether
heat input is calculated according to
appendix D to 40 CFR part 75 or 40 CFR
75.19.
(D) Annual CO2, CH4, and N2O
emissions at each monitored location,
across all fuel types, expressed in metric
tons of CO2e.
(iii) For units with continuous
monitoring systems that use the
alternative method for units with
continuous monitoring systems in
§ 98.33(a)(5)(iii) to monitor heat input
year-round according to 40 CFR part 75:
(A) Fuel combusted during the
reporting year.
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(B) Methodology used to calculate the
CO2 mass emissions.
(C) A code or flag to indicate that the
heat input data is derived from CEMS
measurements.
(D) The total annual CO2, CH4, and
N2O emissions at each monitored
location, expressed in metric tons of
CO2e.
(e) Verification data. You must keep
on file, in a format suitable for
inspection and auditing, sufficient data
to verify the reported GHG emissions.
This data and information must, where
indicated in this paragraph (e), be
included in the annual GHG emissions
report.
(1) The applicable verification data
specified in this paragraph (e) are not
required to be kept on file or reported
for units that meet any one of the three
following conditions:
(i) Are subject to the Acid Rain
Program.
(ii) Use the alternative methods for
units with continuous monitoring
systems provided in § 98.33(a)(5).
(iii) Are not in the Acid Rain Program,
but are required monitor and report CO2
mass emissions and heat input data
year-round, in accordance with 40 CFR
part 75.
(2) For stationary combustion sources
using the Tier 1, Tier 2, Tier 3, and Tier
4 Calculation Methodologies in
§ 98.33(a) to quantify CO2 emissions, the
following additional information shall
be kept on file and included in the GHG
emissions report, where indicated:
(i) For the Tier 1 Calculation
Methodology, report the total quantity
of each type of fuel combusted in the
unit or group of aggregated units (as
applicable) during the reporting year, in
short tons for solid fuels, gallons for
liquid fuels and standard cubic feet for
gaseous fuels.
(ii) For the Tier 2 Calculation
Methodology, report:
(A) The total quantity of each type of
fuel combusted in the unit or group of
aggregated units (as applicable) during
each month of the reporting year.
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 frequency of the HHV
determinations (e.g., once a month, once
per fuel lot).
(C) The high heat values used in the
CO2 emissions calculations 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. Specify the date on
which each fuel sample was taken.
Indicate whether each HHV is a
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measured value of a substitute data
value.
(D) If Equation C–2c of this subpart is
used to calculate CO2 mass emissions,
report the total quantity (i.e., pounds) of
steam produced from MSW or solid fuel
combustion during the year, and the
ratio of the maximum rate heat input
capacity to the design rated steam
output capacity of the unit, in mmBtu
per lb of steam.
(iii) For the Tier 2 Calculation
Methodology, keep records of the
methods used to determine the HHV for
each type of fuel combusted and the
date on which each fuel sample was
taken.
(iv) For the Tier 3 Calculation
Methodology, report:
(A) The quantity of each type of fuel
combusted in the unit or group of units
(as applicable) during the year, in short
tons for solid fuels, gallons for liquid
fuels, and scf for gaseous fuels.
(B) The frequency of carbon content
and, if applicable, molecular weight
determinations for each type of fuel for
the reporting year (e.g., daily, weekly,
monthly, semiannually, once per fuel
lot).
(C) The carbon content and, if
applicable, gas molecular weight values
used in the emission calculations
(including both valid and substitute
data values). Report all measured values
if the fuel is sampled monthly or less
frequently. Otherwise, for daily and
weekly sampling, report monthly
average values determined using the
calculation procedures in Equation C–
2b for each variable. Express carbon
content as a decimal fraction for solid
fuels, kg C per gallon for liquid fuels,
and kg C per kg of fuel for gaseous fuels.
Express the gas molecular weights in
units of kg per kg-mole.
(D) The total number of valid carbon
content determinations and, if
applicable, molecular weight
determinations made during the
reporting year, for each fuel type.
(E) The number of substitute data
values used for carbon content and, if
applicable, molecular weight used in
the annual GHG emissions calculations.
(v) For the Tier 3 Calculation
Methodology, keep records of the
following:
(A) For liquid and gaseous fuel
combustion, the dates and results of the
initial calibrations and periodic
recalibrations of the required fuel flow
meters.
(B) For fuel oil combustion, the
method from § 98.34(b) used to make
tank drop measurements (if applicable).
(C) The methods used to determine
the carbon content for each type of fuel
combusted.
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(D) The methods used to calibrate the
fuel flow meters).
(vi) For the Tier 4 Calculation
Methodology, report:
(A) The total number of source
operating hours in the reporting year.
(B) The cumulative CO2 mass
emissions in each quarter of the
reporting year, i.e., the sum of the
hourly values calculated from Equation
C–6 or C–7 of this subpart (as
applicable), in metric tons.
(C) For CO2 concentration, stack gas
flow rate, and (if applicable) stack gas
moisture content, the percentage of
source operating hours in which a
substitute data value of each parameter
was used in the emissions calculations.
(vii) For the Tier 4 Calculation
Methodology, keep records of:
(A) Whether the CEMS certification
and quality assurance procedures of 40
CFR part 75, 40 CFR part 60, or an
applicable State continuous monitoring
program were used.
(B) The dates and results of the initial
certification tests of the CEMS.
(C) 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).
(viii) 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 short tons.
(B) The molecular weight of the
sorbent.
(C) The ratio (‘‘R’’) in Equation C–11
of this subpart.
(ix) For units that combust both fossil
fuel and biomass, when CEMS are used
to quantify the annual CO2 emissions
and biogenic CO2 is determined
according to § 98.33(e)(2), you 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 biomass, i.e.,
Vbio, in scf.
(D) The carbon-based F-factor used in
Equation C–13 of this subpart, for each
type of fossil fuel combusted, in scf CO2
per mmBtu.
(E) The annual average HHV value
used in Equation C–13 of this subpart,
for each type of fossil fuel combusted,
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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) Annual biogenic CO2 mass
emissions, in metric tons.
(x) When ASTM methods D7459–08
and D6866–08 are used to determine the
biogenic portion of the annual CO2
emissions from MSW combustion,
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) Annual combined biomass and
fossil fuel CO2 emissions from MSW
combustion, in metric tons of CO2e.
(C) The quantities Vff, Vtotal, and VMSW
from § 98.33(e)(4)(ii), if CEMS are used
to measure CO2 emissions.
(D) The annual volume of biogenic
CO2 emissions from MSW combustion,
in metric tons.
(xi) When ASTM methods D7459–08
and D6866–08 are used to determine the
biogenic portion of the annual CO2
emissions from a unit that co-fires
biogenic (other than MSW) and nonbiogenic fuels, you shall report the
results of each quarterly sample
analysis, expressed as a decimal fraction
(e.g., if the biogenic fraction of the CO2
emissions is 30 percent, report 0.30).
(3) Within 30 days of receipt of a
written request from the Administrator,
you shall submit explanations of the
following:
(i) An explanation of how company
records are used to quantify fuel
consumption, if the Tier 1 or Tier 2
Calculation Methodology is used to
calculate CO2 emissions.
(ii) An explanation of how company
records are used to quantify fuel
consumption, if solid fuel is combusted
and the Tier 3 Calculation Methodology
is used to calculate CO2 emissions.
(iii) An explanation of how sorbent
usage is quantified.
(iv) An explanation of how company
records are used to quantify fossil fuel
56409
consumption in units that uses CEMS to
quantify CO2 emissions and combusts
both fossil fuel and biomass.
(v) An explanation of how company
records are used to measure steam
production, when it is used to calculate
CO2 mass emissions under
§ 98.33(a)(2)(iii) or to quantify solid fuel
usage under § 98.33(c)(3).
(4) Within 30 days of receipt of a
written request from the Administrator,
you shall submit the verification data
and information described in
paragraphs (e)(2)(iii), (e)(2)(v), and
(e)(2)(vii) of this section.
§ 98.37
Records that must be retained.
In addition to the requirements of
§ 98.3(g), you must retain the applicable
records specified in §§ 98.34(f) and (g),
98.35(b), and 98.36(e).
§ 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 TO SUBPART C OF PART 98—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 ......................................................................................................................................................
Subbituminous ................................................................................................................................................
Lignite .............................................................................................................................................................
Coke ................................................................................................................................................................
Mixed (Commercial sector) .............................................................................................................................
Mixed (Industrial coking) .................................................................................................................................
Mixed (Industrial sector) .................................................................................................................................
Mixed (Electric Power sector) .........................................................................................................................
Natural gas
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Petroleum products
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1.028 ×
10¥3
mmBtu/gallon
Distillate Fuel Oil No. 1 ...................................................................................................................................
Distillate Fuel Oil No. 2 ...................................................................................................................................
Distillate Fuel Oil No. 4 ...................................................................................................................................
Residual Fuel Oil No. 5 ..................................................................................................................................
Residual Fuel Oil No. 6 ..................................................................................................................................
Still Gas ..........................................................................................................................................................
Kerosene .........................................................................................................................................................
Liquefied petroleum gases (LPG) ...................................................................................................................
Propane ..........................................................................................................................................................
Propylene ........................................................................................................................................................
Ethane .............................................................................................................................................................
Ethylene ..........................................................................................................................................................
Isobutane ........................................................................................................................................................
Isobutylene ......................................................................................................................................................
Butane .............................................................................................................................................................
Butylene ..........................................................................................................................................................
Naphtha (<401 deg F) ....................................................................................................................................
Natural Gasoline .............................................................................................................................................
Other Oil (>401 deg F) ...................................................................................................................................
Pentanes Plus .................................................................................................................................................
Petrochemical Feedstocks ..............................................................................................................................
17:39 Oct 29, 2009
103.54
93.40
97.02
96.36
102.04
95.26
93.65
93.91
94.38
mmBtu/scf
Pipeline (Weighted U.S. Average) ..................................................................................................................
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17.25
14.21
24.80
21.39
26.28
22.35
19.73
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0.139
0.138
0.146
0.140
0.150
0.143
0.135
0.092
0.091
0.091
0.096
0.100
0.097
0.103
0.101
0.103
0.125
0.110
0.139
0.110
0.129
30OCR2
kg CO2/mmBtu
53.02
kg CO2/mmBtu
73.25
73.96
75.04
72.93
75.10
66.72
75.20
62.98
61.46
65.95
62.64
67.43
64.91
67.74
65.15
67.73
68.02
66.83
76.22
70.02
70.97
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TABLE C–1 TO SUBPART C OF PART 98—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS
TYPES OF FUEL—Continued
Default high
heat value
Fuel type
Petroleum Coke ..............................................................................................................................................
Special Naphtha .............................................................................................................................................
Unfinished Oils ................................................................................................................................................
Heavy Gas Oils ...............................................................................................................................................
Lubricants .......................................................................................................................................................
Motor Gasoline ...............................................................................................................................................
Aviation Gasoline ............................................................................................................................................
Kerosene-Type Jet Fuel .................................................................................................................................
Asphalt and Road Oil .....................................................................................................................................
Crude Oil .........................................................................................................................................................
0.143
0.125
0.139
0.148
0.144
0.125
0.120
0.135
0.158
0.138
Fossil fuel-derived fuels (solid)
102.41
72.34
74.49
74.92
74.27
70.22
69.25
72.22
75.36
74.49
mmBtu/short ton
Municipal Solid Waste 1 ..................................................................................................................................
Tires ................................................................................................................................................................
kg CO2/mmBtu
9.95
26.87
Fossil fuel-derived fuels (gaseous)
90.7
85.97
mmBtu/scf
kg CO2/mmBtu
0.092 ×
0.599 × 10¥3
10¥3
Blast Furnace Gas ..........................................................................................................................................
Coke Oven Gas ..............................................................................................................................................
Biomass fuels—solid
mmBtu/short ton
Wood and Wood Residuals ............................................................................................................................
Agricultural Byproducts ...................................................................................................................................
Peat .................................................................................................................................................................
Solid Byproducts .............................................................................................................................................
274.32
46.85
kg CO2/mmBtu
15.38
8.25
8.00
25.83
Biomass fuels—gaseous
93.80
118.17
111.84
105.51
mmBtu/scf
kg CO2/mmBtu
0.841 × 10¥3
Biogas (Captured methane) ...........................................................................................................................
Biomass Fuels—Liquid ...................................................................................................................................
mmBtu/gallon
Ethanol (100%) ...............................................................................................................................................
Biodiesel (100%) .............................................................................................................................................
Rendered Animal Fat ......................................................................................................................................
Vegetable Oil ..................................................................................................................................................
1 Allowed
Default CO2
emission factor
52.07
kg CO2/mmBtu
0.084
0.128
0.125
0.120
68.44
73.84
71.06
81.55
only for units that do not generate steam and use Tier 1.
TABLE C–2 TO SUBPART C OF PART 98—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL
Default CH4
emission factor
(kg CH4/mmBtu)
Fuel type
Coal and Coke (All fuel types in Table C–1) ....................................................................................................
Natural Gas ........................................................................................................................................................
Petroleum (All fuel types in Table C–1) ............................................................................................................
Municipal Solid Waste .......................................................................................................................................
Tires ...................................................................................................................................................................
Blast Furnace Gas .............................................................................................................................................
Coke Oven Gas .................................................................................................................................................
Biomass Fuels—Solid (All fuel types in Table C–1) .........................................................................................
Biogas ................................................................................................................................................................
Biomass Fuels—Liquid (All fuel types in Table C–1) ........................................................................................
1.1
1.0
3.0
3.2
3.2
2.2
4.8
3.2
3.2
1.1
×
×
×
×
×
×
×
×
×
×
10¥2
10¥03
10¥03
10¥02
10¥02
10¥05
10¥04
10¥02
10¥03
10¥03
Default N2O
emission factor
(kg N2O/mmBtu)
1.6
1.0
6.0
4.2
4.2
1.0
1.0
4.2
6.3
1.1
×
×
×
×
×
×
×
×
×
×
10¥03
10¥04
10¥04
10¥03
10¥03
10¥04
10¥04
10¥03
10¥04
10¥04
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Note: 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 1g of CH4/MMBtu.
1 Allowed only for units that do not generate steam and use Tier 1.
TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL
Default CH4
emission factor
(kg CH4/mmBtu)
Fuel type
Coal and Coke (All fuel types in Table C–1) ....................................................................................................
Natural Gas ........................................................................................................................................................
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Default N2O
emission factor
(kg N2O/mmBtu)
1.1 × 10¥2
1.0 × 10¥03
1.6 × 10¥03
1.0 × 10¥04
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TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL—Continued
Default CH4
emission factor
(kg CH4/mmBtu)
Fuel type
Petroleum (All fuel types in Table C–1) ............................................................................................................
Municipal Solid Waste .......................................................................................................................................
Tires ...................................................................................................................................................................
Blast Furnace Gas .............................................................................................................................................
Coke Oven Gas .................................................................................................................................................
Biomass Fuels—Solid (All fuel types in Table C–1) .........................................................................................
Biogas ................................................................................................................................................................
Biomass Fuels—Liquid (All fuel types in Table C–1) ........................................................................................
3.0
3.2
3.2
2.2
4.8
3.2
3.2
1.1
×
×
×
×
×
×
×
×
10¥03
10¥02
10¥02
10¥05
10¥04
10¥02
10¥03
10¥03
Default N2O
emission factor
(kg N2O/mmBtu)
6.0
4.2
4.2
1.0
1.0
4.2
6.3
1.1
×
×
×
×
×
×
×
×
10¥04
10¥03
10¥03
10¥04
10¥04
10¥03
10¥04
10¥04
Note: 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
§ 98.43
§ 98.40
Continue to monitor and report CO2
mass emissions as required under
§ 75.13 or section 2.3 of apppendix G to
40 CFR part 75, and § 75.64. Calculate
CO2, CH4, and N2O emissions as
follows:
(a) Convert the cumulative annual
CO2 mass emissions reported in the
fourth quarter electronic data report
required under § 75.64 from units of
short tons to metric tons. To convert
tons to metric tons, divide by 1.1023.
(b) Calculate and report annual CH4
and N2O mass emissions under this
subpart by following the applicable
method specified in § 98.33(c).
Definition of the source category.
(a) The electricity generation source
category comprises electricity
generating units that are subject to the
requirements of the Acid Rain Program
and any other electricity generating
units that are required to monitor and
report to EPA CO2 emissions year-round
according to 40 CFR part 75.
(b) This source category does not
include portable equipment, emergency
equipment, or emergency generators, as
defined in § 98.6.
§ 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 § 98.2(a)(1).
sroberts on DSKD5P82C1PROD with RULES
§ 98.42
GHGs to report.
(a) For each electricity generating unit
that is subject to the requirements of the
Acid Rain Program or is otherwise
required to monitor and report to EPA
CO2 emissions year-round according to
40 CFR part 75, you must report under
this subpart the annual mass emissions
of CO2, N2O, and CH4 by following the
requirements of this subpart.
(b) For each electricity generating unit
that is not subject to the Acid Rain
Program or otherwise required to
monitor and report to EPA CO2
emissions year-round according to 40
CFR part 75, you must report under
subpart C of this part (General
Stationary Fuel Combustion Sources)
the emissions of CO2, CH4, and N2O by
following the requirements of subpart C.
(c) For each stationary fuel
combustion unit that does not generate
electricity, you must report under
subpart C of this part (General
Stationary Fuel Combustion Sources)
the emissions of CO2, CH4, and N2O by
following the requirements of subpart C
of this part.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
Calculating GHG emissions.
§ 98.44 Monitoring and QA/QC
requirements.
Follow the applicable quality
assurance procedures for CO2 emissions
in appendices B, D, and G to 40 CFR
part 75.
§ 98.45
data.
Procedures for estimating missing
Follow the applicable missing data
substitution procedures in 40 CFR part
75 for CO2 concentration, stack gas flow
rate, fuel flow rate, high heating value,
and fuel carbon content.
§ 98.46
Data reporting requirements.
The annual report shall comply with
the data reporting requirements
specified in § 98.36(b) and, if applicable,
§ 98.36(c)(2) or (c)(3).
§ 98.47
Records that must be retained.
You shall comply with the
recordkeeping requirements of
§§ 98.3(g) and 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.
PO 00000
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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 at the facility level.
(b) You must report under subpart C
of this part (General Stationary Fuel
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit following the
requirements of subpart C.
§ 98.53
Calculating GHG emissions.
(a) You must determine annual N2O
emissions from adipic acid production
according to paragraphs (a)(1) or (a)(2)
of this section.
(1) Use a site-specific emission factor
and production data according to
paragraphs (b) through (h) of this
section.
(2) Request Administrator approval
for an alternative method of determining
N2O emissions according to paragraphs
(a)(2)(i) and (a)(2)(ii) of this section.
(i) You must submit the request
within 45 days following promulgation
of this subpart or within the first 30
days of each subsequent reporting year.
(ii) If the Administrator does not
approve your requested alternative
method within 150 days of the end of
the reporting year, you must determine
the N2O emissions factor for the current
reporting period using the procedures
specified in paragraphs (b) through (h)
of this section.
(b) You must conduct an annual
performance test according to
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(3) You must measure the adipic acid
production rate during the test and
calculate the production rate for the test
period in metric tons per hour.
(c) You must determine an N2O
emissions factor to use in Equation E–
2 of this section according to paragraphs
(c)(1) or (c)(2) of this section.
(1) You may request Administrator
approval for an alternative method of
determining N2O concentration
EFN 2O =
Where:
EFN2O = Average facility-specific N2O
emissions factor (lb N2O generated/ton
adipic acid produced).
CN2O = N2O concentration per text run during
the performance test (ppm N2O).
1.14 × 10¥7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas per
test run during the performance test
(dscf/hr).
P = Production rate per test run during the
performance test (tons adipic acid
produced/hr).
n = Number of test runs.
(d) If applicable, you must determine
the destruction efficiency for each N2O
abatement technology used at your
facility according to paragraphs (d)(1),
(d)(2), or (d)(3) of this section.
(1) Use the manufacturer’s specified
destruction efficiency.
(2) Estimate the destruction efficiency
through process knowledge. Examples
of information that could constitute
1
C N 2O ∗1.14 × 10−7 ∗ Q
P
n
process knowledge include calculations
based on material balances, process
stoichiometry, or previous test results
provided the results are still relevant to
the current vent stream conditions. You
must document how process knowledge
was used to determine the destruction
efficiency.
(3) Calculate the destruction
efficiency by conducting an additional
performance test on the emissions
stream following the N2O abatement
technology.
(e) If applicable, you must determine
the abatement factor for each N2O
abatement technology used at your
facility. The abatement factor is
calculated for each adipic acid facility
according to Equation E–2 of this
section.
AFN =
N
N 2O = ∑
sroberts on DSKD5P82C1PROD with RULES
(h) You must determine the amount of
process N2O emissions that is sold or
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Pa Abate
Pa
(Eq. E-2)
EFN 2O ∗ Pa ∗ (1 − ( DFN ∗ AFN ) )
2205
1
Where:
N2O = Annual N2O mass emissions from
adipic acid production (metric tons).
EFN2O = Facility-specific N2O emissions
factor (lb N2O generated/ton adipic acid
produced).
Pa = Annual adipic acid produced (tons).
DFN = Destruction efficiency of N2O
abatement technology N (abatement
device destruction efficiency, percent of
N2O removed from air stream).
AFN = Abatement factor of N2O abatement
technology N (fraction of annual
production abatement technology is
operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement
technologies.
(Eq. E-1)
§ 98.54 Monitoring and QA/QC
requirements.
(a) You must conduct a new
performance test and calculate a new
facility-specific emissions factor
according to the frequency specified in
paragraphs (a)(1) through (a)(3) of this
section.
(1) Conduct the performance test
annually.
(2) Conduct the performance test
when your adipic acid production
process is changed either by altering the
Frm 00154
Fmt 4701
Sfmt 4700
(f) You must determine the annual
amount of adipic acid produced and the
annual adipic acid production during
which N2O abatement is operating.
(g) You must calculate annual adipic
acid production process emissions of
N2O by multiplying the emissions factor
(determined using Equation E–1 of this
section) by the total annual adipic acid
production and accounting for N2O
abatement, according to Equation E–3 of
this section:
(Eq. E-3)
transferred off site (if applicable). You
can determine the amount using
existing process flow meters and N2O
analyzers.
PO 00000
Where:
AFN = Abatement factor of N2O abatement
technology (fraction of annual
production that abatement technology is
operating).
Pa Abate = Annual adipic acid production
during which N2O abatement was used.
Pa = Total annual adipic acid production (ton
acid produced).
ratio of cyclohexanone to cyclohexanol
or by installing abatement equipment.
(3) If you requested Administrator
approval for an alternative method of
determining N2O concentration under
§ 98.53(a)(2), you must conduct the
performance test if your request has not
been approved by the Administrator
within 150 days of the end of the
reporting year in which it was
submitted.
(b) You must measure the N2O
concentration during the performance
test using one of the methods in
paragraphs (b)(1) through (b)(3) of this
section.
(1) EPA Method 320, Measurement of
Vapor Phase Organic and Inorganic
Emissions by Extractive Fourier
E:\FR\FM\30OCR2.SGM
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ER30OC09.024</MATH>
n
∑
according to the procedures in
paragraphs (a)(2)(i) and (a)(2)(ii) of this
section. Alternative methods include
the use of N2O CEMs.
(2) Using the results of the
performance test in paragraph (b) of this
section, you must calculate a facilityspecific emissions factor according to
Equation E–1 of this section:
ER30OC09.023</MATH>
paragraphs (b)(1) through (b)(3) of this
section.
(1) You must conduct the test on the
waste gas stream from the nitric acid
oxidation step of the process using the
methods specified in § 98.54(b) through
(d).
(2) You must conduct the
performance test under normal process
operating conditions and without using
N2O abatement technology.
ER30OC09.022</MATH>
56412
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Transform Infrared (FTIR) Spectroscopy
in 40 CFR part 63, Appendix A;
(2) ASTM D6348–03 Standard Test
Method for Determination of Gaseous
Compounds by Extractive Direct
Interface Fourier Transform Infrared
(FTIR) Spectroscopy (incorporated by
reference, see § 98.7); or
(3) An equivalent method, with
Administrator approval.
(c) You must determine the
production rate(s) during the
performance test according to paragraph
(c)(1) or (c)(2) of this section.
(1) Direct measurement (such as using
flow meters or weigh scales).
(2) Existing plant procedures used for
accounting purposes.
(d) You must conduct all required
performance tests according to the
methods in § 98.54(b) 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. All QA/QC procedures
specified in the reference test methods
and any associated performance
specifications apply. For each test, the
facility must prepare an emissions factor
determination report that must include
the items in paragraphs (d)(1) through
(d)(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(s) during the
performance test and how each
production rate was determined.
(e) You must determine the monthly
adipic acid production quantity and the
monthly adipic acid production during
which N2O abatement technology is
operating according to the methods in
paragraphs (c)(1) or (c)(2) of this section.
(f) You must determine the annual
adipic acid production quantity and the
annual adipic production quantity
during which N2O abatement
technology is operating by summing the
respective monthly adipic acid
production quantities.
sroberts on DSKD5P82C1PROD with RULES
§ 98.55
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, a
substitute data value for the missing
parameter shall be used in the
calculations as specified in paragraphs
(a) and (b) of this section.
(a) For each missing value of monthly
adipic acid production, the substitute
data shall be the best available estimate
based on all available process data or
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data used for accounting purposes (such
as sales records).
(b) For missing values related to the
performance test, including emission
factors, production rate, and N2O
concentration, you must conduct a new
performance test according to the
procedures in § 98.54 (a) through (d).
§ 98.56
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 (k) of this
section at the facility level:
(a) Annual process N2O emissions
from adipic acid production (metric
tons).
(b) Annual adipic acid production
(tons).
(c) Annual adipic acid production
during which N2O abatement
technology is operating (tons).
(d) Annual process N2O emissions
from adipic acid production facility that
is sold or transferred off site (metric
tons).
(e) Number of abatement technologies
(if applicable).
(f) Types of abatement technologies
used (if applicable).
(g) Abatement technology destruction
efficiency for each abatement
technology (percent destruction).
(h) Abatement utilization factor for
each abatement technology (fraction of
annual production that abatement
technology is operating).
(i) Number of times in the reporting
year that missing data procedures were
followed to measure adipic acid
production (months).
(j) If you conducted a performance
test and calculated a site-specific
emissions factor according to
§ 98.53(a)(1), each annual report must
also contain the information specified in
paragraphs (j)(1) through (j)(7) of this
section for each adipic acid production
facility.
(1) Emissions factor (lb N2O/ton
adipic acid).
(2) Test method used for performance
test.
(3) Production rate per test run during
performance test (tons/hr).
(4) N2O concentration per test run
during performance test (ppm N2O).
(5) Volumetric flow rate per test run
during performance test (dscf/hr).
(6) Number of test runs.
(7) Number of times in the reporting
year that a performance test had to be
repeated (number).
(k) If you requested Administrator
approval for an alternative method of
determining N2O concentration under
§ 98.53(a)(2), each annual report must
also contain the information specified in
PO 00000
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56413
paragraphs (k)(1) through (k)(4) of this
section for each adipic acid production
facility.
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
§ 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 (h) of this section at the facility
level:
(a) Annual adipic acid production
capacity (tons).
(b) Records of significant changes to
process.
(c) Number of facility operating hours
in calendar year.
(d) Documentation of how accounting
procedures were used to estimate
production rate.
(e) Documentation of how process
knowledge was used to estimate
abatement technology destruction
efficiency.
(f) Performance test reports of N2O
emissions.
(g) Measurements, records and
calculations used to determine reported
parameters.
(h) Documentation of the procedures
used to ensure the accuracy of the
measurements of all reported
parameters, including but not limited to,
calibration of weighing equipment, flow
meters, 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.
§ 98.58
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart F—Aluminum Production
§ 98.60
Definition of the source category.
(a) A primary aluminum production
facility manufactures primary
´
aluminum using the Hall-Heroult
manufacturing process. The primary
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.
§ 98.61
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an aluminum production
process and the facility meets the
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
§ 98.63
Calculating GHG emissions.
(a) The annual value for PFC
emissions shall be estimated from the
sum of monthly values using Equation
F–1 of this section:
EPFC =
m =12
∑
m =1
Em
(Eq. F-1)
Where:
E CF4 = SCF4 × AEM × MP × 0.001
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).
E CF4 = EFCF4 × MP × 0.001
(Eq. F-3)
EFCF4 = The overvoltage emission factor (kg
CF4/metric ton Al).
(c) You must calculate and report the
annual process CO2 emissions from
sroberts on DSKD5P82C1PROD with RULES
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).
(Eq. F-4)
anode consumption during electrolysis
and anode baking of prebake cells using
either the procedures in paragraph (d) of
this section or the procedures in
paragraphs (e) and (f) of this section.
(d) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining CEMS
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
E CO 2 = NAC × MP ×
([100
MP = Metal production (metric tons Al),
where MP is calculated monthly.
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(e) Use the following procedures to
calculate CO2 emissions from anode
consumption during electrolysis:
(1) For Prebake cells: you must
calculate CO2 emissions from anode
consumption using Equation F–5 of this
section:
− Sa − Ash a ] /100 ) × (44 / 12)
MP = Annual metal production (metric tons
Al).
Sa = Sulfur content in baked anode (percent
weight).
Asha = Ash content in baked anode (percent
weight).
(Eq. F-5)
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) For S<derberg cells you must
calculate CO2 emissions using Equation
F–6 of this section:
E CO 2 = (PC × MP − [ CSM × 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)
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E:\FR\FM\30OCR2.SGM
(Eq. F-6)
30OCR2
ER30OC09.030</MATH>
E C 2 F6 = E CF4 × FC 2 F6 / CF4 × 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).
0.001 = Conversion factor from kg to metric
tons, where ECF4 is calculated monthly.
MP = Metal production (metric tons Al),
where AEM and MP are calculated
monthly.
ER30OC09.029</MATH>
Where:
ECF4 = Monthly CF4 emissions from
aluminum production (metric tons CF4).
(Eq. F-2)
ER30OC09.028</MATH>
Where:
ECF4 = Monthly CF4 emissions from
aluminum production (metric tons CF4).
(b) Use Equation F–2 of this section to
estimate CF4 emissions from anode
effect duration or Equation F–3 of this
section to estimate CF4 emissions from
overvoltage, and use Equation F–4 of
this section to estimate C2F6 emissions
from anode effects from each prebake
and S<derberg electolysis cell.
ER30OC09.027</MATH>
GHGs to report.
You must report:
(a) Perfluoromethane (CF4), and
perfluoroethane (C2F6) emissions from
anode effects in all prebake and
S<derberg electolysis cells.
(b) CO2 emissions from anode
consumption during electrolysis in all
prebake and S<derberg electolysis cells.
(c) CO2 emissions from on-site anode
baking.
(d) You must report under subpart C
of this part (General Stationary Fuel
EPFC = Annual PFC emissions from
aluminum production (metric tons PFC).
Em = PFC emissions from aluminum
production for the month ‘‘m’’ (metric
tons PFC).
ER30OC09.026</MATH>
§ 98.62
Combustion Sources) the emissions of
CO2, N2O, and CH4 emissions from each
stationary fuel combustion unit by
following the requirements of subpart C.
ER30OC09.025</MATH>
requirements of either § 98.2(a)(1) or
(a)(2).
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
− 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).
(
(f) Use the following procedures to
calculate CO2 emissions from anode
baking of prebake cells:
(1) Use Equation F–7 of this section to
calculate emissions from pitch volatiles
combustion.
(Eq. F-7)
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) Use Equation F–8 of this section to
calculate emissions from bake furnace
packing material.
)
E CO 2PC = 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.
(g) If process CO2 emissions from
anode consumption during electrolysis
or anode baking of prebake cells are
vented through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraphs
(d) and (e) of this section shall not be
used to calculate those process
emissions. The owner or operation shall
report under this subpart the combined
stack emissions according to the Tier 4
Calculation Methodology in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
§ 98.64 Monitoring and QA/QC
requirements.
(a) Effective one year after publication
of the rule for smelters with no prior
measurement or effective three years
after publication for facilities with
historic measurements, the smelterspecific slope coefficients used in
Equations F–2, F–3, and F–4 of this
subpart must be measured in
accordance with the recommendations
of the EPA/IAI Protocol for
Measurement of Tetrafluoromethane
(CF4) and Hexafluoroethane (C2F6)
Emissions from Primary Aluminum
Production (2008), except the minimum
frequency of measurement shall be
every 10 years unless a change occurs in
the control algorithm that affects the
mix of types of anode effects or the
nature of the anode effect termination
routine. Facilities which operate at less
than 0.2 anode effect minutes per cell
day or operate with less than 1.4mV
anode effect overvoltage can use either
smelter-specific slope coefficients or the
technology specific default values in
Table F–1 of this subpart.
sroberts on DSKD5P82C1PROD with RULES
ECO 2 = EFp x MPp + EFs x MPs
Where:
ECO2 = CO2 emissions from anode and/or
paste consumption, metric tons CO2.
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(b) The minimum frequency of the
measurement and analysis is annually
except as follows: Monthly—anode
effect minutes per cell day (or anode
effect overvoltage and current
efficiency), production.
(c) Sources may use either smelterspecific values from annual
measurements of parameters needed to
complete the equations in § 98.63 (e.g.,
sulfur, ash, and hydrogen contents) or
the default values shown in Table F–2
of this subpart.
§ 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–8 of this section.
(Eq. F-8)
EFp = Prebake technology specific emission
factor (1.6 metric tons CO2/metric ton
aluminum produced).
MPp = Metal production from prebake
process (metric tons Al).
PO 00000
(Eq. F-8)
EFs = S<derberg technology specific emission
factor (1.7 metric tons CO2/metric ton Al
produced).
MPs = Metal production from S<derberg
process (metric tons Al).
E:\FR\FM\30OCR2.SGM
30OCR2
er30oc09.033</MATH>
Where:
ECO2PV = Annual CO2 emissions from pitch
volatiles combustion (metric tons CO2).
GA = Initial weight of green anodes (metric
tons).
( GA
44/12 = Ratio of molecular weights, CO2 to
carbon.
ER30OC09.032</MATH>
E CO 2 PV =
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).
CD = Carbon in skimmed dust from
S<derberg cells (metric ton C/metric ton
Al).
ER30OC09.031</MATH>
Where:
ECO2 = Annual CO2 emissions from paste
consumption (metric ton CO2).
PC = Annual paste consumption (metric ton/
metric ton Al).
MP = Annual metal production (metric ton
Al).
CSM = Annual emissions of cyclohexane
soluble matter (kg/metric ton Al).
BC = Binder content of paste (percent
weight).
56415
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(b) For other parameters, use the
average of the two most recent data
points after the missing data.
§ 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:
(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
(AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect
duration (minutes). (Or anode effect
overvoltage factor ((kg CF4/metric ton
Al)/(mV/cell day)), potline overvoltage
(mV/cell day), current efficiency (%).)
(3) Smelter-specific slope coefficients
(or overvoltage emission factors) and the
last date when the smelter-specificslope coefficients (or overvoltage
emission factors) were measured.
(d) Method used to measure the
frequency and duration of anode effects
(or overvoltage).
(e) The following CO2-specific
information for prebake cells:
(1) Annual anode consumption.
(2) Annual CO2 emissions from the
smelter.
(f) The following CO2-specific
information for S<derberg cells:
(1) Annual paste consumption.
(2) Annual 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)
and process control technology (e.g.,
Pechiney or other).
§ 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 prebake and S<derberg
electolysis cells.
(2) Anode effect minutes per cell-day
(AE-mins/cell-day), anode effect
frequency (AE/cell-day), anode effect
duration (minutes). (Or anode effect
overvoltage factor ((kg CF4/metric ton
Al)/(mV/cell day)), potline overvoltage
(mV/cell day), current efficiency (%).))
(3) Smelter-specific slope coefficients
and the last date when the smelterspecific-slope coefficients were
measured.
(d) Method used to measure the
frequency and duration of anode effects
(or to measure anode effect overvoltage
and current efficiency).
(e) The following CO2-specific
information for prebake cells:
(1) Annual anode consumption.
(2) Annual CO2 emissions from the
smelter.
(f) The following CO2-specific
information for S<derberg cells:
(1) Annual paste consumption.
(2) Annual 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)
and process control technology (e.g.,
Pechiney or other).
§ 98.68
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE F–1 TO SUBPART F OF PART 98—SLOPE AND OVERVOLTAGE COEFFICIENTS FOR THE CALCULATION OF PFC
EMISSIONS FROM ALUMINUM PRODUCTION
CF4 slope
coefficient
[(kg CF4/metric
ton Al)/(AEMins/cell-day)]
Technology
CF4 overvoltage
coefficient
[(kg CF4/metric
ton Al)/(mV)]
Weight fraction
C2F6/CF4
[(kg C2F6/
kg CF4)]
0.143
0.272
0.092
0.099
1.16
3.65
NA
NA
0.121
0.252
0.053
0.085
CWPB ..........................................................................................................................................
SWPB ..........................................................................................................................................
VSS ..............................................................................................................................................
HSS ..............................................................................................................................................
TABLE F–2 TO SUBPART F OF PART 98—DEFAULT DATA SOURCES FOR PARAMETERS USED FOR CO2 EMISSIONS
Parameter
Data source
CO2 Emissions from Prebake Cells (CWPB and SWPB)
MP: metal production (metric tons Al) ............................................................................................................................
NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) ................................
Sa: sulfur content in baked anode (percent weight) .......................................................................................................
Asha: ash content in baked anode (percent weight) ......................................................................................................
Individual facility records.
Individual facility records.
2.0.
0.4.
sroberts on DSKD5P82C1PROD with RULES
CO2 Emissions from S<derberg Cells (VSS and HSS)
MP: metal production (metric tons Al) ............................................................................................................................
PC: annual paste consumption (metric ton/metric ton Al) .............................................................................................
CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) ....................................................................
BC: binder content of paste (percent weight) ................................................................................................................
Sp: sulfur content of pitch (percent weight) ....................................................................................................................
Ashp: ash content of pitch (percent weight) ...................................................................................................................
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17:39 Oct 29, 2009
Jkt 220001
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E:\FR\FM\30OCR2.SGM
30OCR2
Individual facility records.
Individual facility records.
HSS: 4.0.
VSS: 0.5.
Dry Paste: 24.
Wet Paste: 27.
0.6.
0.2.
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
56417
TABLE F–2 TO SUBPART F OF PART 98—DEFAULT DATA SOURCES FOR PARAMETERS USED FOR CO2 EMISSIONS—
Continued
Parameter
Data source
Hp: hydrogen content of pitch (percent weight) ..............................................................................................................
Sc: sulfur content in calcined coke (percent weight) ......................................................................................................
Ashc: ash content in calcined coke (percent weight) .....................................................................................................
CD: carbon in skimmed dust from S<derberg cells (metric ton C/metric ton Al) ...........................................................
3.3.
1.9.
0.2.
0.01.
CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS)
GA: initial weight of green anodes (metric tons) ............................................................................................................
Hw: annual hydrogen content in green anodes (metric tons) ........................................................................................
BA: annual baked anode production (metric tons) .........................................................................................................
WT: annual waste tar collected (metric tons) .................................................................................................................
(a) Riedhammer furnaces ...............................................................................................................................................
(b) all other furnaces.
Individual facility records.
0.005 × GA.
Individual facility records.
(a) 0.005 × GA.
(b) insignificant.
CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)
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) .....................................................................................................
§ 98.70
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 and liquid 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) CO2 process emissions from steam
reforming of a hydrocarbon or the
gasification of solid and liquid raw
material, reported for each ammonia
manufacturing process unit following
the requirements in this subpart.
(b) CO2, CH4, and N2O emissions from
each stationary fuel combustion unit.
You must report these emissions under
subpart C of this part (General
Stationary Fuel Combustion Sources),
by following the requirements of
subpart C.
(c) CO2 emissions collected and
transferred off site under subpart PP of
this part (Suppliers of CO2), following
the requirements of subpart PP.
§ 98.73
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
sroberts on DSKD5P82C1PROD with RULES
⎛ 12 44
MW ⎞
CO 2,G ,k = ⎜ ∑
∗ Fdstk n ,k ∗ CCn ∗
⎟ ∗ 0.001
⎜
12
MVC ⎟
⎝ n=1
⎠
Where:
CO2,G = Annual CO2 emissions arising from
feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock
used in month n (scf of feedstock).
CCn = Carbon content of the gaseous
feedstock, for month n (kg C per kg of
feedstock), determined according to
98.74(c).
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17:39 Oct 29, 2009
Jkt 220001
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.
0.001 = Conversion factor from kg to metric
tons.
PO 00000
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ammonia manufacturing process unit
using the procedures in either paragraph
(a) or (b) of this section.
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining CEMS
according to the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart process CO2 emissions using the
procedures in paragraphs (b)(1) through
(b)(6) of this section for gaseous
feedstock, liquid feedstock, or solid
feedstock, as applicable.
(1) Gaseous feedstock. You must
calculate, from each ammonia
manufacturing unit, the CO2 process
emissions from gaseous feedstock
according to Equation G–1 of this
section:
(Eq. G-1)
1
k = Processing unit.
n = Number of month.
(2) Liquid feedstock. You must
calculate, from each ammonia
manufacturing unit, the CO2 process
emissions from liquid feedstock
according to Equation G–2 of this
section:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.034</MATH>
Subpart G—Ammonia Manufacturing
0.015.
Individual facility records.
2.
2.5.
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
⎛ 12 44
⎞
CO 2,L,k = ⎜ ∑
∗ Fdstk n ,k ∗ CCn ⎟ ∗ 0.001
⎜
⎟
⎝ n=1 12
⎠
feedstock) determined according to
98.74(c).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
k = Processing unit.
n = Number of month.
⎛ 12 44
⎞
CO 2,S,k = ⎜ ∑
∗ Fdstk n ,k ∗ CCn ⎟ ∗ 0.001
⎜
⎟
⎝ n =1 12
⎠
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
k = Processing unit.
n = Number of month.
(Eq. G-5)
k=1
Where:
CO2 = Annual combined CO2 emissions from
all ammonia processing units (metric
tons).
ECO2k = Annual CO2 emissions from each
ammonia processing unit (metric tons).
k = Processing unit.
sroberts on DSKD5P82C1PROD with RULES
⎛ 12 44
MW ⎞
∗ Re cycleStream n ∗ CCn ∗
CO 2 = ⎜ ∑
⎟ 0.001
⎜
MVC ⎟
⎠
⎝ n=1 12
Where:
CO2 = Annual CO2 contained in waste
recycle stream (metric tons).
RecycleStreamn = Volume of the waste
recycle stream in month n (scf).
CCn = Carbon content of the waste recycle
stream, for month n (kg C per kg of waste
recycle stream) determined according to
98.74(f).
MW = Molecular weight of the waste recycle
stream (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.
n = Number of month
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17:39 Oct 29, 2009
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(c) If GHG emissions from an
ammonia manufacturing unit are vented
through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraph
(b) of this section shall not be used to
calculate process emissions. The owner
or operator shall report under this
subpart the combined stack emissions
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part.
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n = Total number of ammonia processing
units.
(6) If applicable, ammonia
manufacturing facilities that utilize the
waste recycle stream as a fuel must
calculate emissions associated with the
waste stream for each ammonia process
unit according to Equation G–6 of this
section:
(Eq. G-6)
§ 98.74 Monitoring and QA/QC
requirements.
(a) You 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 document the
procedures used to ensure the accuracy
of the estimates of feedstock
consumption.
(c) You must determine monthly
carbon contents and the average
molecular weight of each feedstock
consumed from reports from your
supplier. As an alternative to using
supplier information on carbon
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.039</GPH>
(5) You must determine the combined
CO2 emissions from all ammonia
processing units at your facility using
Equation G–5 of this section.
(Eq. G-4)
n
CO 2 = ∑ E CO2k
(4) You must calculate the annual
process CO2 emissions from each
ammonia processing unit k at your
facility summing emissions, as
applicable from Equation G–1, G–2, and
G–3 of this section using Equation G–4.
ER30OC09.038</MATH>
E CO 2k = CO 2,G + CO 2,S + CO 2,L
Where:
ECO2k = Annual CO2 emissions from each
ammonia processing unit k (metric tons).
k = Processing unit.
(Eq. G-3)
ER30OC09.037</MATH>
Where:
CO2,S = Annual CO2 emissions arising from
feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in
month n (kg of feedstock).
CCn = Carbon content of the solid feedstock,
for month n (kg C per kg of feedstock),
determined according to 98.74(c).
(3) Solid feedstock. You must
calculate, from each ammonia
manufacturing unit, the CO2 process
emissions from solid feedstock
according to Equation G–3 of this
section:
ER30OC09.036</MATH>
Where:
CO2,L = Annual CO2 emissions arising from
feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used
in month n (gallons of feedstock).
CCn = Carbon content of the liquid feedstock,
for month n (kg C per gallon of
(Eq. G-2)
ER30OC09.035</MATH>
56418
sroberts on DSKD5P82C1PROD with RULES
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
contents, you can also collect a sample
of each feedstock on a monthly basis
and analyze the carbon content and
molecular weight of the fuel using any
of the following methods listed in
paragraphs (c)(1) through (c)(8) of this
section, as applicable.
(1) ASTM D1945–03 Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(2) ASTM D1946–90 (Reapproved
2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference, see § 98.7).
(3) ASTM D2502–04 (Reapproved
2002) Standard Test Method for
Estimation of Mean Relative Molecular
Mass of Petroleum Oils from Viscosity
Measurements (incorporated by
reference, see § 98.7).
(4) ASTM D2503–92 (Reapproved
2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of
Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure
(incorporated by reference, see § 98.7).
(5) ASTM D3238–95 (Reapproved
2005) Standard Test Method for
Calculation of Carbon Distribution and
Structural Group Analysis of Petroleum
Oils by the n-d-M Method (incorporated
by reference, see § 98.7).
(6) ASTM D5291–02 (Reapproved
2007) Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants (incorporated
by reference, see § 98.7).
(7) ASTM D3176–89 (Reapproved
2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated
by reference, see § 98.7).
(8) ASTM D5373–08 Standard
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
(d) Calibrate all oil and gas flow
meters (except for gas billing meters)
and perform oil tank measurements
according to the monitoring and QA/QC
requirements for the Tier 3 methodology
in § 98.34(b).
(e) For quality assurance and quality
control of the supplier data, on an
annual basis, you must measure the
carbon contents of a representative
sample of the feedstocks consumed
using the appropriate ASTM Method as
listed in paragraphs (c)(1) through (c)(8)
of this section.
(f) Facilities must continuously
measure the quantity of waste gas
recycled using a flow meter, as
applicable. You must determine the
carbon content and the molecular
weight of the waste recycle stream by
collecting a sample of each waste
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
recycle stream on a monthly basis and
analyzing the carbon content using the
appropriate ASTM Method as listed in
paragraphs (c)(1) through (c)(8) of this
section.
(g) If CO2 from ammonia production
is used to produce urea at the same
facility, you must determine the
quantity of urea produced using
methods or plant instruments used for
accounting purposes (such as sales
records). You must document the
procedures used to ensure the accuracy
of the estimates of urea produced.
§ 98.75
data.
Procedures for estimating missing
A complete record of all measured
parameters used in the GHG emissions
calculations is required. Therefore,
whenever the monitoring and quality
assurance procedures in § 98.74 cannot
be followed (e.g., if a meter
malfunctions during unit operation), a
substitute data value for the missing
parameter shall be used in the
calculations following paragraphs (a)
and (b) of this section. You must
document and keep records of the
procedures used for all such estimates.
(a) For missing data on monthly
carbon contents of feedstock or the
waste recycle stream, the substitute data
value shall be the arithmetic average of
the quality-assured values of that carbon
content in the month preceding and the
month 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 for carbon content
obtained in the month after the missing
data period.
(b) For missing feedstock supply rates
or waste recycle stream used to
determine monthly feedstock
consumption or monthly waste recycle
stream quantity, you must determine the
best available estimate(s) of the
parameter(s), based on all available
process data.
§ 98.76
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) and (b) of this section,
as applicable for each ammonia
manufacturing process unit.
(a) If a CEMS is used to measure CO2
emissions, then you must report the
relevant information required under
§ 98.37(e)(2)(vi) for the Tier 4
Calculation Methodology and the
following information in this paragraph
(a):
(1) Annual quantity of each type of
feedstock consumed for ammonia
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56419
manufacturing (scf of feedstock or
gallons of feedstock or kg of feedstock).
(2) Method used for determining
quantity of feedstock used.
(b) If a CEMS is not used to measure
emissions, then you must report the
following information:
(1) Annual CO2 process emissions
(metric tons) for each ammonia
manufacturing process unit.
(2) Monthly quantity of each type of
feedstock consumed for ammonia
manufacturing for each ammonia
processing unit (scf of feedstock or
gallons of feedstock or kg of feedstock).
(3) Method used for determining
quantity of monthly feedstock used.
(4) Whether carbon content for each
feedstock for month n is based on
reports from the supplier or analysis of
carbon content.
(5) If carbon content of feedstock for
month n is based on analysis, the test
method used.
(6) Sampling analysis results of
carbon content of petroleum coke as
determined for QA/QC of supplier data
under § 98.74(e).
(7) If a facility uses gaseous feedstock,
the carbon content of the gaseous
feedstock, for month n, (kg C per kg of
feedstock).
(8) If a facility uses gaseous feedstock,
the molecular weight of the gaseous
feedstock (kg/kg-mole).
(9) If a facility uses gaseous feedstock,
the molar volume conversion factor of
the gaseous feedstock (scf per kg-mole).
(10) If a facility uses liquid feedstock,
the carbon content of the liquid
feedstock, for month n, (kg C per gallon
of feedstock).
(11) If a facility uses solid feedstock,
the carbon content of the solid
feedstock, for month n, (kg C per kg of
feedstock).
(12) Annual CO2 emissions associated
with the waste recycle stream for each
ammonia process unit (metric tons)
(13) Carbon content of the waste
recycle stream for month n for each
ammonia process unit (kg C per kg of
waste recycle stream).
(14) Volume of the waste recycle
stream for month n for each ammonia
process unit (scf)
(15) Method used for analyzing
carbon content of waste recycle stream.
(16) Annual urea production (metric
tons) and method used to determine
urea production.
(17) Uses of urea produced, if known,
such as but not limited to fertilizer,
animal feed, manufacturing of plastics
or resins, and pollution control
technologies.
(c) Total pounds of synthetic fertilizer
produced through and total nitrogen
contained in that fertilizer.
E:\FR\FM\30OCR2.SGM
30OCR2
56420
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
§ 98.81
§ 98.82
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
sroberts on DSKD5P82C1PROD with RULES
CO2
Cli,m
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
kiln using the procedure in paragraphs
(a) and (b) of this section.
(a) For each cement kiln that meets
the conditions specified in
CO2CMF =
Where:
CO2 CMF = Annual process emissions of CO2
from cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2
from clinker production from kiln m,
metric tons.
GHGs to report.
You must report:
(a) CO2 process emissions from
calcination in each kiln.
(b) CO2 combustion emissions from
each kiln.
(c) CH4 and N2O combustion
emissions from each kiln. You must
calculate and report these emissions
under subpart C of this part (General
Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
(d) CO2, CH4, and N2O emissions from
each stationary combustion unit other
than kilns. You must report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
§ 98.83
§ 98.80
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).
§ 98.33(b)(4)(ii) or (b)(4)(iii), you must
calculate and report under this subpart
the combined process and combustion
CO2 emissions by operating and
maintaining a CEMS to measure CO2
emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(b) For each kiln that is not subject to
the requirements in paragraph (a) of this
section, calculate and report the process
and combustion CO2 emissions from the
kiln by using the procedure in either
paragraph (c) or (d) of this section.
(c) Calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
and maintaining a CEMS to measure
CO2 emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(d) Calculate and report process and
combustion CO2 emissions separately
using the procedures specified in
paragraphs (d)(1) through (d)(4) of this
section.
(1) Calculate CO2 process emissions
from all kilns at the facility using
Equation H–1 of this section:
k
∑ CO2Cli,m +
m =1
CO2 rm
(Eq. H-1)
CO2 rm = Total annual emissions of CO2 from
raw materials, metric tons.
k = Total number of kilns at a cement
manufacturing facility.
(2) CO2 emissions from clinker
production. Calculate CO2 emissions
from each kiln using Equations H–2
through H–5 of this section.
p
2000 ⎤ r ⎡
2000 ⎤
⎡
+ ∑ ( CKD,i ) ∗ ( EFCKD,i ) ∗
= ∑ ⎢ Cli, j ∗ EFCli, j ∗
2205 ⎥ i =1 ⎢
2205 ⎥
⎦
⎣
⎦
j =1 ⎣
(
) (
Where:
Cli,j = Quantity of clinker produced in month
j from kiln m, tons.
EFCli,j = Kiln specific clinker emission factor
for month j for kiln m, metric tons CO2/
metric ton clinker computed as specified
in Equation H–3 of this section.
)
CKD,i = Cement kiln dust (CKD) not recycled
to the kiln in quarter i from kiln m, tons.
EFCKD,i = Kiln specific CKD emission factor
for quarter i from kiln m, metric tons
CO2/metric ton CKD computed as
specified in Equation H–4 of this section.
p = Number of months for clinker
calculation, 12.
(
r = Number of quarters for CKD calculation,
4.
2000/2205 = Conversion factor to convert
tons to metric tons.
(i) Kiln-Specific Clinker Emission
Factor. (A) Calculate the kiln-specific
clinker emission factor using Equation
H–3 of this section.
)
EFCli = ( CLiCaO − ClincCaO ) ∗ MRCaO + CliMgO − ClincMgO ∗ MRMgO
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
PO 00000
Frm 00162
Fmt 4701
Sfmt 4725
(Eq. H-2)
E:\FR\FM\30OCR2.SGM
(Eq. H-3)
30OCR2
ER30OC09.042</MATH>
§ 98.78
in-line kiln/raw mills that burn
hazardous waste.
ER30OC09.041</MATH>
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) and
(b) of this section for each ammonia
manufacturing unit.
(a) If a CEMS is used to measure
emissions, retain records of all feedstock
purchases in addition to the
requirements in § 98.37 for the Tier 4
Calculation Methodology.
(b) If a CEMS is not used to measure
process CO2 emissions, you must also
retain the records specified in
paragraphs (b)(1) through (b)(2) of this
section:
(1) Records of all analyses and
calculations conducted for reported data
as listed in § 98.76(b).
(2) Monthly records of carbon content
of feedstock from supplier and/or all
analyses conducted of carbon content.
ER30OC09.040</MATH>
§ 98.77
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
ClincMgO = Monthly non-calcined MgO
content of Clinker, wt-fraction.
MRMgO = Molecular-weight Ratio of CO2/
MgO = 1.092.
remains in the clinker in the form of
MgCO3 and MgO in the clinker that
entered the kiln as a non-carbonate
species.
(ii) Kiln-Specific CKD Emission
Factor. (A) Calculate the kiln-specific
CKD emission factor for CKD not
recycled to the kiln using Equation H–
4 of this section.
(B) Non-calcined CaO is CaO that
remains in the clinker in the form of
CaCO3 and CaO in the clinker that
entered the kiln as a non-carbonate
species. Non-calcined MgO is MgO that
(
)
EFCKD = ( CKDCaO − CKDncCaO ) ∗ MRCaO + CKDMgO − CKDncMgO ∗ MRMgO
CKDMgO = Quarterly non-calcined MgO
content of CKD not recycled to the kiln,
wt-fraction.
MRMgO = Molecular-weight Ratio of CO2/
MgO = 1.092.
(B) Non-calcined CaO is CaO that
remains in the CKD in the form of
CaCO3 and CaO in the CKD that entered
the kiln as a non-carbonate species.
m
CO2, rm = ∑ rm ∗ TOCrm ∗
i =1
Where:
rm = The amount of raw material i consumed
annually, tons/yr (dry basis).
CO2,rm = Annual CO2 emissions from raw
materials.
TOCrm = Organic carbon content of raw
material i (dry basis), as determined in
§ 98.84(c) or using a default factor of 0.2
percent of total raw material weight.
M = Number of raw materials.
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion factor to convert
tons to metric tons.
(4) Calculate and report under subpart
C of this part (General Stationary Fuel
Combustion Sources) the combustion
CO2 emissions from the kiln according
to the applicable requirements in
subpart C.
sroberts on DSKD5P82C1PROD with RULES
§ 98.84 Monitoring and QA/QC
requirements.
(a) You must determine the weight
fraction of total CaO and total MgO in
CKD not recycled to the kiln from each
kiln using ASTM C114–09, Standard
Test Methods for Chemical Analysis of
Hydraulic Cement (incoporated by
reference, see § 98.7). The monitoring
must be conducted quarterly for each
kiln from a CKD sample drawn either as
CKD is exiting the kiln or from bulk
CKD storage.
(b) You must determine the weight
fraction of total CaO and total MgO in
clinker from each kiln using ASTM
C114–07 Standard Test Methods for
Chemical Analysis of Hydraulic Cement
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
44 2000
∗
12 2205
(Eq. H-5)
(incorporated by reference, see § 98.7).
The monitoring must be conducted
monthly for each kiln from a clinker
sample drawn from bulk clinker storage.
(c) The total organic carbon contents
(dry basis) of each raw material must be
determined annually using ASTM
C114–09 Standard Test Methods for
Chemical Analysis of Hydraulic Cement
(incorporated by reference, see § 98.7) or
a similar industry standard practice or
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).
Facilities that opt to use the default total
organic carbon factor provided in
§ 98.83(d)(3), are not required to
monitor for TOC.
(d) The quantity of clinker produced
monthly 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.
(e) The quantity of CKD not recycled
to the kiln by each kiln must be
determined quarterly by direct weight
measurement using the same plant
instruments used for accounting
purposes, such as weigh hoppers, truck
weigh scales, or belt weigh feeders.
(f) The quantity of each category of
raw materials consumed annually by the
PO 00000
Frm 00163
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Sfmt 4700
Non-calcined MgO is MgO that remains
in the CKD in the form of MgCO3 and
MgO in the CKD that entered the kiln as
a non-carbonate species.
(3) CO2 emissions from raw materials.
Calculate CO2 emissions using Equation
H–5 of this section:
facility (e.g., limestone, sand, shale, iron
oxide, and alumina) must be determined
monthly by direct weight measurement
using the same plant instruments used
for accounting purposes, such as weigh
hoppers, truck weigh scales, or belt
weigh feeders.
(g) The monthly non-calcined CaO
and MgO that remains in the clinker in
the form of CaCO3 or that enters the kiln
as a non-carbonate species may be
assumed to be a default value of 0.0 or
may be determined monthly by careful
chemical analysis of feed material and
clinker material from each kiln using
well documented analytical and
calculational methods or the
appropriate industry standard practice.
(h) The quarterly non-calcined CaO
and MgO that remains in the CKD in the
form of CaCO3 or that enters the kiln as
a non-carbonate species may be
assumed to be a default value of 0.0 or
may be determined quarterly by careful
chemical analysis of feed material and
CKD material from each kiln using well
documented analytical and
calculational methods or the
appropriate industry standard practice.
§ 98.85
data.
Procedures for estimating missing
A complete record of all measured
parameters used in the GHG emissions
calculations in § 98.83 is required.
Therefore, whenever a quality-assured
value of a required parameter is
unavailable, a substitute data value for
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.044</MATH>
Where:
CKDCaO = Quarterly total CaO content of CKD
not recycled to the kiln, wt-fraction.
CKDCaO = Quarterly non-calcined CaO
content of CKD not recycled to the kiln,
wt-fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO
= 0.785.
CKDMgO = Quarterly total MgO content of
CKD not recycled to the kiln, wt-fraction.
(Eq. H-4)
ER30OC09.043</MATH>
Where:
CliCaO = Monthly total CaO content of
Clinker, wt-fraction.
ClincCaO = Monthly non-calcined CaO content
of Clinker, wt-fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO
= 0.785.
CliMgO = Monthly total MgO content of
Clinker, wt-fraction.
56421
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
the missing parameter shall be used in
the calculations. The owner or operator
must document and keep records of the
procedures used for all such estimates.
(a) If the CEMS approach is used to
determine combined process and
combustion CO2 emissions, the missing
data procedures in § 98.35 apply.
(b) For CO2 process emissions from
cement manufacturing facilities
calculated according to § 98.83(d), if
data on the carbonate content (of clinker
or CKD), noncalcined content (of clinker
or CKD) or the annual organic carbon
content of raw materials are missing,
facilities must undertake a new analysis.
(c) For each missing value of monthly
clinker production the substitute data
value must be the best available
estimate of the monthly clinker
production based on information used
for accounting purposes, or use the
maximum tons per day capacity of the
system and the number of days per
month.
(d) For each missing value of monthly
raw material consumption the substitute
data value must be the best available
estimate of the monthly raw material
consumption based on information used
for accounting purposes (such as
purchase records), or use the maximum
tons per day raw material throughput of
the kiln and the number of days per
month.
sroberts on DSKD5P82C1PROD with RULES
§ 98.86
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) and (b) of this section,
as appropriate.
(a) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required by § 98.36(e)(2)(vi) and the
information listed in this paragraph(a):
(1) Monthly clinker production from
each kiln at the facility.
(2) Monthly cement production from
each kiln at the facility.
(3) Number of kilns and number of
operating kilns.
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
information listed in this paragraph (b)
for each kiln:
(1) Kiln identification number.
(2) Monthly clinker production from
each kiln.
(3) Monthly cement production from
each kiln.
(4) Number of kilns and number of
operating kilns.
(5) Quarterly quantity of CKD not
recycled to the kiln for each kiln at the
facility.
(6) Monthly fraction of total CaO, total
MgO, non-calcined CaO and non-
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
calcined MgO in clinker for each kiln
(as wt-fractions).
(7) Method used to determine noncalcined CaO and non-calcined MgO in
clinker.
(8) Quarterly fraction of total CaO,
total MgO, non-calcined CaO and noncalcined MgO in CKD not recycled to
the kiln for each kiln (as wt-fractions).
(9) Method used to determine noncalcined CaO and non-calcined MgO in
CKD.
(10) Monthly kiln-specific clinker CO2
emission factors for each kiln (metric
tons CO2/metric ton clinker produced).
(11) Quarterly kiln-specific CKD CO2
emission factors for each kiln (metric
tons CO2/metric ton CKD produced).
(12) Annual organic carbon content of
each raw material (wt-fraction, dry
basis).
(13) Annual consumption of each raw
material (dry basis).
(14) Number of times missing data
procedures were used to determine the
following information:
(i) Clinker production (number of
months).
(ii) Carbonate contents of clinker
(number of months).
(iii) Non-calcined content of clinker
(number of months).
(iv) CKD not recycled to kiln (number
of quarters).
(v) Non-calcined content of CKD
(number of quarters)
(vi) Organic carbon contents of raw
materials (number of times).
(vii) Raw material consumption
(number of months).
§ 98.87
Records that must be retained.
(a) If a CEMS is used to measure CO2
emissions, then you must retain under
this subpart the records required for the
Tier 4 Calculation Methodology in
§ 98.37.
(1) Documentation of monthly
calculated kiln-specific clinker CO2
emission factor.
(2) Documentation of quarterly
calculated kiln-specific CKD CO2
emission factor.
(3) Measurements, records and
calculations used to determine reported
parameters.
(b) If a CEMS is not used to measure
CO2 emissions, then in addition to the
records required by § 98.3(g), you must
retain the records specified in
paragraphs (a) through (b) of this section
for each portland cement manufacturing
facility.
§ 98.88
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
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Subpart I—[Reserved]
Subpart J—[Reserved]
Subpart K—Ferroalloy Production
§ 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.
You must report:
(a) Process CO2 emissions from each
electric arc furnace (EAF) used for the
production of any ferroalloy listed in
§ 98.110.
(b) CO2, CH4, and N2O emissions from
each stationary combustion unit
following the requirements of subpart C
of this part. You must report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources).
§ 98.113
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
EAF using the procedures in either
paragraph (a) or (b) of this section.
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining CEMS
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart the annual process CO2
emissions using the procedure in either
paragraph (b)(1) or (b)(2) of this section.
(1) Calculate and report under this
subpart the annual process CO2
emissions from EAFs by operating and
maintaining a CEMS according to the
Tier 4 Calculation Methodology
specified in § 98.33(a)(4) and the
applicable requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(2) Calculate and report under this
subpart the annual process CO2
emissions from the EAFs using the
carbon mass balance procedure
specified in paragraphs (b)(2)(i) and
(b)(2)(ii) of this section.
E:\FR\FM\30OCR2.SGM
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(i) For each EAF, determine the
annual mass of carbon in each carboncontaining input and output material for
the EAF and estimate annual process
CO2 emissions from the EAF using
Equation K–1 of this section. Carboncontaining input materials include
carbon electrodes and carbonaceous
reducing agents. If you document that a
specific input or output material
44 2000 i
×
× ∑ M reducing agenti × Creducing agenti
12 2205 1
(
E CO2 =
contributes less than 1 percent of the
total carbon into or out of the process,
you do not have to include the material
in your calculation using Equation K–1
of this section.
)
+
44 2000 m
×
× ∑ M electrodem × Celectrodem
12 2205 1
+
44 2000 h
×
× ∑ M oreh × Coreh
12 2205 1
(
)
+
44 2000 j
×
× ∑ M flux j × Cflux j
12 2205 1
)
−
44 2000 k
×
× ∑ M product outgoingk × C product outgoingk
12 2205 1
−
44 2000 l
×
× ∑ M non- product outgoingl × Cnon- product outgoingl
12 2205 1
(
(
Cproductk = Carbon content in alloy product k.
(percent by weight, expressed as a
decimal fraction).
Mnon-product outgoingl = Annual mass of nonproduct outgoing material l removed
from EAF (tons).
Cnon-product outgoingl = Carbon content in nonproduct outgoing material l (percent by
weight, expressed as a decimal fraction).
(ii) Determine the combined annual
process CO2 emissions from the EAFs at
your facility using Equation K–2 of this
section.
k
CO 2 = ∑ E CO 2k
(Eq. K-2)
1
Where:
CO2 = Annual process CO2 emissions from
EAFs at facility used for the production
of any ferroalloy listed in § 98.110
(metric tons).
ECO2k = Annual process CO2 emissions
calculated from EAF k calculated using
Equation K–1 of this section (metric
tons).
k = Total number of EAFs at facility used for
the production of any ferroalloy listed in
§ 98.110.
i
2000
⎛
⎞
× EFproducti ⎟
ECH 4 = ∑ ⎜ M producti ×
2205
⎝
⎠
1
Where:
ECH4 = Annual process CH4 emissions from
an individual EAF (metric tons).
17:39 Oct 29, 2009
)
Jkt 220001
Mproducti = Annual mass of alloy product i
produced in the EAF (tons).
PO 00000
Frm 00165
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)
(c) If GHG emissions from an EAF are
vented through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraph
(b) of this section shall not be used to
calculate process emissions. The owner
or operator shall report under this
subpart the combined stack emissions
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part.
(d) For the EAFs at your facility used
for the production of any ferroalloy
listed in Table K–1 of this subpart, you
must calculate and report the annual
CH4 emissions using the procedure
specified in paragraphs (d)(1) and (2) of
this section.
(1) For each EAF, determine the
annual CH4 emissions using Equation
K–3 of this section.
(Eq. K-3)
2000/2205 = Conversion factor to convert
tons to metric tons.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.047</MATH>
sroberts on DSKD5P82C1PROD with RULES
(Eq. K-1)
ER30OC09.046</MATH>
(
)
ER30OC09.045</MATH>
(
Where:
ECO2 = Annual process CO2 emissions from
an individual EAF (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion factor to convert
tons to metric tons.
Mreducing agenti = Annual mass of reducing
agent i fed, charged, or otherwise
introduced into the EAF (tons).
Creducing agenti = Carbon content in reducing
agent i (percent by weight, expressed as
a decimal fraction).
Melectrodem = Annual mass of carbon electrode
m consumed in the EAF (tons).
Celectrodem = Carbon content of the carbon
electrode m (percent by weight,
expressed as a decimal fraction).
Moreh = Annual mass of ore h charged to the
EAF (tons).
Coreh = Carbon content in ore h (percent by
weight, expressed as a decimal fraction).
Mfluxj = Annual mass of flux material j fed,
charged, or otherwise introduced into
the EAF to facilitate slag formation
(tons).
Cfluxj = Carbon content in flux material j
(percent by weight, expressed as a
decimal fraction).
Mproductk = Annual mass of alloy product k
tapped from EAF (tons).
VerDate Nov<24>2008
56423
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(2) Determine the combined process
CH4 emissions from the EAFs at your
facility using Equation K–4 of this
section:
j
CH 4 = ∑ E CH 4 j
(Eq. K-4)
1
Where:
CH4 = Annual process CH4 emissions from
EAFs at facility used for the production
of ferroalloys listed in Table K–1 of this
subpart (metric tons).
ECH4j = Annual process CH4 emissions from
EAF j calculated using Equation K–3 of
this section (metric tons).
j = Total number of EAFs at facility used for
the production of ferroalloys listed in
Table K–1 of this subpart.
sroberts on DSKD5P82C1PROD with RULES
§ 98.114 Monitoring and QA/QC
requirements.
If you determine annual process CO2
emissions using the carbon mass
balance procedure in § 98.113(b)(2), you
must meet the requirements specified in
paragraphs (a) and (b) of this section.
(a) Determine the annual mass for
each material used for the calculations
of annual process CO2 emissions using
Equation K–1 of this subpart by
summing the monthly mass for the
material determined for each month of
the calendar year. The monthly mass
may be determined using plant
instruments used for accounting
purposes, including either direct
measurement of the quantity of the
material placed in the unit or by
calculations using process operating
information.
(b) For each material identified in
paragraph (a) of this section, you must
determine the average carbon content of
the material consumed, used, or
produced in the calendar year using the
methods specified in either paragraph
(b)(1) or (b)(2) of this section. If you
document that a specific process input
or output contributes less than one
percent of the total mass of carbon into
or out of the process, you do not have
to determine the monthly mass or
annual carbon content of that input or
output.
(1) Information provided by your
material supplier.
(2) Collecting and analyzing at least
three representative samples of the
material inputs and outputs each year.
The carbon content of the material must
be analyzed at least annually using the
standard methods (and their QA/QC
procedures) specified in paragraphs
(b)(2)(i) through (b)(2)(iii) of this
section, as applicable.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(i) ASTM E1941–04, Standard Test
Method for Determination of Carbon in
Refractory and Reactive Metals and
Their Alloys (incorporated by reference,
see § 98.7) for analysis of metal ore and
alloy product.
(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7),
for analysis of carbonaceous reducing
agents and carbon electrodes.
(iii) ASTM C25–06, Standard Test
Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime (incorporated by reference, see
§ 98.7) for analysis of flux materials
such as limestone or dolomite.
§ 98.115 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations in § 98.113 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 as specified in the
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) If you determine CO2 emissions for
the EAFs at your facility using the
carbon mass balance procedure in
§ 98.113(b), 100 percent data availability
is required for the carbon content of the
input and output materials. You must
repeat the test for average carbon
contents of inputs according to the
procedures in § 98.114(b) if data are
missing.
(b) For missing records of the monthly
mass of carbon-containing inputs and
outputs, the substitute data value must
be based on the best available estimate
of the mass of the inputs and outputs
from on all available process data or
data used for accounting purposes, such
as purchase records.
(c) If you are required to calculate CH4
emissions for an EAF at your facility as
specified in § 98.113(d), the estimate is
based an annual quantity of certain
alloy products, so 100 percent data
availability is required.
§ 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 (e) of this
section, as applicable:
(a) Annual facility ferroalloy product
production capacity (tons).
(b) Annual production for each
ferroalloy product (tons) identified in
§ 98.110, as applicable.
PO 00000
(c) Total number of EAFs at facility
used for production of ferroalloy
products reported in paragraph (a)(4) of
this section.
(d) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required by § 98.37 for the Tier 4
Calculation Methodology and the
following information specified in
paragraphs (d)(1) through (d)(3) of this
section.
(1) Annual process CO2 emissions (in
metric tons) from each EAF used for the
production of any ferroalloy listed in
Table K–1 of this subpart (metric tons).
(2) Annual process CH4 emissions (in
metric tons) from each EAF used for the
production of any ferroalloy listed in
Table K–1 of this subpart (metric tons).
(3) Identification number of each EAF.
(e) If a CEMS is not used to measure
CO2 process emissions, and the carbon
mass balance procedure is used to
determine CO2 emissions according to
the requirements in § 98.113(b), then
you must report the following
information specified in paragraphs
(e)(1) through (e)(7) of this section.
(1) Annual process CO2 emissions (in
metric tons) from each EAF used for the
production of any ferroalloy listed in
Table K–1 of this subpart (metric tons).
(3) Identification number for each
material.
(4) Annual material quantity for each
material included for the calculation of
annual process CO2 emissions for each
EAF.
(5) Annual average of the carbon
content determinations for each material
included for the calculation of annual
process CO2 emissions for each EAF
(percent by weight, expressed as a
decimal fraction).
(6) List the method used for the
determination of carbon content for
each material reported in paragraph
(e)(5) of this section (e.g., supplier
provided information, analyses of
representative samples you collected).
(7) If you use the missing data
procedures in § 98.115(b), you must
report how monthly mass of carboncontaining inputs and outputs with
missing data was determined and the
number of months the missing data
procedures were used.
Frm 00166
Fmt 4701
Sfmt 4700
§ 98.117
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 EAF, as
applicable.
(a) If a CEMS is used to measure CO2
emissions according to the requirements
in § 98.113(a), then you must retain
under this subpart the records required
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.048</MATH>
EFproducti = CH4 emission factor for alloy
product i from Table K–1 in this subpart
(kg of CH4 emissions per metric ton of
alloy product i).
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
for the Tier 4 Calculation Methodology
in § 98.37 and the information specified
in paragraphs (a)(1) through (a)(3) of this
section.
(1) Monthly EAF production quantity
for each ferroalloy product (tons).
(2) Number of EAF operating hours
each month.
(3) Number of EAF operating hours in
a calendar year.
(b) If the carbon mass balance
procedure is used to determine CO2
emissions according to the requirements
in § 98.113(b)(2), then you must retain
records for the information specified in
paragraphs (b)(1) through (b)(5) of this
section.
(1) Monthly EAF production quantity
for each ferroalloy product (tons).
(2) Number of EAF operating hours
each month.
(3) Number of EAF operating hours in
a calendar year.
(4) Monthly material quantity
consumed, used, or produced for each
material included for the calculations of
annual process CO2 emissions (tons).
(5) Average carbon content
determined and records of the supplier
provided information or analyses used
for the determination for each material
included for the calculations of annual
process CO2 emissions.
(c) You must keep records that
include a detailed explanation of how
company records of measurements are
used to estimate the carbon input and
output to each EAF, including
documentation of specific input or
output materials excluded from
Equation K–1 of this subpart that
contribute less than 1 percent of the
total carbon into or out of the process.
You also must document the procedures
used to ensure the accuracy of the
56425
measurements of materials fed, charged,
or placed in an EAF 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.
(d) If you are required to calculate
CH4 emissions for the EAF as specified
in § 98.113(d), 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 the CH4 emissions.
§ 98.118
Definitions.
All terms used of this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
TABLE K–1 TO SUBPART K OF PART 98—ELECTRIC ARC FURNACE (EAF) CH4 EMISSION FACTORS
CH4 emission factor
(kg CH4 per metric ton product)
EAF Operation
Alloy product produced in EAF
Batchcharging
Silicon metal ............................................................................................................................................
Ferrosilicon 90% ......................................................................................................................................
Ferrosilicon 75% ......................................................................................................................................
Ferrosilicon 65% ......................................................................................................................................
1.5
1.4
1.3
1.3
Sprinklecharging a
1.2
1.1
1.0
1.0
Sprinklecharging
and
>750 °C b
0.7
0.6
0.5
0.5
a Sprinkle-charging
b Temperature
is charging intermittently every minute.
measured in off-gas channel downstream of the furnace hood.
§ 98.142
Subpart L—[Reserved]
(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
§ 98.143
Subpart M—[Reserved]
Subpart N—Glass Production
§ 98.140
sroberts on DSKD5P82C1PROD with RULES
GHGs to report.
You must report:
(a) CO2 process emissions from each
continuous glass melting furnace.
(b) CO2 combustion emissions from
each continuous glass melting furnace.
(c) CH4 and N2O combustion
emissions from each continuous glass
melting furnace. You must calculate and
report these emissions under subpart C
of this part (General Stationary Fuel
Combustion Sources) by following the
requirements of subpart C.
(d) CO2, CH4, and N2O emissions from
each stationary fuel combustion unit
other than continuous glass melting
furnaces. You must report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
Definition of the source category.
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).
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17:39 Oct 29, 2009
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Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
continuous glass melting furnace using
the procedure in paragraphs (a) and (b)
of this section.
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(a) For each continuous glass melting
furnace that meets the conditions
specified in § 98.33(b)(4)(ii) or (iii), you
must calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
and maintaining a CEMS to measure
CO2 emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(b) For each continuous glass melting
furnace that is not subject to the
requirements in paragraph (a) of this
section, calculate and report the process
and combustion CO2 emissions from the
glass melting furnace by using either the
procedure in paragraph (b)(1) of this
section or the procedure in paragraphs
(b)(2) through (b)(7) of this section,
except as specified in paragraph (c) of
this section.
(1) Calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
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separately using the procedures
specified in paragraphs (b)(2)(i) through
(b)(2)(vi) of this section.
(i) For each carbonate-based raw
material charged to the furnace, obtain
from the supplier of the raw material the
carbonate-based mineral mass fraction.
(ii) Determine the quantity of each
carbonate-based raw material charged to
the furnace.
E CO 2 =
Where:
ECO2 = Process emissions of CO2 from the
furnace (metric tons).
n = Number of carbonate-based raw materials
charged to furnace.
MFi = Annual average mass fraction of
carbonate-based mineral i in carbonatebased raw material i (percentage,
expressed as a decimal).
Mi = Annual amount of carbonate-based raw
material i charged to furnace (tons).
2000/2205 = Conversion factor to convert
tons to metric tons.
EFi = Emission factor for carbonate-based raw
material i (metric ton CO2 per metric ton
carbonate-based raw material as shown
in Table N–1 to this subpart).
Fi = Fraction of calcination achieved for
carbonate-based raw material i, assumed
to be equal to 1.0 (percentage, expressed
as a decimal).
(v) You must calculate the total
process CO2 emissions from continuous
glass melting furnaces at the facility
using Equation N–2 of this section:
CO 2 =
k
∑ ECO2i
(Eq. N-2)
i =1
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2 = Annual process CO2 emissions from
glass manufacturing facility (metric
tons).
ECO2i = Annual CO2 emissions from glass
melting furnace i (metric tons).
k = Number of continuous glass melting
furnaces.
(vi) Calculate and report under
subpart C of this part (General
Stationary Fuel Combustion Sources)
the combustion CO2 emissions in the
glass furnace according to the applicable
requirements in subpart C.
(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 must measure annual amounts
of carbonate-based raw materials
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17:39 Oct 29, 2009
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n
⎛
2000 ⎞
∑ MFi i ⎜ Mi i 2205 ⎟ i EFi i Fi
⎠
⎝
(Eq. N-1)
i =1
charged to each continuous glass
melting furnace from monthly
measurements using plant instruments
used for accounting purposes, such as
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) You must measure carbonatebased mineral mass fractions 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 ASTM D3682–01
(Reapproved 2006) Standard Test
Method for Major and Minor Elements
in Combustion Residues from Coal
Utilization Processes (incorporated by
reference, see § 98.7).
(c) You must determine the annual
average mass fraction for the carbonatebased mineral in each carbonate-based
raw material by calculating an
arithmetic average of the monthly data
obtained from raw material suppliers or
sampling and chemical analysis.
(d) You must determine on an annual
basis the calcination fraction for each
carbonate consumed based on sampling
and chemical analysis using an industry
consensus standard. This chemical
analysis must be conducted using an xray fluorescence test or other enhanced
testing method published by an industry
consensus standards organization (e.g.,
ASTM, ASME, API, etc.).
§ 98.145 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations is required (e.g., carbonate
raw materials consumed, etc.). If the
monitoring and quality assurance
procedures in § 98.144 cannot be
followed and data is missing, you must
use the most appropriate of the missing
data procedures in paragraphs (a) and
(b) of this section. You must document
PO 00000
(iii) Apply the appropriate emission
factor for each carbonate-based raw
material charged to the furnace, as
shown in Table N–1 to this subpart.
(iv) Use Equation N–1 of this section
to calculate process mass emissions of
CO2 for each furnace:
Frm 00168
Fmt 4701
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and keep records of the procedures used
for all such missing value estimates.
(a) For missing data on the monthly
amounts of carbonate-based raw
materials charged to any continuous
glass melting furnace use the best
available estimate(s) of the parameter(s),
based on all available process data or
data used for accounting purposes, such
as purchase records.
(b) For missing data on the mass
fractions of carbonate-based minerals in
the carbonate-based raw materials
assume that the mass fraction of each
carbonate based mineral is 1.0.
§ 98.146
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) and (b) of this section,
as applicable.
(a) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required under § 98.37 for the Tier 4
Calculation Methodology and the
following information specified in
paragraphs (a)(1) and (a)(2) of this
section:
(1) Annual quantity of each carbonatebased raw material charged to each
continuous glass melting furnace and
for all furnaces combined (tons).
(2) Annual quantity of glass produced
(tons).
(b) If a CEMS is not used to determine
CO2 emissions from continuous glass
melting furnaces, and process CO2
emissions are calculated according to
the procedures specified in § 98.143(b),
then you must report the following
information as specified in paragraphs
(b)(1) through (b)(9) of this section:
(1) Annual process emissions of CO2
(metric tons) for each continuous glass
melting furnace and for all furnaces
combined.
(2) Annual quantity of each carbonatebased raw material charged (tons) to
each continuous glass melting furnace
and for all furnaces combined.
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ER30OC09.050</MATH>
and maintaining a CEMS to measure
CO2 emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(2) Calculate and report the process
and combustion CO2 emissions
ER30OC09.049</MATH>
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sroberts on DSKD5P82C1PROD with RULES
§ 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), (b),
and (c) of this section.
(a) If a CEMS is used to measure
emissions, then you must retain the
records required under § 98.37 for the
Tier 4 Calculation Methodology and the
following information specified in
paragraphs (a)(1) and (a)(2) of this
section:
(1) Monthly glass production rate for
each continuous glass melting furnace
(tons).
(2) Monthly amount of each
carbonate-based raw material charged to
each continuous glass melting furnace
(tons).
(b) If process CO2 emissions are
calculated according to the procedures
specified in § 98.143(b), you must retain
the records in paragraphs (b)(1) through
(b)(5) of this section.
(1) Monthly glass production rate for
each continuous glass melting furnace
(metric tons).
(2) Monthly amount of each
carbonate-based raw material charged to
each continuous glass melting furnace
(metric tons).
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(3) Data on carbonate-based mineral
mass fractions provided by the raw
material supplier for all raw materials
consumed annually and included in
calculating process emissions in
Equation N–1 of this subpart.
(4) 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, including the data
specified in paragraphs (b)(4)(i) through
(b)(4)(v) of this section.
(i) Date of test.
(ii) Method(s), and any variations of
the methods, used in the analyses.
(iii) Mass fraction of each sample
analyzed.
(iv) Relevant calibration data for the
instrument(s) used in the analyses.
(v) Name and address of laboratory
that conducted the tests.
(5) The fraction of calcination
achieved for each carbonate-based raw
material (percentage, expressed as a
decimal), if a value other than 1.0 is
used to calculate process mass
emissions of CO2.
(c) 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 TO SUBPART N OF PART
98—CO2 EMISSION FACTORS FOR
CARBONATE-BASED RAW MATERIALS
Carbonate-based
raw material—mineral
Limestone—CaCO3 ..................
Dolomite—CaMg(CO3)2 ............
Sodium carbonate/soda ash—
Na2CO3 .................................
CO2 emission factor a
0.440
0.477
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.
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§ 98.151
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains an HCFC–22 production or
HFC–23 destruction process and the
facility meets the requirements of either
§ 98.2(a)(1) or (a)(2).
§ 98.152
GHGs to report.
(a) You must report under subpart C
of this part (General Stationary Fuel
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit following the
requirements of subpart C.
(b) You must report HFC–23
emissions from HCFC–22 production
processes and HFC–23 destruction
processes.
§ 98.153
Calculating GHG emissions.
(a) The 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 weekly (or more
frequent) HFC–23 concentration
measurement (which may be the average
of more frequent concentration
measurements) by the weekly (or more
frequent) mass flow of the combined
stream of HFC–23 and the other
product. To estimate annual HFC–23
production, sum the weekly (or more
frequent) estimates of the quantities of
HFC–23 produced over the year. This
calculation is summarized in Equation
O–1 of this section:
G23 =
n
∑ c23 ∗ Fp ∗ 10−3
(Eq. O -1)
p =1
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.
(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 weekly (or more
frequent) measurement of the HFC–23
concentration and the weekly (or more
frequent) measurement of the other
product concentration by the weekly (or
more frequent) mass produced of the
other product. To estimate annual HFC–
23 production, sum the weekly (or more
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.051</MATH>
(3) Annual quantity of glass produced
(tons) from each continuous glass
melting furnace and from all furnaces
combined.
(4) Carbonate-based mineral mass
fraction (percentage, expressed as a
decimal) for each carbonate-based raw
material charged to a continuous glass
melting furnace.
(5) 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, as specified in
paragraphs (b)(5)(i) through (b)(5)(iii) of
this section.
(i) Date of test.
(ii) Method(s) and any variations used
in the analyses.
(iii) Mass fraction of each sample
analyzed.
(6) The fraction of calcination
achieved for each carbonate-based raw
material, if a value other than 1.0 is
used to calculate process mass
emissions of CO2.
(7) Method used to determine fraction
of calcination (percentage, expressed as
a decimal).
(8) Total number of continuous glass
melting furnaces.
(9) The number of times in the
reporting year that missing data
procedures were followed to measure
monthly quantities of carbonate-based
raw materials any continuous glass
melting furnace or mass fraction of the
carbonate-based minerals (months).
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
c22 = Fraction HCFC–22 by weight in HCFC–
22/HFC–23 stream.
P22 = Mass of HCFC–22 produced over the
period p (kg), calculated using Equation
O–3 of this section.
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.
(Eq. O - 2)
Where:
G23 = Mass of HFC–23 generated annually
(metric tons).
c23 = Fraction HFC–23 by weight in HCFC–
22/HFC–23 stream.
(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 )
(Eq. O-3)
Where:
P22 = Mass of HCFC–22 produced over the
period p (kg).
E23 = G23 − ( S23 + OD23 + D23 + I 23 )
Where:
E23 = Mass of HFC–23 emitted annually
(metric tons).
G23 = Mass of HFC–23 generated annually
(metric tons).
S23 = Mass of HFC–23 sent off site for sale
annually (metric tons).
OD23 = Mass of HFC–23 sent off site for
destruction (metric tons).
D23 = Mass of HFC–23 destroyed on site
(metric tons).
I23 = Increase in HFC–23 inventory = HFC–
23 in storage at end of year—HFC–23 in
storage at beginning of year (metric tons).
EL =
Where:
E23 = Mass of HFC–23 emitted annually
(metric tons).
EL = Mass of HFC–23 emitted annually from
equipment leaks, calculated using
sroberts on DSKD5P82C1PROD with RULES
(1) 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:
(Eq. O-6)
p =1 t
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).
Jkt 220001
Equation O–6 of this section (metric
tons).
EPV = Mass of HFC–23 emitted annually from
process vents, calculated using Equation
O–7 of this section (metric tons).
ED = Mass of HFC–23 emitted annually from
thermal oxidizer (metric tons), calculated
using Equation O–8 of this section.
n
greater than or equal to 10,000 ppmv as
determined according to § 98.154(i).
FLt = The applicable leak rate specified in
Table O–1 of this subpart 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(j).
p = One hour.
n
⎛ PR p
EPV = ∑ ERT * ⎜
⎝ PRT
p =1
17:39 Oct 29, 2009
(Eq. O-5)
∑ ∑ c23 ∗ ( FGt ∗ NGt + FLt ∗ N Lt ) ∗ 10−3
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 of this subpart 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
VerDate Nov<24>2008
(Eq. O- 4)
(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
(c) For HCFC–22 production facilities
that do not use a thermal oxidizer or
that 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:
ER30OC09.058</MATH>
⎠
⎞
−3
⎟ * l p ∗ 10
⎠
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(2) The mass of HFC–23 emitted
annually from process vents (for use in
Equation O–5 of this section) shall be
estimated by using Equation O–7 of this
section:
(Eq. O-7)
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.
PO 00000
n = Number of hours during the year during
which equipment contained HFC–23.
t = Equipment type and service as specified
in Table O–1 of this subpart .
10¥3 = Factor converting kg to metric tons.
(3) The total mass of HFC–23 emitted
from destruction devices shall be
estimated by using Equation O–8 of this
section:
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ED = FD − D23
30OCR2
(Eq. O-8)
ER30OC09.057</MATH>
p =1 ⎝ 22
ER30OC09.056</MATH>
⎞
ER30OC09.055</MATH>
⎛c
ER30OC09.054</MATH>
n
∑ ⎜ c23 ⎟ ∗ P22 ∗ 10−3
ER30OC09.053</MATH>
G23 =
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
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).
ER30OC09.052</MATH>
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.
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).
D23 = Mass of HFC–23 destroyed annually
(metric tons).
(4) For facilities that destroy HFC–23,
the total mass of HFC–23 destroyed
shall be estimated by using Equation O–
9 of this section:
D 23 = FD ∗ DE
(Eq. O-9)
Where:
D23 = 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).
sroberts on DSKD5P82C1PROD with RULES
§ 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 weekly 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 at least weekly 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.
(c) The mass of HCFC–22 or HCl
coming out of the production process
shall be measured at least weekly 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 (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. If the mass in paragraph (c) of
this section is measured by weighing
containers that include returned heels
as well as newly produced fluorinated
GHGs, the returned heels shall be
considered used fluorinated HCFC–22
for purposes of this paragraph (d) of this
section and § 98.153(b).
(e) The loss factor LF in Equation O–
3 of this subpart for the mass of HCFC–
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17:39 Oct 29, 2009
Jkt 220001
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 sent off site
for sale shall be measured at least
weekly (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 weekly (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 weekly 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 masses of HFC–23 in storage
at the beginning and end of the year
shall be measured 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.
(i) 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.
(j) The number of sources of
equipment type t with screening values
less than 10,000 ppmv shall be the
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.
(k) The mass of HFC–23 emitted from
process vents shall be estimated at least
monthly by incorporating the results of
the most recent emissions test into
Equation O–6 of this subpart. HCFC–22
production facilities that use a thermal
PO 00000
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Fmt 4701
Sfmt 4700
56429
oxidizer connected to the HCFC–22
production equipment shall conduct
emissions tests at process vents at least
once every five years or after significant
changes to the process. 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.
(l) For purposes of Equation O–9 of
this subpart, the destruction efficiency
must be equated to the destruction
efficiency determined during a new or
previous performance test of the
destruction device. HFC–23 destruction
facilities shall conduct annual
measurements of HFC–23
concentrations at the outlet of the
thermal oxidizer in accordance with
EPA Method 18 at 40 CFR part 60,
appendix A–6. Three samples shall be
taken under conditions that are typical
for the production process and
destruction device at the facility, and
the average concentration of HFC–23
shall be determined. The sensitivity of
the concentration measurement shall be
sufficient to detect an outlet
concentration equal to or less than the
outlet concentration determined in the
destruction efficiency performance test.
If the concentration measurement
indicates that the HFC–23 concentration
is less than or equal to that measured
during the performance test that is the
basis for the destruction efficiency,
continue to use the previously
determined destruction efficiency. If the
concentration measurement indicates
that the HFC–23 concentration is greater
than that measured during the
performance test that is the basis for the
destruction efficiency, facilities shall
either:
(1) Substitute the higher HFC–23
concentration for that measured during
the destruction efficiency performance
test and calculate a new destruction
efficiency, or
(2) Estimate the mass emissions of
HFC–23 from the destruction device
based on the measured HFC–23
concentration and volumetric flow rate
determined by measurement of
volumetric flow rate using EPA Method
2, 2A, 2C,2D, or 2F at 40 CFR part 60,
appendix A–1, or Method 26 at 40 CFR
part 60, appendix A–2. Determine the
mass rate of HFC–23 into the
destruction device by measuring the
HFC–23 concentration and volumetric
flow rate at the inlet or by a metering
device for HFC–23 sent to the device.
Determine a new destruction efficiency
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
sroberts on DSKD5P82C1PROD with RULES
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
based on the mass flow rate of HFC–23
into and out of the destruction device.
(m) 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.
(n) The mass of HFC–23 fed into the
destruction device shall be measured at
least weekly using flow meters, 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 weekly 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.
(o) In their estimates of the mass of
HFC–23 destroyed, 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.
(p) Calibrate all flow meters, weigh
scales, and combinations of volumetric
and density measures using NISTtraceable standards and suitable
methods published by a consensus
standards organization (e.g., ASTM,
ASME, ISO, or others). Recalibrate all
flow meters, weigh scales, and
combinations of volumetric and density
measures at the minimum frequency
specified by the manufacturer.
(q) 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 Method 205 at
40 CFR part 51, appendix M) with
known HFC–23 concentrations that are
in the same range (fractions by mass) as
the process samples.
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17:39 Oct 29, 2009
Jkt 220001
§ 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
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 where such a
measurement is available. 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. Where a
secondary mass measurement is not
available, the substitute value of the
parameter shall be an estimate based on
a related parameter. For example, if a
flowmeter measuring the mass fed into
a destruction device is rendered
inoperable, then the mass fed into the
destruction device may be estimated
using the production rate and the
previously observed relationship
between the production rate and the
mass flow rate into the destruction
device.
§ 98.156
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), the HCFC–22
production facility shall report the
following information at the facility
level:
(1) Annual mass of HCFC–22
produced in metric tons.
(2) Loss Factor used to account for the
loss of HCFC– 22 upstream of the
measurement.
(3) Annual mass of reactants fed into
the process in metric tons of reactant.
(4) 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
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Frm 00172
Fmt 4701
Sfmt 4700
are permanently removed from the
process.
(5) The method for tracking startups,
shutdowns, and malfunctions and HFC–
23 generation/emissions during these
events.
(6) 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.
(7) Annual mass of the HFC–23
generated in metric tons.
(8) Annual mass of any HFC–23 sent
off site for sale in metric tons.
(9) Annual mass of any HFC–23 sent
off site for destruction in metric tons.
(10) Mass of HFC–23 in storage at the
beginning and end of the year, in metric
tons.
(11) Annual mass of HFC–23 emitted
in metric tons.
(12) Annual mass of HFC–23 emitted
from equipment leaks in metric tons.
(13) Annual mass of HFC–23 emitted
from process vents in metric tons.
(b) In addition to the information
required by § 98.3(c), facilities that
destroy HFC–23 shall report the
following for each HFC–23 destruction
process:
(1) Annual mass of HFC–23 fed into
the thermal oxidizer.
(2) Annual mass of HFC–23
destroyed.
(3) Annual mass of HFC–23 emitted
from the thermal oxidizer.
(c) 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) Flow rate of HFC–23 being fed into
the destruction device in kg/hr.
(2) Concentration (mass fraction) of
HFC–23 at the outlet of the destruction
device.
(3) Flow rate at the outlet of the
destruction device in kg/hr.
(d) Emission rate calculated from
paragraphs (c)(2) and (3) of this section
in kg/hr.
(e) HFC–23 destruction facilities shall
submit a one-time report including the
following information for each the
destruction process:
(1) Destruction efficiency (DE).
(2) The methods used to determine
destruction efficiency.
(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.
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
§ 98.157
Records that must be retained.
(a) In addition to the data required by
§ 98.3(g), HCFC–22 production facilities
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(p) and
(q).
(b) In addition to the data required by
§ 98.3(g), the HFC–23 destruction
facilities shall retain the following
records:
(1) Records documenting their onetime and annual reports in § 98.156(b)
through (d).
(2) Records documenting the initial
and periodic calibration of the gas
chromatographs, weigh scales,
56431
volumetric and density measurements,
and flowmeters used to measure the
quantities reported under this subpart,
including the industry standard practice
or manufacturer directions used for
calibration pursuant to § 98.154(p) and
(q).
§ 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.
TABLE O–1 TO SUBPART O OF PART 98—EMISSION FACTORS FOR EQUIPMENT LEAKS
Emission factor
(kg/hr/source)
Service
Valves ...............................................................................
Valves ...............................................................................
Pump seals .......................................................................
Compressor seals .............................................................
Pressure relief valves .......................................................
Connectors ........................................................................
Open-ended lines .............................................................
§ 98.162
Subpart P—Hydrogen Production
§ 98.160
Definition of the source category.
(a) A hydrogen production source
category consists of facilities that
produce hydrogen gas sold as a product
to other entities.
(b) This source category comprises
process units that produce hydrogen by
reforming, gasification, oxidation,
reaction, or other transformations of
feedstocks.
(c) This source category includes
merchant hydrogen production facilities
located within a petroleum refinery if
they are not owned by, or under the
direct control of, the refinery owner and
operator.
§ 98.161
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 (a)(2).
Gas ...................................................................................
Light liquid ........................................................................
Light liquid ........................................................................
Gas ...................................................................................
Gas ...................................................................................
All ......................................................................................
All ......................................................................................
GHGs to report.
You must report:
(a) CO2 process emissions from each
hydrogen production process unit.
(b) CO2, CH4 and N2O combustion
emissions from each hydrogen
production process unit. You must
calculate and report these combustion
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
(c) CO2, CH4, and N2O emissions from
each stationary combustion unit other
than hydrogen production process units.
You must calculate and report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
(d) For CO2 collected and transferred
off site, you must follow the
requirements of subpart PP of this part.
§ 98.163
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
sroberts on DSKD5P82C1PROD with RULES
⎛ k 44
MW ⎞
CO2 = ⎜ ∑
∗ Fdstkn ∗ CCn ∗
⎟ ∗ 0.001
⎜
MVC ⎟
⎝ n =1 12
⎠
Where:
CO2 = Annual CO2 process emissions arising
from fuel and feedstock consumption
(metric tons/yr).
Fdstkn = Volume of the gaseous fuel and
feedstock used in month n (scf (at
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17:39 Oct 29, 2009
Jkt 220001
standard conditions of 68 °F and
atmospheric pressure) of fuel and
feedstock).
CCn = Average carbon content of the gaseous
fuel and feedstock, from the results of
PO 00000
≥10,000
ppmv
Frm 00173
Fmt 4701
Sfmt 4700
0.0782
0.0892
0.243
1.608
1.691
0.113
0.01195
<10,000
ppmv
0.000131
0.000165
0.00187
0.0894
0.0447
0.0000810
0.00150
hydrogen production process unit using
the procedures specified in either
paragraph (a) or (b) of this section.
(a) Continuous Emissions Montoring
Systems (CEMS). Calculate and report
under this subpart the process CO2
emissions by operating and maintaining
CEMS according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(b) Fuel and feedstock material
balance approach. Calculate and report
process CO2 emissions as the sum of the
annual emissions associated with each
fuel and feedstock used for hydrogen
production by following paragraphs
(b)(1) through (b)(3) of this section.
(1) Gaseous fuel and feedstock. You
must calculate the annual CO2 process
emissions from gaseous fuel and
feedstock according to Equation P–1 of
this section:
(Eq. P-1)
one or more analyses for month n (kg
carbon per kg of fuel and feedstock).
MW = Molecular weight of the gaseous fuel
and feedstock (kg/kg-mole).
E:\FR\FM\30OCR2.SGM
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ER30OC09.060</MATH>
Equipment type
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to
carbon. 0.001 = Conversion factor from
kg to metric tons.
(2) Liquid fuel and feedstock. You
must calculate the annual CO2 process
Where:
CO2 = Annual CO2 emissions arising from
fuel and feedstock consumption (metric
tons/yr).
Fdstkn = Volume of the liquid fuel and
feedstock used in month n (gallons of
fuel and feedstock).
CCn = Average carbon content of the liquid
fuel and feedstock, from the results of
one or more analyses for month n (kg
carbon per gallon of fuel and feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to
carbon.
⎛ k 44
⎞
CO2 = ⎜ ∑
∗ Fdstkn ∗ CCn ⎟ ∗ 0.001
⎜
⎟
⎝ n =1 12
⎠
Where:
CO2 = Annual CO2 emissions from fuel and
feedstock consumption in metric tons
per month (metric tons/yr).
Fdstkn = Mass of solid fuel and feedstock
used in month n (kg of fuel and
feedstock).
CCn = Average carbon content of the solid
fuel and feedstock, from the results of
one or more analyses for month n (kg
carbon per kg of fuel and feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.001 = Conversion factor from kg to metric
tons.
sroberts on DSKD5P82C1PROD with RULES
(c) If GHG emissions from a hydrogen
production process unit are vented
through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraph
(b) of this section shall not be used to
calculate process emissions. The owner
or operator shall report under this
subpart the combined stack emissions
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
§ 98.164 Monitoring and QA/QC
requirements.
The GHG emissions data for hydrogen
production process units must be
quality-assured as specified in
paragraphs (a) or (b) of this section, as
appropriate for each process unit:
17:39 Oct 29, 2009
Jkt 220001
(Eq. P- 2)
Frm 00174
Fmt 4701
Sfmt 4700
(3) Solid fuel and feedstock. You must
calculate the annual CO2 process
emissions from solid fuel and feedstock
according to Equation P–3 of this
section:
(Eq. P-3)
(a) If a CEMS is used to measure GHG
emissions, then the facility must comply
with the monitoring and QA/QC
procedures specified in § 98.34(c).
(b) If a CEMS is not used to measure
GHG emissions, then you must:
(1) Calibrate all oil and gas flow
meters (except for gas billing meters),
solids weighing equipment, and oil tank
drop measurements (if used to
determine liquid fuel and feedstock use
volume) according to the calibration
accuracy requirements in § 98.3(i) of
this part.
(2) Determine the carbon content and
the molecular weight annually of
standard gaseous hydrocarbon fuels and
feedstocks having consistent
composition (e.g., natural gas). For other
gaseous fuels and feedstocks (e.g.,
biogas, refinery gas, or process gas),
weekly sampling and analysis is
required to determine the carbon
content and molecular weight of the fuel
and feedstock.
(3) Determine the carbon content of
fuel oil, naphtha, and other liquid fuels
and feedstocks at least monthly, except
annually for standard liquid
hydrocarbon fuels and feedstocks
having consistent composition, or upon
delivery for liquid fuels delivered by
bulk transport (e.g., by truck or rail).
(4) Determine the carbon content of
coal, coke, and other solid fuels and
feedstocks at least monthly, except
annually for standard solid hydrocarbon
fuels and feedstocks having consistent
composition, or upon delivery for solid
fuels delivered by bulk transport (e.g.,
by truck or rail).
PO 00000
0.001 = Conversion factor from kg to metric
tons.
(5) You must use the following
applicable methods to determine the
carbon content for all fuels and
feedstocks, and molecular weight of
gaseous fuels and feedstocks.
(i) ASTM D1945–03 Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(ii) ASTM D1946–90 (Reapproved
2006), Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference, see § 98.7).
(iii) ASTM D2013–07 Standard
Practice of Preparing Coal Samples for
Analysis (incorporated by reference, see
§ 98.7).
(iv) ASTM D2234/D2234M–07
Standard Practice for Collection of a
Gross Sample of Coal (incorporated by
reference, see § 98.7).
(v) ASTM D2597–94 (Reapproved
2004) Standard Test Method for
Analysis of Demethanized Hydrocarbon
Liquid Mixtures Containing Nitrogen
and Carbon Dioxide by Gas
Chromatography (incorporated by
reference, see § 98.7).
(vi) ASTM D3176–89 (Reapproved
2002), Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated
by reference, see § 98.7).
(vii) ASTM D3238–95 (Reapproved
2005), Standard Test Method for
Calculation of Carbon Distribution and
Structural Group Analysis of Petroleum
Oils by the n-d-M Method (incorporated
by reference, see § 98.7).
(viii) ASTM D4057–06 Standard
Practice for Manual Sampling of
Petroleum and Petroleum Products
(incorporated by reference, see § 98.7).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.062</MATH>
⎛ k 44
⎞
CO2 = ⎜ ∑
∗ Fdstkn ∗ CCn ⎟ ∗ 0.001
⎜
⎟
⎝ n =1 12
⎠
VerDate Nov<24>2008
emissions from liquid fuel and
feedstock according to Equation P–2 of
this section:
ER30OC09.061</MATH>
56432
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(ix) ASTM D4177–95 (Reapproved
2005) Standard Practice for Automatic
Sampling of Petroleum and Petroleum
Products (incorporated by reference, see
§ 98.7).
(x) ASTM D5291–02 (Reapproved
2007), Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants (incorporated
by reference, see § 98.7).
(xi) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
(xii) ASTM D6609–08 Standard Guide
for Part-Stream Sampling of Coal
(incorporated by reference, see § 98.7).
(xiii) ASTM D6883–04 Standard
Practice for Manual Sampling of
Stationary Coal from Railroad Cars,
Barges, Trucks, or Stockpiles
(incorporated by reference, see § 98.7).
(xiv) ASTM D7430–08ae1 Standard
Practice for Mechanical Sampling of
Coal (incorporated by reference, see
§ 98.7).
(xv) ASTM UOP539–97 Refinery Gas
Analysis by Gas Chromatography
(incorporated by reference, see § 98.7).
(xvi) GPA 2261–00 Analysis for
Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography
(incorporated by reference, see § 98.7).
(xvii) ISO 3170: Petroleum Liquids—
Manual sampling—Third Edition
(incorporated by reference, see § 98.7).
(xviii) ISO 3171: Petroleum Liquids—
Automatic pipeline sampling—Second
Edition (incorporated by reference, see
§ 98.7).
(c) For units using the calculation
methodologies described in this section,
the records required under § 98.3(g)
must include both the company records
and a detailed explanation of how
company records are used to estimate
the following:
(1) Fuel and feedstock consumption,
when solid fuel and feedstock is
combusted and a CEMS is not used to
measure GHG emissions.
(2) 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.
(3) Sorbent usage, if the methodology
in § 98.33(d) is used to calculate CO2
emissions from sorbent.
(d) The owner or operator must
document the procedures used to ensure
the accuracy of the estimates of fuel and
feedstock usage and sorbent usage (as
applicable) in paragraph (b) of this
section, including, but not limited to,
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17:39 Oct 29, 2009
Jkt 220001
calibration of weighing equipment, fuel
and feedstock flow meters, 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.
§ 98.165 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 must be used in
the calculations as specified in
paragraphs (a), (b), and (c) of this
section:
(a) For each missing value of the
monthly fuel and feedstock
consumption, the substitute data value
must be the best available estimate of
the fuel and feedstock consumption,
based on all available process data (e.g.,
hydrogen production, electrical load,
and operating hours). You must
document and keep records of the
procedures used for all such estimates.
(b) For each missing value of the
carbon content or molecular weight of
the fuel and feedstock, the substitute
data value must be the arithmetic
average of the quality-assured values of
carbon contents or molecular weight of
the fuel and feedstock immediately
preceding and immediately following
the missing data incident. If no qualityassured data on carbon contents or
molecular weight of the fuel and
feedstock are available prior to the
missing data incident, the substitute
data value must be the first qualityassured value for carbon contents or
molecular weight of the fuel and
feedstock obtained after the missing
data period. You must document and
keep records of the procedures used for
all such estimates.
(c) For missing CEMS data, you must
use the missing data procedures in
§ 98.35.
§ 98.166
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as appropriate:
(a) If a CEMS is used to measure CO2
emissions, then you must report the
relevant information required under
§ 98.36 for the Tier 4 Calculation
Methodology and the following
information in this paragraph (a):
(1) Unit identification number and
annual CO2 process emissions.
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56433
(2) Annual quantity of hydrogen
produced (metric tons) for each process
unit and for all units combined.
(3) Annual quantity of ammonia
produced (metric tons), if applicable, for
each process unit and for all units
combined.
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
following information for each hydrogen
production process unit:
(1) Unit identification number and
annual CO2 process emissions.
(2) Monthly consumption of each fuel
and feedstock used for hydrogen
production and its type (scf of gaseous
fuels and feedstocks, gallons of liquid
fuels and feedstocks, kg of solid fuels
and feedstocks).
(3) Annual quantity of hydrogen
produced (metric tons).
(4) Annual quantity of ammonia
produced, if applicable (metric tons).
(5) Monthly analyses of carbon
content for each fuel and feedstock used
in hydrogen production (kg carbon/kg of
gaseous and solid fuels and feedstocks,
(kg carbon per gallon of liquid fuels and
feedstocks).
(6) Monthly analyses of the molecular
weight of gaseous fuels and feedstocks
(kg/kg-mole) used, if any.
(c) Quarterly quantity of CO2 collected
and transferred off site in either gas,
liquid, or solid forms (kg), following the
requirements of subpart PP of this part.
(d) Annual quantity of carbon other
than CO2 collected and transferred off
site in either gas, liquid, or solid forms
(kg carbon).
§ 98.167
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 (b) of this section for each
hydrogen production facility.
(a) If a CEMS is used to measure CO2
emissions, then you must retain under
this subpart the records required for the
Tier 4 Calculation Methodology in
§ 98.37.
(b) If a CEMS is not used to measure
CO2 emissions, then you must retain
records of all analyses and calculations
conducted as listed in §§ 98.166(b), (c),
and (d).
§ 98.168
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
E:\FR\FM\30OCR2.SGM
30OCR2
56434
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
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 under subpart C
of this part (General Stationary Fuel
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit following the
requirements of subpart C except for
flares. Stationary combustion units
include, but are not limited to, byproduct recovery coke oven battery
combustion stacks, blast furnace stoves,
CO2 =
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
taconite indurating furnace, basic
oxygen furnace, non-recovery coke oven
battery, sinter process, EAF, argonoxygen decarburization vessel, and
direct reduction furnace using the
procedures in either paragraph (a) or (b)
of this section. Calculate and report the
MW
44 ⎡
⎤
∗ ( Fs ) ∗ C sf + Fg ∗ C gf ∗
∗ 0.001 + ( Fl ) ∗ Clf ∗ 0.001 + ( O ) ∗ ( Co ) − ( P ) ∗ C p − ( R ) ∗ ( CR ) ⎥
MVC
12 ⎢
⎣
⎦
( ) ( ) ( )
Where:
CO2 = Annual CO2 mass emissions from the
taconite indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fs) = Annual mass of the solid fuel
combusted (metric tons).
(Csf) = Carbon content of the solid fuel, from
the fuel analysis (percent by weight,
expressed as a decimal fraction, e.g.,
95% = 0.95).
(Fg) = Annual volume of the gaseous fuel
combusted (scf).
(Cgf) = Average carbon content of the gaseous
fuel, from the fuel analysis results (kg C
per kg of fuel).
sroberts on DSKD5P82C1PROD with RULES
§ 98.173
CO2 =
( )
( )
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.
(Fl) = Annual volume of the liquid fuel
combusted (gallons).
(Clf) = Carbon content of the liquid fuel, from
the fuel analysis results (kg C per gallon
of fuel).
(O) = Annual mass of greenball (taconite)
pellets fed to the furnace (metric tons).
(C0) = Carbon content of the greenball
(taconite) pellets, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(
(ii) For basic oxygen process furnaces,
estimate CO2 emissions using Equation
Q–2 of this section.
)
(
17:39 Oct 29, 2009
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)
(Eq. Q-1)
(P) = Annual mass of fired pellets produced
by the furnace (metric tons).
(Cp) = Carbon content of the fired pellets,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
44 ⎡
∗ ( Iron ) ∗ ( C Iron ) + ( Scrap ) ∗ CScrap + ( Flux ) ∗ ( CFlux )
12 ⎣
+ ( Carbon ) ∗ ( CCarbon ) − ( Steel ) ∗ ( CSteel ) − ( Slag ) ∗ CSlag
g
VerDate Nov<24>2008
annual process CO2 emissions from the
coke pushing process according to
paragraph (c) of this section.
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining CEMS
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart the process CO2 emissions using
the procedure in paragraph (b)(1) or
(b)(2) of this section.
(1) Carbon mass balance method.
Calculate the annual mass emissions of
CO2 for the process as specified in
paragraphs (b)(1)(i) through (b)(1)(vii) of
this section. The calculations are based
on the annual mass of inputs and
outputs to the process and an annual
analysis of the respective weight
fraction of carbon as determined
according to the procedures in
§ 98.174(b). If you have a process input
or output other than CO2 in the exhaust
gas that contains carbon that is not
included in Equations Q–1 through Q–
7 of this section, you must account for
the carbon and mass rate of that process
input or output in your calculations
according to the procedures in
§ 98.174(b)(5).
(i) For taconite indurating furnaces,
estimate CO2 emissions using Equation
Q–1 of this section.
− ( R ) ∗ ( CR ) ⎤
⎦
E:\FR\FM\30OCR2.SGM
(Eq. Q- 2)
q
30OCR2
ER30OC09.064</MATH>
§ 98.171
boilers, process heaters, reheat furnaces,
annealing furnaces, flame suppression,
ladle reheaters, and other miscellaneous
combustion sources.
(b) You must report CO2 emissions
from flares according to the procedures
in § 98.253(b)(1) of subpart Y (Petroleum
Refineries) of this part except you must
use the default CO2 emission factors for
coke oven gas and blast furnace gas from
Table C–1 of subpart C in Equation Y–
1 of subpart Y of this part. You must
report CH4 and N2O emissions from
flares according to the requirements in
§ 98.33(c)(2) using the emission factors
for coke oven gas and blast furnace gas
in Table C–2 of subpart C of this part.
(c) You must report process CO2
emissions from each taconite indurating
furnace; basic oxygen furnace; nonrecovery coke oven battery combustion
stack; coke pushing process; sinter
process; EAF; argon-oxygen
decarburization vessel; and direct
reduction furnace by following the
procedures in this subpart.
ER30OC09.063</MATH>
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.
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Where:
CO2 = Annual CO2 mass emissions from the
basic oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Iron) = Annual mass of molten iron charged
to the furnace (metric tons).
(CIron) = Carbon content of the molten iron,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
(Scrap) = Annual mass of ferrous scrap
charged to the furnace (metric tons).
(CScrap) = Carbon content of the ferrous scrap,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
CO2 =
(CSteel) = Carbon content of the steel, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(Slag) = Annual mass of slag produced by the
furnace (metric tons).
(CSlag) = Carbon content of the slag, from the
carbon analysis (percent by weight,
expressed as a decimal fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (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.
44
∗ ⎡( Coal ) ∗ ( C Coal ) − ( Coke ) ∗ ( CCoke ) − ( R) ∗ ( CR ) ⎤
⎦
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.
(Coal) = Annual mass of coal charged to the
battery (metric tons).
(CCoal) = Carbon content of the coal, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(Coke) = Annual mass of coke produced by
the battery (metric tons).
(CCoke) = Carbon content of the coke, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
(Eq. Q-3)
-
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(iv) For sinter processes, estimate CO2
emissions using Equation Q–4 of this
section.
44 ⎡
MW
∗ 0.001 + ( Feed ) ∗ ( CFeed ) − ( Sinter ) ∗ ( CSinter ) − ( R) ∗ ( CR ) ⎤
∗ Fg ∗ C gf ∗
⎦
⎣
12
MVC
)
Where:
CO2 = Annual CO2 mass emissions from the
sinter process (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fg) = Annual volume of the gaseous fuel
combusted (scf).
(Cgf) = Carbon content of the gaseous fuel,
from the fuel analysis results (kg C per
kg of fuel).
MW = Molecular weight of the gaseous fuel
(kg/kg-mole).
(CSinter) = Carbon content of the sinter pellets,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(v) For EAFs, estimate CO2 emissions
using Equation Q–5 of this section.
44 ⎡
∗ ( Iron ) ∗ ( C Iron ) + ( Scrap ) ∗ CScrap + ( Flux )
12 ⎣
(
( )
)
∗ C f + ( Electrode ) ∗ ( CElectrode ) + ( Carbon ) ∗ ( Cc ) − ( Steel )
(
(Eq. Q-5)
)
sroberts on DSKD5P82C1PROD with RULES
∗ ( CSteel ) − ( Slag ) ∗ CSlag − ( R) ∗ ( CR )
Where:
CO2 = Annual CO2 mass emissions from the
EAF (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Iron) = Annual mass of direct reduced iron
(if any) charged to the furnace (metric
tons).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(CIron) = Carbon content of the direct reduced
iron, from the carbon analysis results
(percent by weight, expressed as a
decimal fraction).
(Scrap) = Annual mass of ferrous scrap
charged to the furnace (metric tons).
(CScrap) = Carbon content of the ferrous scrap,
from the carbon analysis results (percent
PO 00000
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Sfmt 4700
by weight, expressed as a decimal
fraction).
(Flux) = Annual mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace (metric tons).
(CFlux) = Carbon content of the flux materials,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.067</MATH>
CO2 =
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
0.001 = Conversion factor from kg to metric
tons.
(Feed) = Annual mass of sinter feed material
(metric tons).
(CFeed) = Carbon content of the mixed sinter
feed materials that form the bed entering
the sintering machine, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(Sinter) = Annual mass of sinter produced
(metric tons).
(Eq. Q-4)
ER30OC09.066</MATH>
( ) (
ER30OC09.065</MATH>
CO2 =
(Flux) = Annual mass of flux materials (e.g.,
limestone, dolomite) charged to the
furnace (metric tons).
(CFlux) = Carbon content of the flux materials,
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
(Carbon) = Annual mass of carbonaceous
materials (e.g., coal, coke) charged to the
furnace (metric tons).
(CCarbon) = Carbon content of the
carbonaceous materials, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(Steel) = Annual mass of molten raw steel
produced by the furnace (metric tons).
56435
56436
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(Electrode) = Annual mass of carbon
electrode consumed (metric tons).
(CElectrode) = Carbon content of the carbon
electrode, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(Carbon) = Annual mass of carbonaceous
materials (e.g., coal, coke) charged to the
furnace (metric tons).
(CCarbon) = Carbon content of the
carbonaceous materials, from the carbon
CO2 =
44
∗ ( Steel ) ∗ ⎡( C Steelin ) − ( CSteelout ) ⎤ − ( R) ∗ ( CR )
⎣
⎦
12
Where:
CO2 = Annual CO2 mass emissions from the
argon-oxygen decarburization vessel
(metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Steel) = Annual mass of molten steel
charged to the vessel (metric tons).
CO2 =
analysis results (percent by weight,
expressed as a decimal fraction).
(Steel) = Annual mass of molten raw steel
produced by the furnace (metric tons).
(CSteel) = Carbon content of the steel, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(Slag) = Annual mass of slag produced by the
furnace (metric tons).
(CSlag) = Carbon content of the slag, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(CSteelin) = Carbon content of the molten steel
before decarburization, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(CSteelout) = Carbon content of the molten steel
after decarburization, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
44 ⎡
MW
∗ ⎢ Fg ∗ C gf ∗
∗ 0.001 + ( Ore ) ∗ (COre )
12 ⎣
MVC
( ) (
)
(R) = Annual mass of air pollution control
residue collected (metric tons).
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(vi) For argon-oxygen decarburization
vessels, estimate CO2 emissions using
Equation Q–6 of this section.
(Eq. Q -6)
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(vii) For direct reduction furnaces,
estimate CO2 emissions using Equation
Q–7 of this section.
(Eq. Q-7)
+ (Carbon) ∗ ( CCarbon ) + (Other ) ∗ ( COther )
− ( Iron) ( CIron ) − ( NM ) ∗ ( C NM ) − ( R) ∗ ( CR ) ⎤
⎦
CO2 = 5.18 x 10−7 CCO 2
Where:
VerDate Nov<24>2008
⎛ 100 − % H 2O ⎞
Q ⎜
⎟
100
⎝
⎠
CO2 = CO2 mass emission rate, corrected for
moisture (metric tons/hr).
17:39 Oct 29, 2009
Jkt 220001
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(2) Site-specific emission factor
method. 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
(b)(2)(i) through (b)(2)(iv) of this section.
(i) You must measure the process
production rate or process feed rate, as
applicable, during the performance test
according to the procedures in
§ 98.174(c)(5) 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 of this
section and determine the average
hourly CO2 emission rate for the test.
(Eq. Q-8)
5.18 × 10¥7 = Conversion factor (metric tons/
scf¥% CO2).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.070</GPH>
results (percent by weight, expressed as
a decimal fraction).
ER30OC09.069</MATH>
(CCarbon) = Carbon content of the
carbonaceous materials, from the carbon
analysis results (percent by weight,
expressed as a decimal fraction).
(Other) = Annual mass of other materials
charged to the furnace (metric tons).
(COther) = Average carbon content of the other
materials charged to the furnace, from
the carbon analysis results (percent by
weight, expressed as a decimal fraction).
(Iron) = Annual mass of iron produced
(metric tons).
(CIron) = Carbon content of the iron, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
(NM) = Annual mass of non-metallic
materials produced by the furnace
(metric tons).
(CNM) = Carbon content of the non-metallic
materials, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(R) = Annual mass of air pollution control
residue collected (metric tons).
(CR) = Carbon content of the air pollution
control residue, from the carbon analysis
ER30OC09.068</MATH>
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2 = Annual CO2 mass emissions from the
direct reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
(Fg) = Annual volume of the gaseous fuel
combusted (scf).
(Cgf) = Carbon content of the gaseous fuel,
from the fuel analysis results (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.
(Ore) = Annual mass of iron ore or iron ore
pellets fed to the furnace (metric tons).
(COre) = Carbon content of the iron ore or iron
ore pellets, from the carbon analysis
results (percent by weight, expressed as
a decimal fraction).
(Carbon) = Annual mass of carbonaceous
materials (e.g., coal, coke) charged to the
furnace (metric tons).
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
CCO2 = Hourly CO2 concentration, dry basis
(% 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.
(c) 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.
(d) If GHG emissions from a taconite
indurating furnace, basic oxygen
furnace, non-recovery coke oven battery,
sinter process, EAF, argon-oxygen
decarburization vessel, or direct
reduction furnace are vented through
the same stack as any combustion unit
or process equipment that reports CO2
emissions using a CEMS that complies
with the Tier 4 Calculation
Methodology in subpart C of this part
(General Stationary Fuel Combustion
Sources), then the calculation
methodology in paragraph (b) of this
section shall not be used to calculate
process emissions. The owner or
operator shall report under this subpart
the combined stack emissions according
to the Tier 4 Calculation Methodology
in § 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
sroberts on DSKD5P82C1PROD with RULES
§ 98.174 Monitoring and QA/QC
requirements.
(a) If you operate and maintain a
CEMS that measures CO2 emissions
consistent with subpart C of this part,
you must meet the monitoring and QA/
QC requirements of § 98.34(c).
(b) If you determine CO2 emissions
using the carbon mass balance
procedure in § 98.173(b)(1), you must:
(1) Except as provided in paragraph
(b)(4) of this section, determine the mass
of each process input and output other
than fuels using the same plant
instruments or procedures that are used
for accounting purposes (such as weigh
hoppers, belt weigh feeders, weighed
purchased quantities in shipments or
containers, combination of bulk density
and volume measurements, etc.), record
the totals for each process input and
output for each calendar month, and
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
sum the monthly mass to determine the
annual mass for each process input and
output. Determine the mass rate of fuels
using the procedures for combustion
units in § 98.34.
(2) Except as provided in paragraph
(b)(4) of this section, determine the
carbon content of each process input
and output annually for use in the
applicable equations in § 98.173(b)(1)
based on analyses provided by the
supplier or by the average carbon
content determined by collecting and
analyzing at least three samples each
year using the standard methods
specified in paragraphs (b)(2)(i) through
(b)(2)(vi) of this section as applicable.
(i) ASTM C25–06, Standard Test
Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime (incorporated by reference, see
§ 98.7) for limestone, dolomite, and slag.
(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7)
for coal, coke, and other carbonaceous
materials.
(iii) ASTM E1915–07a, Standard Test
Methods for Analysis of Metal Bearing
Ores and Related Materials by
Combustion Infrared-Absorption
Spectrometry (incorporated by
reference, see § 98.7) for iron ore,
taconite pellets, and other iron-bearing
materials.
(iv) ASTM E1019–08, Standard Test
Methods for Determination of Carbon,
Sulfur, Nitrogen, and Oxygen in Steel,
Iron, Nickel, and Cobalt Alloys by
Various Combustion and Fusion
Techniques (incorporated by reference,
see § 98.7) for iron and ferrous scrap.
(v) ASM CS–104 UNS No. G10460—
Alloy Digest April 1985 (Carbon Steel of
Medium Carbon Content) (incorporated
by reference, see § 98.7); ISO/TR 15349–
1:1998, Unalloyed steel—Determination
of low carbon content, Part 1: Infrared
absorption method after combustion in
an electric resistance furnace (by peak
separation) (1998–10–15) First Edition
(incorporated by reference, see § 98.7);
or ISO/TR 15349–3:1998, Unalloyed
steel-Determination of low carbon
content Part 3: Infrared absorption
method after combustion in an electric
resistance furnace (with preheating)
(1998–10–15) First Edition
(incorporated by reference, see § 98.7) as
applicable for steel.
(vi) For each process input that is a
fuel, determine the carbon content and
molecular weight (if applicable) using
the applicable methods listed in § 98.34.
(3) For solid ferrous materials charged
to basic oxygen process furnaces or
EAFs that differ in carbon content, you
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56437
may determine a weighted average
carbon content based on the carbon
content of each type of ferrous material
and the average weight percent of each
type that is used. Examples of these
different ferrous materials include
carbon steel, low carbon steel, stainless
steel, high alloy steel, pig iron, iron
scrap, and direct reduced iron.
(4) If you document that a specific
process input or output contributes less
than one percent of the total mass of
carbon into or out of the process, you do
not have to determine the monthly mass
or annual carbon content of that input
or output.
(5) Except as provided in paragraph
(b)(4) of this section, you must
determine the annual carbon content
and monthly mass rate of any input or
output that contains carbon that is not
listed in the equations in § 98.173(b)(1)
using the procedures in paragraphs
(b)(1) and (b)(2) of this section.
(c) If you determine CO2 emissions
using the site-specific emission factor
procedure in § 98.173(b)(2), you must:
(1) Conduct an annual performance
test that is based on representative
performance (i.e., performance based on
normal operating conditions) of the
affected process.
(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 three 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 3 hours.
(4) Conduct the stack test using EPA
Method 3A at 40 CFR part 60, appendix
A–2 to measure the CO2 concentration,
Method 2, 2A, 2C, 2D, or 2F at 40 CFR
part 60, appendix A–1 or Method 26 at
40 CFR part 60, appendix A–2 to
determine the stack gas volumetric flow
rate, and Method 4 at 40 CFR part 60,
at appendix A–3 to determine the
moisture content of the stack gas.
(5) Determine the mass rate of process
feed or process production (as
applicable) during the test using the
same plant instruments or procedures
that are used for accounting purposes
(such as weigh hoppers, belt weigh
feeders, combination of bulk density
and volume measurements, etc.)
(6) If your process operates under
different conditions as part of normal
operations in such a manner that CO2
emissions change by more than 20
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percent (e.g., routine changes in the
carbon content of the sinter feed or
change in grade of product), you must
perform emission testing and develop
separate emission factors for these
different operating conditions and
determine emissions based on the
number of hours the process operates
and the production or feed rate (as
applicable) at each specific different
condition.
(7) If your EAF and argon-oxygen
decarburization vessel exhaust to a
common emission control device and
stack, you must sample each process in
the ducts before the emissions are
combined, sample each process when
only one process is operating, or sample
the combined emissions when both
processes are operating and base the
site-specific emission factor on the steel
production rate of the EAF.
(8) 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 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.
sroberts on DSKD5P82C1PROD with RULES
§ 98.175 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations in § 98.173 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 as specified in the
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) For each missing data for the
carbon content of inputs and outputs for
facilities that estimate emissions using
the carbon mass balance procedure in
§ 98.173(b)(1) or for facilities that
estimate emissions using the sitespecific emission factor procedure in
§ 98.173(b)(2); 100 percent data
availability is required. You must repeat
the test for average carbon contents of
inputs and outputs according to the
procedures in § 98.174(b)(2). Similarly,
you must repeat the test to determine
the site-specific emission factor if data
on the CO2 emission rate, process
production rate or process feed rate are
missing.
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(b) For missing records of the monthly
mass or volume of carbon-containing
inputs and outputs using the carbon
mass balance procedure in
§ 98.173(b)(1), the substitute data value
must be based on the best available
estimate of the mass of the input or
output material from all available
process data or data used for accounting
purposes.
§ 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 (f) of this
section for each coke pushing operation;
taconite indurating furnace; basic
oxygen furnace; non-recovery coke oven
battery; sinter process; EAF; argonoxygen decarburization vessel; and
direct reduction furnace:
(a) Unit identification number and
annual CO2 emissions (in metric tons).
(b) Annual production quantity (in
metric tons) for taconite pellets, coke,
sinter, iron, and raw steel.
(c) If a CEMS is used to measure CO2
emissions, then you must report the
relevant information required under
§ 98.37 for the Tier 4 Calculation
Methodology.
(d) If a CEMS is not used to measure
CO2 emissions, then you must report for
each process whether the emissions
were determined using the carbon mass
balance method in § 98.173(b)(1) or the
site-specific emission factor method in
§ 98.173(b)(2).
(e) If you use the carbon mass balance
method in § 98.173(b)(1) to determine
CO2 emissions, you must report the
following information for each process:
(1) The carbon content of each process
input and output used to determine CO2
emissions.
(2) Whether the carbon content was
determined from information from the
supplier or by laboratory analysis, and
if by laboratory analysis, the method
used.
(3) The annual volume of gaseous fuel
(in standard cubic feet), the annual
volume of liquid fuel (in gallons), and
the annual mass (in metric tons) of all
other process inputs and outputs used
to determine CO2 emissions.
(4) The molecular weight of gaseous
fuels.
(5) If you used the missing data
procedures in § 98.175(b), you must
report how the monthly mass for each
process input or output with missing
data was determined and the number of
months the missing data procedures
were used.
(f) If you used the site-specific
emission factor method in § 98.173(b)(2)
to determine CO2 emissions, you must
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report the following information for
each process:
(1) The measured average hourly CO2
emission rate during the test (in metric
tons per hour).
(2) The average hourly feed or
production rate (as applicable) during
the test (in metric tons per hour).
(3) The site-specific emission factor
(in metric tons of CO2 per metric ton of
feed or production, as applicable).
(4) The annual feed or production rate
(as applicable) used to estimate annual
CO2 emissions (in metric tons).
§ 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 (e) of
this section, as applicable. Facilities that
use CEMS to measure emissions must
also retain records of the verification
data required for the Tier 4 Calculating
Methodology in § 98.36(e).
(a) Records of all analyses and
calculations conducted, including all
information reported as required under
§ 98.176.
(b) When the carbon mass balance
method is used to estimate emissions for
a process, the monthly mass of each
process input and output that are used
to determine the annual mass.
(c) Production capacity (in metric tons
per year) for the production of taconite
pellets, coke, sinter, iron, and raw steel.
(d) Annual operating hours for
taconite furnaces, coke oven batteries,
sinter production, blast furnaces, direct
reduced iron furnaces, and electric arc
furnaces.
(e) 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). You 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.
§ 98.178
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
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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
(including but not limited to, lead-acid
batteries) are recycled by smelting into
elemental lead or lead alloys.
§ 98.181
§ 98.183
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 (a)(2).
§ 98.182
GHGs to report.
You must report:
(a) Process CO2 emissions from each
smelting furnace used for lead
production.
(b) CO2 combustion emissions from
each smelting furnace used for lead
production.
(c) CH4 and N2O combustion
emissions from each smelting furnace
used for lead production. You must
sroberts on DSKD5P82C1PROD with RULES
E CO2 =
44 2000 ⎡
×
× ( Ore × COre ) + Scrap × CScrap + ( Flux × CFlux ) + ( Carbon × CCarbon ) + ( Other × COther ) ⎤
⎦
12 2205 ⎣
(
Where:
ECO2 = Annual process CO2 emissions from
an individual smelting furnace (metric
tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion factor to convert
tons to metric tons.
Ore = Annual mass of lead ore charged to the
smelting furnace (tons).
COre = Carbon content of the lead ore, from
the carbon analysis results (percent by
weight, expressed as a decimal fraction).
Scrap = Annual mass of lead scrap charged
to the smelting furnace (tons).
CScrap = Carbon content of the lead scrap,
from the carbon analysis (percent by
weight, expressed as a decimal fraction).
Flux = Annual mass of flux materials (e.g.,
limestone, dolomite) charged to the
smelting furnace (tons).
CFlux = Carbon content of the flux materials,
from the carbon analysis (percent by
weight, expressed as a decimal fraction).
Carbon = Annual mass of carbonaceous
materials (e.g., coal, coke) charged to the
smelting furnace (tons).
CCarbon = Carbon content of the carbonaceous
materials, from the carbon analysis
(percent by weight, expressed as a
decimal fraction).
VerDate Nov<24>2008
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
smelting furnace using the procedure in
paragraphs (a) and (b) of this section.
(a) For each smelting furnace that
meets the conditions specified in
§ 98.33(b)(4)(ii) or (b)(4)(iii), you must
calculate and report combined process
and combustion CO2 emissions by
operating and maintaining a CEMS to
measure CO2 emissions according to the
Tier 4 Calculation Methodology
specified in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) For each smelting furnace that is
not subject to the requirements in
paragraph (a) of this section, calculate
and report the process and combustion
17:39 Oct 29, 2009
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)
Other = Annual mass of any other material
containing carbon, other than fuel, fed,
charged, or otherwise introduced into
the smelting furnace (tons).
COther = Carbon content of the other material
from the carbon analysis results (percent
by weight, expressed as a decimal
fraction).
(ii) Determine the combined annual
process CO2 emissions from the
smelting furnaces at your facility using
Equation R–2 of this section.
k
CO 2 = ∑ E CO2k
(Eq. R-2)
1
Where:
CO2 = Annual process CO2 emissions from
smelting furnaces at facility used for lead
production (metric tons).
ECO2k = Annual process CO2 emissions from
smelting furnace k calculated using
Equation R–1 of this section (metric
tons/year).
k = Total number of smelting furnaces at
facility used for lead production.
(iii) Calculate and report under
subpart C of this part (General
Stationary Fuel Combustion Sources)
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(Eq. R-1)
the combustion CO2 emissions from the
smelting furnaces according to the
applicable requirements in subpart C.
§ 98.184 Monitoring and QA/QC
requirements.
If you determine process CO2
emissions using the carbon mass
balance procedure in § 98.183(b)(2)(i)
and (b)(2)(ii), you must meet the
requirements specified in paragraphs (a)
and (b) of this section.
(a) Determine the annual mass for
each material used for the calculations
of annual process CO2 emissions using
Equation R–1 of this subpart by
summing the monthly mass for the
material determined for each month of
the calendar year. The monthly mass
may be determined using plant
instruments used for accounting
purposes, including either direct
measurement of the quantity of the
material placed in the unit or by
calculations using process operating
information.
(b) For each material identified in
paragraph (a) of this section, you must
determine the average carbon content of
E:\FR\FM\30OCR2.SGM
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ER30OC09.072</MATH>
§ 98.180
CO2 emissions from the smelting
furnace by using the procedure in either
paragraph (b)(1) or (b)(2) of this section.
(1) Calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
and maintaining a CEMS to measure
CO2 emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(2) Calculate and report process and
combustion CO2 emissions separately
using the procedures specified in
paragraphs (b)(2)(i) through (b)(2)(iii) of
this section.
(i) For each smelting furnace,
determine the annual mass of carbon in
each carbon-containing material, other
than fuel, that is fed, charged, or
otherwise introduced into the smelting
furnace and estimate annual process
CO2 emissions using Equation R–1 of
this section. Carbon-containing
materials include carbonaceous
reducing agents. If you document that a
specific material contributes less than 1
percent of the total carbon into the
process, you do not have to include the
material in your calculation using
Equation R–1 of this section.
ER30OC09.071</MATH>
calculate and report these emissions
under subpart C of this part (General
Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
(d) CO2, CH4, and N2O emissions from
each stationary combustion unit other
than smelting furnaces used for lead
production. You must report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
Subpart R—Lead Production
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the material consumed or used in the
calendar year using the methods
specified in either paragraph (b)(1) or
(b)(2) of this section. If you document
that a specific process input or output
contributes less than one percent of the
total mass of carbon into or out of the
process, you do not have to determine
the monthly mass or annual carbon
content of that input or output.
(1) Information provided by your
material supplier.
(2) Collecting and analyzing at least
three representative samples of the
material each year. The carbon content
of the material must be analyzed at least
annually using the methods (and their
QA/QC procedures) specified in
paragraphs (b)(2)(i) through (b)(2)(iii) of
this section, as applicable.
(i) ASTM E1941–04, Standard Test
Method for Determination of Carbon in
Refractory and Reactive Metals and
Their Alloys (incorporated by reference,
see § 98.7) for analysis of metal ore and
alloy product.
(ii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7),
for analysis of carbonaceous reducing
agents and carbon electrodes.
(iii) ASTM C25–06, Standard Test
Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime (incorporated by reference, see
§ 98.7) for analysis of flux materials
such as limestone or dolomite.
sroberts on DSKD5P82C1PROD with RULES
§ 98.185 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations in § 98.183 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 as specified in the
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) For each missing data for the
carbon content for the smelting furnaces
at your facility that estimate annual
process CO2 emissions using the carbon
mass balance procedure in
§ 98.183(b)(2)(i) and (ii), 100 percent
data availability is required. You must
repeat the test for average carbon
contents of inputs according to the
procedures in § 98.184(b) if data are
missing.
(b) For missing records of the monthly
mass of carbon-containing materials, the
substitute data value must be based the
best available estimate of the mass of the
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17:39 Oct 29, 2009
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material from all available process data
or data used for accounting purposes
(such as purchase records).
§ 98.186
Data reporting procedures.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as applicable.
(a) If a CEMS is used to measure CO2
emissions according to the requirements
in § 98.183(a) or (b)(1), then you must
report under this subpart the relevant
information required by § 98.36 and the
information specified in paragraphs
(a)(1) through (a)(4) of this section.
(1) Identification number of each
smelting furnace.
(2) Annual lead product production
capacity (tons).
(3) Annual production for each lead
product (tons).
(4) Total number of smelting furnaces
at facility used for lead production.
(b) If a CEMS is not used to measure
CO2 emissions, and you measure CO2
emissions according to the requirements
in § 98.183(b)(2)(i) and (b)(2)(ii), then
you must report the information
specified in paragraphs (b)(1) through
(b)(9) of this section.
(1) Identification number of each
smelting furnace. (2) Annual process
CO2 emissions (in metric tons) from
each smelting furnace as determined by
Equation R–1 of this subpart.
(3) Annual lead product production
capacity for the facility and each
smelting furnace(tons).
(4) Annual production for each lead
product (tons).
(5) Total number of smelting furnaces
at facility used for production of lead
products reported in paragraph (b)(4) of
this section.
(6) Annual material quantity for each
material used for the calculation of
annual process CO2 emissions using
Equation R–1 of this subpart for each
smelting furnace (tons).
(7) Annual average of the carbon
content determinations for each material
used for the calculation of annual
process CO2 emissions using Equation
R–1 of this subpart for each smelting
furnace.
(8) List the method used for the
determination of carbon content for
each material reported in paragraph
(b)(7) of this section (e.g., supplier
provided information, analyses of
representative samples you collected).
(9) If you use the missing data
procedures in § 98.185(b), you must
report how the monthly mass of carboncontaining materials with missing data
was determined and the number of
months the missing data procedures
were used.
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§ 98.187
Records that must be retained.
In addition to the records required by
§ 98.3(g), each annual report must
contain the information specified in
paragraphs (a) through (c) of this
section, as applicable to the smelting
furnaces at your facility.
(a) If a CEMS is used to measure
combined process and combustion CO2
emissions according to the requirements
in § 98.183(a) or (b)(1), then you must
retain the records required for the Tier
4 Calculation Methodology in § 98.37
and the information specified in
paragraphs (a)(1) through (a)(3) of this
section.
(1) Monthly smelting furnace
production quantity for each lead
product (tons).
(2) Number of smelting furnace
operating hours each month.
(3) Number of smelting furnace
operating hours in calendar year.
(b) If the carbon mass balance
procedure is used to determine process
CO2 emissions according to the
requirements in § 98.183(b)(2)(i) and
(b)(2)(ii), then you must retain under
this subpart the records specified in
paragraphs (b)(1) through (b)(5) of this
section.
(1) Monthly smelting furnace
production quantity for each lead
product (tons).
(2) Number of smelting furnace
operating hours each month.
(3) Number of smelting furnace
operating hours in calendar year.
(4) Monthly material quantity
consumed, used, or produced for each
material included for the calculations of
annual process CO2 emissions using
Equation R–1 of this subpart (tons).
(5) Average carbon content
determined and records of the supplier
provided information or analyses used
for the determination for each material
included for the calculations of annual
process CO2 emissions using Equation
R–1 of this subpart.
(c) 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, including
documentation of any materials
excluded from Equation R–1 of this
subpart that contribute less than 1
percent of the total carbon into or out
of the process. You also must document
the procedures used to ensure the
accuracy of the measurements of
materials fed, charged, or placed in an
smelting furnace 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
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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.
(a) Lime manufacturing plants (LMPs)
engage in the manufacture of a lime
product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide,
hydrated lime, dolomitic quicklime,
dolomitic hydrate, or other products) by
calcination of limestone, dolomite,
shells or other cacareous substances as
defined in 40 CFR 63.7081(a)(1).
(b) This source category includes all
LMPs unless the LMP is located at a
kraft pulp mill, soda pulp mill, sulfite
pulp mill, or only processes sludge
containing calcium carbonate from
water softening processes. The lime
manufacturing source category consists
of marketed and non-marketed lime
manufacturing facilities.
(c) Lime kilns at pulp and paper
manufacturing facilities must report
emissions under subpart AA of this part
(Pulp and Paper Manufacturing).
§ 98.191
Reporting threshold.
You must report GHG emissions
under this subpart if your facility is a
lime manufacturing plant as defined in
§ 98.192
GHGs to report.
You must report:
(a) CO2 process emissions from lime
kilns.
(b) CO2 emissions from fuel
combustion at lime kilns.
(c) N2O and CH4 emissions from fuel
combustion at each lime kiln. You must
report these emissions under 40 CFR
part 98, subpart C (General Stationary
Fuel Combustion Sources).
(d) CO2, N2O, and CH4 emissions from
each stationary fuel combustion unit
other than lime kilns. You must report
these emissions under 40 CFR part 98,
subpart C (General Stationary Fuel
Combustion Sources).
(e) CO2 collected and transferred off
site under 40 CFR part 98, following the
requirements of subpart PP of this part
(Suppliers of Carbon Dioxide (CO2)).
§ 98.193
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from all
lime kilns combined using the
procedure in paragraphs (a) and (b) of
this section.
(a) If all lime kilns meet the
conditions specified in § 98.33(b)(4)(ii)
or (b)(4)(iii), you must calculate and
report under this subpart the combined
process and combustion CO2 emissions
2000
EFLIME,i,n = ⎡( SRCaO ∗ CaOi,n ) + SRMgO ∗ MgOi,n ⎤ ∗
⎣
⎦ 2205
(
Where:
EFLIME,i,n = Emission factor for lime type i, for
month n (metric tons CO2/ton lime).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate [see Table S–1 of
this subpart] (metric tons CO2/metric
tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S–
)
1 of this subpart) (metric tons CO2/metric
tons MgO).
CaOi,n = Calcium oxide content for lime type
i, for month n, determined according to
§ 98.194(c) (metric tons CaO/metric ton
lime).
MgOi,n = Magnesium oxide content for lime
type i, for month n, determined
according to § 98.194(c) (metric tons
MgO/metric ton lime).
2000/2205 = Conversion factor for metric
tons to tons.
(ii) You must calculate a monthly
emission factor for each type of
byproduct/waste sold (including
lime kiln dust) using Equation S–2
of this section:
2000
0
EFLKD,i,n = ⎡( SRCaO ∗ CaOLKD,i,n ) + SRMgO ∗ MgOLKD,i,n ⎤ ∗
⎣
⎦ 2205
sroberts on DSKD5P82C1PROD with RULES
(
Where:
EFLKD,i,n = Emission factor for sold lime
byproduct/waste type i, for month n
(metric tons CO2/ton lime byproduct).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate (see Table S–1 of
this subpart((metric tons CO2/metric tons
CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S–
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
)
1 of this subpart) (metric tons CO2/metric
tons MgO).
CaOLKD,i,n = Calcium oxide content for sold
lime byproduct/waste type i, for month
n (metric tons CaO/metric ton lime).
MgOLKD,i,n = Magnesium oxide content for
sold lime byproduct/waste type i, for
month n (metric tons MgO/metric ton
lime).
PO 00000
Frm 00183
Fmt 4701
Sfmt 4700
(Eq. S-1)
(Eq. S-2)
2000/2205 = Conversion factor for metric
tons to tons.
(iii) You must calculate the annual
CO2 emissions from each type of
byproduct/waste that is not sold
(including lime kiln dust and scrubber
sludge) using Equation S–3 of this
section:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.074</MATH>
§ 98.188
by operating and maintaining a CEMS to
measure CO2 emissions according to the
Tier 4 Calculation Methodology
specified in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) If CEMS are not required to be
used to determine CO2 emissions from
all lime kilns under paragraph (a) of this
section, then you must calculate and
report the process and combustion CO2
emissions from the lime kilns by using
the procedures in either paragraph (b)(1)
or (b)(2) of this section.
(1) Calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
and maintaining a CEMS to measure
CO2 emissions from all lime kilns
according to the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
(2) Calculate and report process and
combustion CO2 emissions separately
using the procedures specified in
paragraphs (b)(2)(i) through (b)(2)(v) of
this section.
(i) You must calculate a monthly
emission factor 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 lime type:
ER30OC09.073</MATH>
§ 98.190 and the facility meets the
requirements of either § 98.2(a)(1) or
(a)(2).
basis for these estimates must be
provided.
56441
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
2000
Ewaste,i = ⎡( SRCaO ∗ CaOwaste,i ) + SRMgO ∗ MgOwaste,i ⎤ ∗ M waste,i ∗
⎣
⎦
2205
(
Where:
Ewaste,i = Annual CO2 emissions for unsold
lime byproduct/waste type i (metric tons
CO2).
SRCaO = Stoichiometric ratio of CO2 and CaO
for calcium carbonate (see Table S–1 of
this subpart) (metric tons CO2/metric
tons CaO).
)
(Eq. S-3)
Mwaste,i = Annual weight or mass of unsold
byproducts/wastes for lime type i (tons).
2000/2205 = Conversion factor for metric
tons to tons.
SRMgO = Stoichiometric ratio of CO2 and MgO
for magnesium carbonate (See Table S–
1 of this subpart) (metric tons CO2/metric
tons MgO).
CaOwaste,i = Calcium oxide content for unsold
lime byproduct/waste type i (metric tons
CaO/metric ton lime).
MgOwaste,i = Magnesium oxide content for
unsold lime byproduct/waste type i
(metric tons MgO/metric ton lime).
(iv) You must calculate annual CO2
process emissions for all kilns using
Equation S–4 of this section:
t 12
b 12
z
i =1 n =1
i =1 n =1
i =1
ECO2 ∑ ∑ ( EFLIME,i,n ∗ M LIME,i,n ) + ∑ ∑ EFLKD,i,n ∗ M LKD,i,n ) + ∑ Ewaste,i
(v) Calculate and report under subpart
C of this part (General Stationary Fuel
Combustion Sources) the combustion
CO2 emissions from each lime kiln
according to the applicable
requirements in subpart C.
sroberts on DSKD5P82C1PROD with RULES
§ 98.194 Monitoring and QA/QC
requirements.
(a) You must determine the total
quantity of each product type of lime
and each calcined byproduct/waste
(such as lime kiln dust) that is sold. The
quantities of each should be directly
measured monthly with the same plant
instruments used for accounting
purposes, including but not limited to,
calibrated weigh feeders, rail or truck
scales, and barge measurements. The
direct measurements of each lime
product shall be reconciled annually
with the difference in the beginning of
and end of year inventories for these
products, when measurements represent
lime sold.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(b) You must determine the annual
quantity of each calcined byproduct/
waste generated that is not sold by
either direct measurement using the
same instruments identified in
paragraph (a) of this section or by using
a calcined byproduct/waste generation
rate.
(c) You must determine the chemical
composition (percent total CaO and
percent total MgO) of each type of lime
and each type of calcined byproduct/
waste sold according to paragraph (c)(1)
or (c)(2) of this section. You must
determine the chemical composition of
each type of lime on a monthly basis.
You must determine the chemical
composition for each type of calcined
byproduct/waste that is not sold on an
annual basis.
(1) ASTM C25–06 Standard Test
Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime (incorporated by reference—see
§ 98.7).
(2) The National Lime Association’s
CO2 Emissions Calculation Protocol for
the Lime Industry English Units
Version, February 5, 2008 RevisionNational Lime Association
(incorporated by reference—see § 98.7).
(d) You must use the analysis of
calcium oxide and magnesium oxide
content of each lime product collected
during the same month as the
production data in monthly
calculations.
(e) You must follow the quality
assurance/quality control procedures
(including documentation) in National
Lime Association’s CO2 Emissions
Calculation Protocol for the Lime
Industry English Units Version,
February 5, 2008 Revision—National
Lime Association (incorporated by
reference—see § 98.7).
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§ 98.195 Procedures for estimating
missing data.
For the procedure in § 98.193(b)(2), a
complete record of all measured
parameters used in the GHG emissions
calculations is required (e.g., oxide
content, quantity of lime products, 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 as specified in
paragraphs (a) or (b) of this section. You
must document and keep records of the
procedures used for all such estimates.
(a) For each missing value of the
quantity of lime produced (by lime
type), and quantity of byproduct/waste
produced and sold, the substitute data
value shall be the best available estimate
based on all available process data or
data used for accounting purposes.
(b) For missing values related to the
CaO and MgO content, you must
conduct a new composition test
according to the standard methods in
§ 98.194 (c)(1) or (c)(2).
§ 98.196
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as applicable.
(a) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required by § 98.36 and the information
listed in paragraphs (a)(1) through (a)(8)
of this section.
(1) Method used to determine the
quantity of lime sold.
(2) Method used to determine the
quantity of lime byproduct/waste sold.
(3) Beginning and end of year
inventories for each lime product.
(4) Beginning and end of year
inventories for lime byproducts/wastes.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.076</MATH>
Where:
ECO2 = Annual CO2 process emissions from
lime production from all kilns (metric
tons/year).
EFLIME,i,n = Emission factor for lime type i, in
calendar month n (metric tons CO2/ton
lime) from Equation S–1 of this section.
MLIME,i,n = Weight or mass of lime type i in
calendar month n (tons).
EFLKD,i,n = Emission factor of byproducts/
wastes sold for lime type i in calendar
month n, (metric tons CO2/ton
byproduct/waste) from Equation S–2 of
this section.
MLKD,i,n = Monthly weight or mass of
byproducts/waste sold (such as lime kiln
dust, LKD) for lime type i in calendar
month n (tons).
Ewaste,i = Annual CO2 emissions for unsold
lime byproduct/waste type i (metric tons
CO2) from Equation S–3 of this section.
t = Number of lime types
b = Number of byproducts/wastes sold
z = Number of byproducts/wastes not sold
(Eq. S-4)
ER30OC09.075</MATH>
56442
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
§ 98.197
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) Annual operating hours in
calendar year.
(b) Records of all analyses (e.g.
chemical composition of lime products,
by type) and calculations conducted.
§ 98.198
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.213
Subpart U—Miscellaneous Uses of
Carbonate
You must determine CO2 process
emissions from carbonate use in
accordance with the procedures
specified in either paragraphs (a) or (b)
of this section.
(a) Calculate the process emissions of
CO2 using calcination fractions with
Equation U–1 of this section.
§ 98.210
Definition of the source category.
(a) This source category includes any
equipment that uses carbonates listed in
Table U–1 in manufacturing processes
that emit carbon dioxide. Table U–1
2000
2205
(Eq. U-1)
subpart, metric tons CO2/metric ton
carbonate consumed.
Fi = Fraction calcination achieved for each
particular carbonate type i (decimal
fraction). As an alternative to measuring
the calcination fraction, a value of 1.0
can be used.
n = Number of carbonate types.
(
PO 00000
Frm 00185
Fmt 4701
⎤
)⎥ ∗ 2000
⎥ 2205
Sfmt 4725
Calculating GHG emissions.
2000/2205 = Conversion factor to convert
tons to metric tons.
(b) Calculate the process emissions of
CO2 using actual mass of output
carbonates with Equation U–2 of
this section.
(Eq. U-2)
⎦
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.078</MATH>
sroberts on DSKD5P82C1PROD with RULES
GHGs to report.
Subpart T—[Reserved]
n
⎡m
E CO2 = ⎢ ∑ ( M k ∗ EFk ) − ∑ M j ∗ EFj
⎢ k =1
j=1
⎣
Jkt 220001
§ 98.212
You must report CO2 process
0.7848 emissions from all miscellaneous
1.0918 carbonate use at your facility as
specified in this subpart.
SRCaO ..............................
SRMgO .............................
i =1
17:39 Oct 29, 2009
Reporting threshold.
You must report GHG emissions from
miscellaneous uses of carbonate if your
facility uses carbonates as defined in
§ 98.210 of this subpart and the facility
meets the requirements of either
§ 98.2(a)(1) or (a)(2).
Stoichiometric
ratio
Variable
n
VerDate Nov<24>2008
§ 98.211
TABLE S–1 TO SUBPART S OF PART
98—BASIC PARAMETERS FOR THE
CALCULATION OF EMISSION FACTORS FOR LIME PRODUCTION
E CO2 = ∑ Mi ∗ EFi ∗ Fi ∗
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
includes the following carbonates:
limestone, dolomite, ankerite,
magnesite, siderite, rhodochrosite, or
sodium carbonate. Facilities are
considered to emit CO2 if they consume
at least 2,000 tons per year of carbonates
heated to a temperature sufficient to
allow the calcination reaction to occur.
(b) This source category does not
include equipment that uses carbonates
or carbonate containing minerals that
are consumed in the production of
cement, glass, ferroalloys, iron and steel,
lead, lime, phosphoric acid, pulp and
paper, soda ash, sodium bicarbonate,
sodium hydroxide, or zinc.
(c) This source category does not
include carbonates used in sorbent
technology used to control emissions
from stationary fuel combustion
equipment. Emissions from carbonates
used in sorbent technology are reported
under 40 CFR 98, subpart C (Stationary
Fuel Combustion Sources).
(months) or the chemical composition of
lime products sold (months).
(17) Indicate whether CO2 was used
on-site (i.e. for use in a purification
process). If CO2 was used on-site,
provide the information in paragraphs
(b)(17)(i) and (b)(17)(ii) of this section.
(i) The annual amount of CO2
captured for use in the on-site process.
(ii) The method used to determine the
amount of CO2 captured.
ER30OC09.077</MATH>
(5) Annual amount of lime byproduct/
waste sold, by type (tons).
(6) Annual amount of lime product
sold, by type (tons).
(7) Annual amount of lime byproduct/
waste not sold, by type (tons).
(8) Annual amount of lime product
not sold, by type (tons).
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
information listed in paragraphs (b)(1)
through (b)(17) of this section.
(1) Annual CO2 process emissions
from all kilns combined (metric tons).
(2) Monthly emission factors for each
lime type.
(3) Monthly emission factors for each
sold byproduct/waste by lime type.
(4) Standard method used (ASTM or
NLA testing method) to determine
chemical compositions of each lime
type and lime byproduct/waste type.
(5) Monthly results of chemical
composition analysis of each lime
product and byproduct/waste sold.
(6) Annual results of chemical
composition analysis of each type of
lime byproduct/waste not sold.
(7) Method used to determine the
quantity of lime sold.
(8) Monthly amount of lime product
sold, by type (tons).
(9) Method used to determine the
quantity of lime byproduct/waste sold.
(10) Monthly amount of lime
byproduct/waste sold, by type (tons).
(11) Annual amount of lime
byproduct/waste not sold (tons).
(12) Monthly mass of each lime type
produced (tons).
(13) Beginning and end of year
inventories for each lime product.
(14) Beginning and end of year
inventories for lime byproducts/wastes.
(15) Annual lime production capacity
(tons) per facility.
(16) Number of times in the reporting
year that missing data procedures were
followed to measure lime production
56443
56444
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Where:
ECO2 = Annual CO2 mass emissions from
consumption of carbonates (metric tons).
Mk = Annual mass of input carbonate type k
(tons).
EFk = Emission factor for the carbonate type
k, as specified in Table U–1 of this
subpart (metric tons CO2/metric ton
carbonate input).
Mj = Annual mass of output carbonate type
j (tons).
EFj = Emission factor for the output
carbonate type j, as specified in Table U–
1 of this subpart (metric tons CO2/metric
ton carbonate input).
m = Number of input carbonate types.
n = Number of output carbonate types.
§ 98.214 Monitoring and QA/QC
requirements.
(a) The annual mass of carbonate
consumed (for Equation U–1 of this
subpart) or carbonate inputs (for
Equation U–2 of this subpart) must be
determined annually from monthly
measurements using the same plant
instruments used for accounting
purposes including purchase records or
direct measurement, such as weigh
hoppers or weigh belt feeders.
(b) The annual mass of carbonate
outputs (for Equation U–2 of this
subpart) must be determined annually
from monthly measurements using the
same plant instruments used for
accounting purposes including purchase
records or direct measurement, such as
weigh hoppers or belt weigh feeders.
(c) If you follow the procedures of
§ 98.213(a), as an alternative to
assuming a calcination fraction of 1.0,
you can determine on an annual basis
the calcination fraction for each
carbonate consumed based on sampling
and chemical analysis using a suitable
method such as using an x-ray
fluorescence standard method or other
enhanced industry consensus standard
method published by an industry
consensus standard organization (e.g.,
ASTM, ASME, etc.).
sroberts on DSKD5P82C1PROD with RULES
§ 98.215 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 as specified in paragraph
(b) of this section. You must document
and keep records of the procedures used
for all such estimates.
(b) For each missing value of monthly
carbonate consumed, monthly carbonate
output, or monthly carbonate input, the
substitute data value must be the best
available estimate based on the all
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
available process data or data used for
accounting purposes.
§ 98.216
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 (g) of this
section at the facility level, as
applicable.
(a) Annual CO2 emissions from
miscellaneous carbonate use (metric
tons).
(b) Annual mass of each carbonate
type consumed (tons).
(c) Measurement method used to
determine the mass of carbonate.
(d) Method used to calculate
emissions.
(e) If you followed the calculation
method of § 98.213(b)(1)(i), you must
report the information in paragraphs
(e)(1) through (e)(3) of this section.
(1) Annual carbonate consumption by
carbonate type (tons).
(2) Annual calcination fractions used
in calculations.
(3) If you determined the calcination
fraction, indicate which standard
method was used.
(f) If you followed the calculation
method of § 98.213(b)(1)(ii), you must
report the information in paragraphs
(f)(1) and (f)(2) of this section.
(1) Annual carbonate input by
carbonate type (tons).
(2) Annual carbonate output by
carbonate type (tons).
(g) Number of times in the reporting
year that missing data procedures were
followed to measure carbonate
consumption, carbonate input or
carbonate output (months).
§ 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 (d)
of this section:
(a) Monthly carbonate consumption
(by carbonate type in tons).
(b) You must document the
procedures used to ensure the accuracy
of the monthly measurements of
carbonate consumption, carbonate input
or carbonate output including, but not
limited to, calibration of weighing
equipment and other measurement
devices.
(c) Records of all analyses conducted
to meet the requirements of this rule.
(d) Records of all calculations
conducted.
§ 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.
PO 00000
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TABLE U–1 TO SUBPART U OF PART
98—CO2 EMISSION FACTORS FOR
COMMON CARBONATES
Mineral name—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 .................................
CO2 emission factor
(tons CO2/
ton carbonate)
0.43971
0.52197
0.47732
0.37987
0.47572
0.38286
0.41492
Subpart V—Nitric Acid Production
§ 98.220
Definition of source category.
A nitric acid production facility uses
one or more trains to produce weak
nitric acid (30 to 70 percent in strength).
A nitric acid train produces weak nitric
acid through the catalytic oxidation of
ammonia.
§ 98.221
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a nitric acid train and the
facility meets the requirements of either
§ 98.2(a)(1) or (a)(2).
§ 98.222
GHGs to report.
(a) You must report N2O process
emissions from each nitric acid
production train as required by this
subpart.
(b) You must report under subpart C
of this part (General Stationary Fuel
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit by following the
requirements of subpart C.
§ 98.223
Calculating GHG emissions.
(a) You must determine annual N2O
process emissions from each nitric acid
train according to paragraphs (a)(1) or
(a)(2) of this section.
(1) Use a site-specific emission factor
and production data according to
paragraphs (b) through (h) of this
section.
(2) Request Administrator approval
for an alternative method of determining
N2O emissions according to paragraphs
(a)(2)(i) and (a)(2)(ii) of this section.
(i) You must submit the request
within 45 days following promulgation
of this subpart or within the first 30
days of each subsequent reporting year.
(ii) If the Administrator does not
approve your requested alternative
method within 150 days of the end of
the reporting year, you must determine
the N2O emissions factor for the current
E:\FR\FM\30OCR2.SGM
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operating conditions and without using
N2O abatement technology (if
applicable).
(3) You must measure the production
rate during the performance test and
calculate the production rate for the test
period in metric tons (100 percent acid
basis) per hour.
(c) You must determine an N2O
emissions factor to use in Equation V–
3 of this section according to paragraphs
(c)(1) or (c)(2) of this section.
(d) If applicable, you must determine
the destruction efficiency for each N2O
abatement technology according to
paragraphs (d)(1), (d)(2), or (d)(3) of this
section.
(1) Use the manufacturer’s specified
destruction efficiency.
(2) Estimate the destruction efficiency
through process knowledge. Examples
sroberts on DSKD5P82C1PROD with RULES
EFN 2Ot =
Where:
EN2Ot = N2O mass emissions per year for
nitric acid train ‘‘t’’ (metric tons).
EFN2Ot = Average site-specific N2O emissions
factor for nitric acid train ‘‘t’’ (lb N2O
generated/ton acid produced, 100
percent acid basis).
Pa t = Annual nitric acid production from the
train ‘‘t’’ (ton acid produced, 100 percent
acid basis).
(Eq. V-1)
of information that could constitute
process knowledge include calculations
based on material balances, process
stoichiometry, or previous test results
provided the results are still relevant to
the current vent stream conditions. You
must document how process knowledge
(if applicable) was used to determine
the destruction efficiency.
(3) Calculate the destruction
efficiency by conducting an additional
performance test on the emissions
stream following the N2O abatement
technology.
(e) If applicable, you must determine
the abatement factor for each N2O
abatement technology. The abatement
factor is calculated for each nitric acid
train according to Equation V–2 of this
section.
AFN t =
Pa t Abate
(Eq. V-2)
Pa t
Where:
z
∑
( (
EFN 2Ot ∗ Pa t ∗ 1 − DFN t ∗ AFN t
))
2204.63
N =1
DFN t = Destruction efficiency of N2O
abatement technology N that is used on
nitric acid train ‘‘t’’ (percent of N2O
removed from air stream).
AFN t = Abatement factor of N2O abatement
technology for nitric acid train ‘‘t’’
(fraction of annual production that
abatement technology is operating).
2204.63 = Conversion factor (lb/metric ton).
AFN t = Abatement factor of N2O abatement
technology at nitric acid train ‘‘t’’
(fraction of annual production that
abatement technology is operating).
Pa t = Total annual nitric acid production
from nitric acid train ‘‘t’’ (ton acid
produced, 100 percent acid basis).
Pa t Abate = Annual nitric acid production from
nitric acid train ‘‘t’’ during which N2O
abatement was used (ton acid produced,
100 percent acid basis).
(f) You must determine the annual
amount of nitric acid produced and the
annual amount of nitric acid produced
while each N2O abatement technology is
operating from each nitric acid train
(100 percent basis).
(g) You must calculate N2O emissions
for each nitric acid train by multiplying
the emissions factor (determined in
Equation V–1 of this section) by the
annual nitric acid production and
accounting for N2O abatement,
according to Equation V–3 of this
section:
(Eq. V-3)
z = Number of different N2O abatement
technologies.
(h) You must determine the annual
nitric acid production emissions
combined from all nitric acid trains at
your facility using Equation V–4 of this
section:
m
N 2O = ∑ EN 2Ot
(Eq. V-4)
t =1
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E:\FR\FM\30OCR2.SGM
ER30OC09.082</MATH>
Where:
EFN2Ot = Average site-specific N2O emissions
factor for nitric acid train ‘‘t’’ (lb N2O
generated/ton nitric acid produced, 100
percent acid basis).
CN2O = N2O concentration for each test run
during the performance test (ppm N2O).
1.14 × 10¥7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas for
each test run during the performance test
(dscf/hr).
P = Production rate for each test run during
the performance test (tons nitric acid
produced per hour, 100 percent acid
basis).
n = Number of test runs.
1
ER30OC09.081</MATH>
EFN 2Ot =
C N 2O ∗1.14 × 10−7 ∗ Q
P
n
ER30OC09.080</MATH>
n
∑
(1) You may request Administrator
approval for an alternative method of
determining N2O concentration
according to the procedures in
paragraphs (a)(2)(i) and (a)(2)(ii) of this
section. Alternative methods include
the use of N2O CEMs.
(2) Using the results of the
performance test in paragraph (b) of this
section, you must calculate an average
site-specific emission factor for each
nitric acid train ‘‘t’’ according to
Equation V–1 of this section:
30OCR2
ER30OC09.079</MATH>
reporting period using the procedures
specified in paragraph (a)(1) of this
section.
(b) You must conduct an annual
performance test according to
paragraphs (b)(1) through (b)(3) of this
section.
(1) You must measure N2O emissions
from the absorber tail gas vent for each
nitric acid train using the methods
specified in § 98.224(b) through (d).
(2) You must conduct the
performance test under normal process
56445
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Where:
N2O = Annual process N2O emissions from
nitric acid production facility (metric
tons).
EN2Ot = N2O mass emissions per year for
nitric acid train ‘‘t’’ (metric tons).
m = Number of nitric acid trains.
sroberts on DSKD5P82C1PROD with RULES
§ 98.224 Monitoring and QA/QC
requirements.
(a) You must conduct a new
performance test and calculate a new
site-specific emissions factor according
to a test plan as specified in paragraphs
(a)(1) through (a)(3) of this section.
(1) Conduct the performance test
annually.
(2) Conduct the performance test
when your nitric acid production
process is changed, specifically when
abatement equipment is installed.
(3) If you requested Administrator
approval for an alternative method of
determining N2O concentration under
§ 98.223(a)(2), you must conduct the
performance test if your request has not
been approved by the Administrator
within 150 days of the end of the
reporting year in which it was
submitted.
(b) You must measure the N2O
concentration during the performance
test using one of the methods in
paragraphs (b)(1) through (b)(3) of this
section.
(1) EPA Method 320 at 40 CFR part
63, appendix A, Measurement of Vapor
Phase Organic and Inorganic Emissions
by Extractive Fourier Transform Infrared
(FTIR) Spectroscopy.
(2) ASTM D6348–03 Standard Test
Method for Determination of Gaseous
Compounds by Extractive Direct
Interface Fourier Transform Infrared
(FTIR) Spectroscopy (incorporated by
reference in § 98.7).
(3) An equivalent method, with
Administrator approval.
(c) You must determine the
production rate(s) (100 percent basis)
from each nitric acid train during the
performance test according to
paragraphs (c)(1) or (c)(2) of this section.
(1) Direct measurement of production
and concentration (such as using flow
meters, weigh scales, for production and
concentration measurements).
(2) Existing plant procedures used for
accounting purposes (i.e. dedicated
tank-level and acid concentration
measurements).
(d) You must conduct all performance
tests 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.
All QA/QC procedures specified in the
reference test methods and any
associated performance specifications
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17:39 Oct 29, 2009
Jkt 220001
apply. For each test, the facility must
prepare an emission factor
determination report that must include
the items in paragraphs (d)(1) through
(d)(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.
(e) You must determine the monthly
nitric acid production and the monthly
nitric acid production during which
N2O abatement technology is operating
from each nitric acid train according to
the methods in paragraphs (c)(1) or
(c)(2) of this section.
(f) You must determine the annual
nitric acid production and the annual
nitric acid production during which
N2O abatement technology is operating
for each train by summing the
respective monthly nitric acid
production quantities.
§ 98.225 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, a
substitute data value for the missing
parameter shall be used in the
calculations as specified in paragraphs
(a) and (b) of this section.
(a) For each missing value of nitric
acid production, the substitute data
shall be the best available estimate
based on all available process data or
data used for accounting purposes (such
as sales records).
(b) For missing values related to the
performance test, including emission
factors, production rate, and N2O
concentration, you must conduct a new
performance test according to the
procedures in § 98.224 (a) through (d).
§ 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 (o) of this
section for each nitric acid production
train.
(a) Train identification number.
(b) Annual process N2O emissions
from each nitric acid train (metric tons).
(c) Annual nitric acid production
from each nitric acid train (tons, 100
percent acid basis).
(d) Annual nitric acid production
from each nitric acid train during which
N2O abatement technology is operating
(ton acid produced, 100 percent acid
basis).
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Sfmt 4700
(e) Annual nitric acid production
from the nitric acid facility (tons, 100
percent acid basis).
(f) Number of nitric acid trains.
(g) Number of abatement technologies
(if applicable).
(h) Abatement technologies used (if
applicable).
(i) Abatement technology destruction
efficiency for each abatement
technology (percent destruction).
(j) Abatement utilization factor for
each abatement technology (fraction of
annual production that abatement
technology is operating).
(k) Type of nitric acid process used
for each nitric acid train (low, medium,
high, or dual pressure).
(l) Number of times in the reporting
year that missing data procedures were
followed to measure nitric acid
production (months).
(m) If you conducted a performance
test and calculated a site-specific
emissions factor according to
§ 98.223(a)(1), each annual report must
also contain the information specified in
paragraphs (m)(1) through (m)(7) of this
section for each nitric acid production
facility.
(1) Emission factor calculated for each
nitric acid train (lb N2O/ton nitric acid,
100 percent acid basis).
(2) Test method used for performance
test.
(3) Production rate per test run during
performance test (tons nitric acid
produced/hr, 100 percent acid basis).
(4) N2O concentration per test run
during performance test (ppm N2O).
(5) Volumetric flow rate per test run
during performance test (dscf/hr).
(6) Number of test runs during
performance test.
(7) Number of times in the reporting
year that a performance test had to be
repeated (number).
(n) If you requested Administrator
approval for an alternative method of
determining N2O concentration under
§ 98.223(a)(2), each annual report must
also contain the information specified in
paragraphs (n)(1) through (n)(4) of this
section for each nitric acid production
facility.
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(o) Total pounds of synthetic fertilizer
produced through and total nitrogen
contained in that fertilizer.
§ 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)
through (g) of this section for each nitric
acid production facility:
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(a) Records of significant changes to
process.
(b) Documentation of how process
knowledge was used to estimate
abatement technology destruction
efficiency (if applicable).
(c) Performance test reports.
(d) Number of operating hours in the
calendar year for each nitric acid train
(hours).
(e) Annual nitric acid permitted
production capacity (tons).
(f) Measurements, records, and
calculations used to determine reported
parameters.
(g) Documentation of the procedures
used to ensure the accuracy of the
measurements of all reported
parameters, including but not limited to,
calibration of weighing equipment, flow
meters, 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.
§ 98.228
Subpart W—[Reserved]
Subpart X—Petrochemical Production
sroberts on DSKD5P82C1PROD with RULES
Definition of the source category.
(a) The petrochemical production
source category consists of all processes
that produce acrylonitrile, carbon black,
ethylene, ethylene dichloride, ethylene
oxide, or methanol, except as specified
in paragraphs (b) through (f) of this
section. The source category includes
processes that produce the
petrochemical as an intermediate in the
onsite production of other chemicals as
well as processes that produce the
petrochemical as an end product for sale
or shipment offsite.
(b) A process that produces a
petrochemical as a byproduct is not part
of the petrochemical production source
category.
(c) A facility that makes methanol,
hydrogen, and/or ammonia from
synthesis gas is part of the
petrochemical source category if the
annual mass of methanol produced
exceeds the individual annual mass
production levels of both hydrogen
recovered as product and ammonia. The
facility is part of subpart P of this part
(Hydrogen Production) if the annual
mass of hydrogen recovered as product
exceeds the individual annual mass
production levels of both methanol and
ammonia. The facility is part of subpart
G of this part (Ammonia Manufacturing)
VerDate Nov<24>2008
17:39 Oct 29, 2009
§ 98.241
Jkt 220001
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a petrochemical process as
specified in § 98.240, and the facility
meets the requirements of either
§ 98.2(a)(1) or (2).
§ 98.242
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.240
if the annual mass of ammonia
produced exceeds the individual annual
mass production levels of both
hydrogen recovered as product and
methanol.
(d) A direct chlorination process that
is operated independently of an
oxychlorination process to produce
ethylene dichloride is not part of the
petrochemical production source
category.
(e) A process that produces bone
black is not part of the petrochemical
source category.
(f) A process that produces a
petrochemical from bio-based feedstock
is not part of the petrochemical
production source category.
GHGs to report.
You must report the information in
paragraphs (a) through (c) of this
section:
(a) CO2 CH4, and N2O process
emissions from each petrochemical
process unit. Process emissions include
CO2 generated by reaction in the process
and by combustion of process off-gas in
stationary combustion units and flares.
(1) If you comply with § 98.243(b) or
(d), report under this subpart the
calculated CO2, CH4, and N2O emissions
for each stationary combustion source
and flare that burns any amount of
petrochemical process off-gas.
(2) If you comply with § 98.243(c),
report under this subpart the calculated
CO2 emissions for each petrochemical
process unit.
(b) CO2, CH4, and N2O combustion
emissions from stationary combustion
units and flares.
(1) If you comply with § 98.243(b) or
(d), report these emissions from
stationary combustion units that are
associated with petrochemical process
units and burn only supplemental fuel
under subpart C of this part (General
Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
(2) If you comply with § 98.243(c),
report CO2, CH4, and N2O combustion
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C only for the combustion of
supplemental fuel. Determine the
applicable Tier in subpart C of this part
(General Stationary Fuel Combustion
Sources) based on the maximum rated
heat input capacity of the stationary
combustion source.
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56447
(c) CO2 captured. You must report the
mass of CO2 captured under, subpart PP
of this part (Suppliers of Carbon Dioxide
(CO2) by following the requirements of
subpart PP.
§ 98.243
Calculating GHG emissions.
(a) If you route all process vent
emissions and emissions from
combustion of process off-gas to one or
more stacks and use CEMS on each
stack to measure CO2 emissions (except
flare stacks), then you must determine
process-based GHG emissions in
accordance with paragraph (b) of this
section. Otherwise, determine processbased GHG emissions in accordance
with the procedures specified in
paragraph (c) or (d) of this section.
(b) Continuous emission monitoring
system (CEMS). Route all process vent
emissions and emissions from
combustion of process off-gas to one or
more stacks and determine CO2
emissions from each stack (except flare
stacks) according to the Tier 4
Calculation Methodology requirements
in subpart C of this part. For each stack
(except flare stacks) that includes
emissions from combustion of
petrochemical process off-gas, calculate
CH4 and N2O emissions in accordance
with subpart C of this part (use the Tier
3 methodology and emission factors for
‘‘Petroleum’’ in Table C–2 of subpart C
of this part). For each flare, calculate
CO2, CH4, and N2O emissions using the
methodology specified in § 98.253(b)(1)
through (b)(3).
(c) Mass balance for each
petrochemical process unit. Calculate
the emissions of CO2 from each process
unit, for each calendar month as
described in paragraphs (c)(1) through
(c)(5) of this section.
(1) For each gaseous and liquid
feedstock and product, measure the
volume or mass used or produced each
calendar month with a flow meter by
following the procedures specified in
§ 98.244(b)(2). Alternatively, for liquids,
you may calculate the volume used or
collected in each month based on
measurements of the liquid level in a
storage tank at least once per month
(and just prior to each change in
direction of the level of the liquid)
following the procedures specified in
§ 98.244(b)(3). Fuels used for
combustion purposes are not considered
to be feedstocks.
(2) For each solid feedstock and
product, measure the mass used or
produced each calendar month by
following the procedures specified in
§ 98.244(b)(1).
(3) Collect a sample of each feedstock
and product at least once per month and
determine the carbon content of each
E:\FR\FM\30OCR2.SGM
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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 (c)(4) along with all
supporting data, calculations, and other
information. This alternative may not be
used for products during periods of
operation when off-specification
product is produced. You must
reevaluate determinations made under
this paragraph (c)(4) after any process
change that affects the feedstock or
product composition. You must keep
records of the process change and the
corresponding composition
( )i,n ∗ (CCgf )i,n ∗
Where:
Cg = Annual net contribution to calculated
emissions from carbon (C) in gaseous
materials (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i
introduced in month ‘‘n’’ (standard cubic
feet, scf).
(CCgf)i,n = Average carbon content of the
gaseous feedstock i for month ‘‘n’’ (kg C
per kg of feedstock).
(MWf)i = Molecular weight of gaseous
feedstock i (kg/kg-mole).
( MW f )i
MVC
( )i,n ∗ (CCgp )i,n ∗
− Pgp
MVC = Molar volume conversion factor
(849.5 scf per kg-mole at standard
conditions).
(Pgp)i,n = Volume of gaseous product i
produced in month ‘‘n’’ (scf).
(CCgp)i,n = Average carbon content of gaseous
product i, including streams containing
CO2 recovered for sale or use in another
process, for month ‘‘n’’ (kg C per kg of
product).
(MWp)i = Molecular weight of gaseous
product i (kg/kg-mole).
12 ⎡ j or k
Cl = ∑ ⎢ ∑ ⎡ Flf
⎢
⎣
⎢
n =1 ⎣ i=1
⎥
⎦
(CClf)i,n = Average carbon content of liquid
feedstock i for month ‘‘n’’ (kg C per
gallon or kg of feedstock).
(Plp)i,n = Volume or mass of liquid product i
produced in month ‘‘n’’ (gallons or kg).
(CClp)i,n = Average carbon content of liquid
product i, including organic liquid
wastes, for month ‘‘n’’ (kg C per gallon
or kg of product).
j = Number of feedstocks.
(iii) Solid feedstocks and products.
Use Equation X–3 of this section to
calculate the net annual carbon input or
output from solid feedstocks and
products. Note that the result will be a
negative value if there are no solid
feedstocks in the process but there are
solid products.
⎫
sroberts on DSKD5P82C1PROD with RULES
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
⎪
⎭
(CCsf)i,n = Average carbon content of solid
feedstock i for month ‘‘n’’ (kg C per kg
of feedstock).
(Psp)i,n = Mass of solid product i produced in
month ‘‘n’’ (kg).
(CCsp)i,n = Average carbon content of solid
product i in month ‘‘n’’ (kg C per kg of
product).
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Fmt 4701
Sfmt 4700
(Eq. X-2)
k = Number of products.
( )i,n ∗ (CCsf )i,n − ( Psp )i,n ∗ (CCsp )i,n ⎤ ⎪
⎥⎬
⎦
Where:
Cs = Annual net contribution to calculated
emissions from carbon in solid materials
(kg/yr).
(Fsf)i,n = Mass of solid feedstock i introduced
in month ‘‘n’’ (kg).
(Eq. X-1)
(ii) Liquid feedstocks and products.
Use Equation X–2 of this section to
calculate the net carbon input or output
from liquid feedstocks and products.
Note that the result will be a negative
value if there are no liquid feedstocks in
the process but there are liquid
products.
⎤
12 ⎧ j or k
⎪
Cs = ∑ ⎨ ∑ ⎡ Fsf
⎢
⎣
⎪
n =1 ⎩ i=1
MVC ⎥ ⎥
⎦⎦
j = Number of feedstocks.
k = Number of products.
( )i,n ∗ (CClf )i,n − ( Plp )i,n ∗ (CClp )i,n ⎤ ⎥
⎥
⎦
Where:
Cl = Annual net contribution to calculated
emissions from carbon in liquid
materials, including liquid organic
wastes (kg/yr).
(Flf)i,n = Volume or mass of liquid feedstock
i introduced in month ‘‘n’’ (gallons or
kg).
( MW p )i ⎤ ⎤
⎥⎥
(Eq. X-3)
j = Number of feedstocks.
k = Number of products.
(iv) Annual emissions. Use the results
from Equations X–1 through X–3 of this
section, as applicable, in Equation X–4
of this section to calculate annual CO2
emissions.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.085</MATH>
⎡ j or k ⎡
C g = ∑ ⎢ ∑ ⎢ Fgf
⎢
n =1 i=1 ⎢
⎣
⎣
12
determinations. If the feedstock or
product composition changes so that the
average monthly concentration falls
below 99.5 percent, you are no longer
permitted to use this alternative
method.
(5) Calculate the CO2 mass emissions
for each petrochemical process unit
using Equations X–1 through X–4 of this
section.
(i) Gaseous feedstocks and products.
Use Equation X–1 of this section to
calculate the net annual carbon input or
output from gaseous feedstocks and
products. Note that the result will be a
negative value if there are no gaseous
feedstocks in the process but there are
gaseous products.
ER30OC09.084</MATH>
sample according to the procedures in
§ 98.244(b)(4). Alternatively, you may
use the results of analyses conducted by
a fuel or feedstock supplier, provided
the sampling and analysis are
conducted at least once per month using
any of the procedures specified in
§ 98.244(b)(4). If multiple valid carbon
content measurements are made during
the monthly measurement period,
average them arithmetically.
(4) If you determine that the monthly
average concentration of a specific
compound in a feedstock or product is
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 (c)(3) of this
ER30OC09.083</MATH>
56448
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Where:
CO2 = Annual CO2 mass emissions from
process operations and process off-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).
(d) Optional combustion methodology
for ethylene production processes. For
any ethylene production process,
calculate CO2 emissions from
combustion of fuel that contains
ethylene process off-gas using the Tier
3 or Tier 4 methodology in subpart C of
this part, and calculate CH4 and N2O
emissions using the applicable
procedures in § 98.33(c) (use the
emission factors for ‘‘Petroleum’’ in
Table C–2 of subpart C of this part
(General Stationary Fuel Combustion
Sources)). You are not required to use
the same Tier for each stationary
combustion unit that burns ethylene
process off-gas. For each flare, calculate
CO2, CH4, and N2O emissions using the
methodology specified in § 98.253(b)(1)
through (b)(3).
sroberts on DSKD5P82C1PROD with RULES
§ 98.244 Monitoring and QA/QC
requirements.
(a) If you use CEMS to determine
emissions from process vents, you must
comply with the procedures specified in
§ 98.34(c).
(b) If you use the mass balance
methodology in § 98.243(c), use the
procedures specified in paragraphs
(b)(1) through (b)(4) of this section to
determine feedstock and product flows
and carbon contents.
(1) Operate and maintain belt scales
or other weighing devices as described
in Specifications, Tolerances, and Other
Technical Requirements For Weighing
and Measuring Devices NIST Handbook
44 (2009) (incorporated by reference, see
§ 98.7) or follow procedures specified by
the measurement device manufacturer.
Calibrate the measurement device
according to the procedures specified by
the method, the procedures specified by
the manufacturer, or § 98.3(i).
Recalibrate either biennially or at the
minimum frequency specified by the
manufacturer.
(2) Operate and maintain all flow
meters for gas and liquid feedstocks and
products by following the procedures in
§ 98.3(i) and using any of the flow meter
methods specified in paragraphs (b)(2)(i)
through (b)(2)(xv) of this section, as
applicable, use a standard method
published by a consensus-based
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
44
∗ C g + Cl + Cs
12
(
)
(Eq. X-4)
standards organization (e.g., ASTM,
API, etc.), or follow procedures
specified by the flow meter
manufacturer or § 98.3(i). Recalibrate
each flow meter either biennially or at
the minimum frequency specified by the
manufacturer.
(i) ASME MFC–3M–2004
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi
(incorporated by reference, see § 98.7).
(ii) ASME MFC–4M–1986 (Reaffirmed
1997) Measurement of Gas Flow by
Turbine Meters (incorporated by
reference, see § 98.7).
(iii) ASME MFC–5M–1985
(Reaffirmed 1994) Measurement of
Liquid Flow in Closed Conduits Using
Transit-Time Ultrasonic Flowmeters
(incorporated by reference, see § 98.7).
(iv) ASME MFC–6M–1998
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters (incorporated
by reference, see § 98.7).
(v) ASME MFC–7M–1987 (Reaffirmed
1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles
(incorporated by reference, see § 98.7).
(vi) ASME MFC–9M–1988
(Reaffirmed 2001) Measurement of
Liquid Flow in Closed Conduits by
Weighing Method (incorporated by
reference, see § 98.7).
(vii) ASME MFC–11M–2006
Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters (incorporated
by reference, see § 98.7).
(viii) ASME MFC–14M–2003
(Reaffirmed 2008), Measurement of
Fluid Flow Using Small Bore Precision
Orifice Meters (incorporated by
reference, see § 98.7).
(ix) ASME MFC–16–2007
Measurement of Liquid Flow in Closed
Conduits with Electromagnetic
Flowmeters (incorporated by reference,
see § 98.7).
(x) ASME MFC–18M–2001
(Reaffirmed 2006), Measurement of
Fluid Flow Using Variable Area Meters
(incorporated by reference, see § 98.7).
(xi) ASME MFC–22–2007
Measurement of Liquid by Turbine
Flowmeters (incorporated by reference,
see § 98.7).
(xii) AGA Report No. 3: Orifice
Metering of Natural Gas and Other
Related Hydrocarbon Fluids, Part 1:
General Equations and Uncertainty
Guidelines (1990), Part 2: Specification
and Installation Requirements (2000)
(incorporated by reference, see § 98.7).
(xiii) AGA Transmission
Measurement Committee Report No. 7:
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Measurement of Natural Gas by Turbine
Meter (2006)/February (incorporated by
reference, see § 98.7).
(xiv) AGA Report No. 11:
Measurement of Natural Gas by Coriolis
Meter (2003) (incorporated by reference,
see § 98.7).
(xv) ISO 8316: Measurement of Liquid
Flow in Closed Conduits—Method by
Collection of the Liquid in a Volumetric
Tank (1987–10–01) First Edition
(incorporated by reference, see § 98.7).
(3) Perform tank level measurements
(if used to determine feedstock or
product flows) according to any
standard method published by a
consensus-based standards organization
(e.g., ASTM, API, etc.) or follow
procedures specified by the
measurement device manufacturer or
§ 98.3(i). Calibrate the measurement
devices prior to the effective date of the
rule, and recalibrate either biennially or
at the minimum frequency specified by
the manufacturer or § 98.3(i).
(4) Use any of the standard methods
specified in paragraphs (b)(4)(i) through
(b)(4)(x) of this section, as applicable, to
determine the carbon content or
composition of feedstocks and products
and the average molecular weight of
gaseous feedstocks and products.
Calibrate instruments in accordance
with the method and as specified in
paragraphs (b)(4)(i) through (b)(4)(x), as
applicable. 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 monthly period. For
carbon black products, samples shall be
taken of each grade or type of product
produced during the monthly period.
Samples of coal feedstock or carbon
black product for carbon content
determinations may be either grab
samples collected and analyzed
monthly or a composite of samples
collected more frequently and analyzed
monthly. Analyses conducted in
accordance with methods specified in
paragraphs (b)(4)(i) through (b)(4)(x) of
this section may be performed by the
owner or operator, by an indpendent
laboratory, or by the supplier of a
feedstock.
(i) ASTM D1945–03, Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(ii) ASTM D6060–96 (Reapproved
2001) Standard Practice for Sampling of
Process Vents With a Portable Gas
E:\FR\FM\30OCR2.SGM
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ER30OC09.086</MATH>
CO2 = 0.001 ∗
56449
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Chromatograph (incorporated by
reference, see § 98.7).
(iii) ASTM D2505–88(Reapproved
2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and
Carbon Dioxide in High-Purity Ethylene
by Gas Chromatography (incorporated
by reference, see § 98.7).
(iv) ASTM UOP539–97 Refinery Gas
Analysis by Gas Chromatography
(incorporated by reference, see § 98.7).
(v) ASTM D3176–89 (Reapproved
2002) Standard Practice Method for
Ultimate Analysis of Coal and Coke
(incorporated by reference, see § 98.7).
(vi) ASTM D5291–02 (Reapproved
2007) Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants (incorporated
by reference, see § 98.7).
(vii) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
(viii) 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.
(ix) Method 18 at 40 CFR part 60,
appendix A–6.
(x) Performance Specification 9 in 40
CFR part 60, appendix B for continuous
online gas analyzers. The 7-day
calibration error test period must be
completed prior to the effective date of
the rule.
§ 98.245 Procedures for estimating
missing data.
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.
sroberts on DSKD5P82C1PROD with RULES
§ 98.246
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a), (b), or (c) of this
section, as appropriate for each process
unit.
(a) If you use the mass balance
methodology in § 98.243(c), you must
report the information specified in
paragraphs (a)(1) through (a)(10) of this
section for each type of petrochemical
produced, reported by process unit.
(1) The petrochemical process unit ID
number or other appropriate descriptor.
(2) The type of petrochemical
produced, names of other products, and
names of carbon-containing feedstocks.
(3) Annual CO2 emissions calculated
using Equation X–4 of this subpart.
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(4) Each of the monthly volume, mass,
and carbon content values used in
Equations X–1 through X–3 of this
subpart (i.e., the directly measured
values, substitute values, or the
calculated values based on other
measured data such as tank levels or gas
composition) and the molecular weights
for gaseous feedstocks and products
used in Equation X–1 of this subpart.
Indicate whether you used the
alternative to sampling and analysis
specified in § 98.243(c)(4).
(5) Annual quantity of each type of
petrochemical produced from each
process unit (metric tons).
(6) Name of each method listed in
§ 98.244 used to determine a measured
parameter (or description of
manufacturer’s recommended method).
(7) The dates and summarized results
(e.g., percent calibration error) of the
calibrations of each measurement
device.
(8) Identification of each combustion
unit that burned both process off-gas
and supplemental fuel.
(9) If you comply with the alternative
to sampling and analysis specified in
§ 98.243(c)(4), the amount of time
during which off-specification product
was produced, the volume or mass of
off-specification product produced, and
if applicable, the date of any process
change that reduced the composition to
less than 99.5 percent.
(10) You may elect to report the flow
and carbon content of wastewater, and
you may elect to report the carbon
content of hydrocarbons in fugitive
emissions and in process vents that are
not controlled with a combustion
device. These values may be estimated
based on engineering analyses. These
values are not to be used in the mass
balance calculation.
(b) If you use CEMS to measure CO2
emissions in accordance with
§ 98.243(b), then you must report the
relevant information required under
§ 98.36 for the Tier 4 Calculation
Methodology and the information listed
in paragraphs (b)(1) through (b)(6) of
this section.
(1) For CEMS used on stacks for
stationary combustion units, report the
relevant information required under
§ 98.36 for the Tier 4 calculation
methodology.
(2) For CEMS used on stacks that are
not used for stationary combustion
units, report the information required
under § 98.36(e)(2)(vi) and (vii).
(3) The petrochemical process unit ID
or other appropriate descriptor, and the
type of petrochemical produced.
(4) The CO2 emissions from each stack
and the combined CO2 emissions from
all stacks (except flare stacks) that
PO 00000
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Fmt 4701
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handle process vent emissions and
emissions from stationary combustion
units that burn process off-gas for the
petrochemical process unit. If a
stationary combustion source serves
multiple petrochemical process units or
units other than the petrochemical
process unit, estimate based on
engineering judgment the fraction of
fuel energy and emissions attributable to
each petrochemical process unit.
(5) The CH4 and N2O emissions from
each stack and the combined CH4 and
N2O emissions from all stationary
combustion units that burn process offgas from the petrochemical process unit,
the cumulative annual heat input used
in Equation C–10 in § 98.33(c) of this
subpart, and the annual flow of each
fuel on which this heat input is based.
(6) ID or other appropriate descriptor
of each stationary combustion unit that
burns process off-gas.
(7) Information listed in § 98.256(e) of
subpart Y of this part for each flare that
burns process off-gas.
(8) Annual quantity of each type of
petrochemical produced from each
process unit (metric tons).
(c) If you comply with the combustion
methodology specified in § 98.243(d),
you must report under this subpart the
information listed in paragraphs (c)(1)
through (c)(4) of this section.
(1) For each stationary combustion
unit that burns ethylene process off-gas
(or group of stationary sources with a
common pipe), the relevant information
listed in § 98.36 for the selected Tier 3
or Tier 4 methodology. If a stationary
combustion source serves multiple
ethylene process units or units other
than the ethylene process unit, estimate
based on engineering judgment the
fraction of fuel energy and emissions
attributable to each ethylene process
unit.
(2) Information listed in § 98.256(e)
for each flare that burns ethylene
process off-gas.
(3) Name and annual quantity of each
feedstock.
(4) Annual quantity of each type of
petrochemical produced from each
process unit (metric tons).
§ 98.247
Records that must be retained.
In addition to the recordkeeping
requirements in § 98.3(g), you must
retain the records specified in
paragraphs (a) through (c) of this
section, as applicable.
(a) If you comply with the CEMS
measurement methodology in
§ 98.243(b), then you must retain under
this subpart the records required for the
Tier 4 Calculation Methodology in
§ 98.37.
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(b) If you comply with the mass
balance methodology in § 98.243(c),
then you must retain records of the
information listed in paragraphs (b)(1)
through (b)(3) of this section.
(1) Results of feedstock or product
composition determinations conducted
in accordance with § 98.243(c)(4).
(2) 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(c)(4) for
determining carbon content of feedstock
or product.
(3) A part of the monitoring plan
required under § 98.3(g)(5), record the
estimated accuracy of measurement
devices and the technical basis for these
estimates.
(c) If you comply with the combustion
methodology in § 98.243(d), then you
must retain under this subpart the
records required for the Tier 3 and/or
Tier 4 Calculation Methodologies in
§ 98.37.
§ 98.248
Definitions.
Except as specified in this section, all
terms used in this subpart have the
same meaning given in the Clean Air
Act and subpart A of this part.
Product, as used in § 98.243, means
each of the following carbon-containing
outputs from a process: the
petrochemical, recovered byproducts,
and liquid organic wastes that are not
incinerated onsite. Product does not
include process vent emissions, fugitive
emissions, or wastewater.
Subpart Y—Petroleum Refineries
sroberts on DSKD5P82C1PROD with RULES
§ 98.250
Definition of source category.
(a) A petroleum refinery is any facility
engaged in producing gasoline, gasoline
blending stocks, naphtha, kerosene,
distillate fuel oils, residual fuel oils,
lubricants, or asphalt (bitumen) through
distillation of petroleum or through
redistillation, cracking, or reforming of
unfinished petroleum derivatives,
except as provided in paragraph (b) of
this section.
(b) For the purposes of this subpart,
facilities that distill only pipeline
transmix (off-spec material created
when different specification products
mix during pipeline transportation) are
not petroleum refineries, regardless of
the products produced.
(c) This source category consists of
the following sources at petroleum
refineries: Catalytic cracking units; fluid
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coking units; delayed coking units;
catalytic reforming units; coke calcining
units; asphalt blowing operations;
blowdown systems; storage tanks;
process equipment components
(compressors, pumps, valves, pressure
relief devices, flanges, and connectors)
in gas service; marine vessel, barge,
tanker truck, and similar loading
operations; flares; sulfur recovery
plants; and non-merchant hydrogen
plants (i.e., hydrogen plants that are
owned or under the direct control of the
refinery owner and operator).
§ 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 (a)(2).
§ 98.252
GHGs to report.
You must report:
(a) CO2, CH4, and N2O combustion
emissions from stationary combustion
units and from each flare. Calculate and
report these emissions under subpart C
of this part (General Stationary Fuel
Combustion Sources) by following the
requirements of subpart C, except for
CO2 emissions from combustion of
refinery fuel gas. For CO2 emissions
from combustion of fuel gas, use either
equation C–5 in subpart C of this part
or the Tier 4 methodology in subpart C
of this part. You may aggregate units,
monitor common stacks, or monitor
common (fuel) pipes as provided in
§ 98.36(c) when calculating and
reporting emissions from stationary
combustion units.
(b) CO2, CH4, and N2O coke burn-off
emissions from each catalytic cracking
unit, fluid coking unit, and catalytic
reforming unit under this subpart.
(c) CO2 emissions from sour gas sent
off site for sulfur recovery operations
under this subpart. You must follow the
calculation methodologies from
§ 98.253(f) and the monitoring and QA/
QC methods, missing data procedures,
reporting requirements, and
recordkeeping requirements of this
subpart.
(d) CO2 process emissions from each
on-site sulfur recovery plant under this
subpart.
(e) CO2, CH4, and N2O emissions from
each coke calcining unit under this
subpart.
(f) CO2 and CH4 emissions from
asphalt blowing operations under this
subpart.
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56451
(g) CH4 emissions from equipment
leaks, storage tanks, loading operations,
delayed coking units, and uncontrolled
blowdown systems under this subpart.
(h) CO2, CH4, and N2O emissions from
each process vent not specifically
included in paragraphs (a) through (g) of
this section under this subpart.
(i) CO2 and CH4 emissions from nonmerchant hydrogen production under
this subpart. You must follow the
calculation methodologies, 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) Calculate GHG emissions required
to be reported in § 98.252(b) through (i)
using the applicable methods in
paragraphs (b) through (n) of this
section.
(b) For flares, calculate GHG
emissions according to the requirements
in paragraphs (b)(1) through (b)(3) of
this section.
(1) Calculate the CO2 emissions
according to the applicable
requirements in paragraphs (b)(1)(i)
through (b)(1)(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 and the
flow rate is within the calibrated range
of the measurement device to calculate
the flare gas flow. If you do not have a
continuous flow monitor on the flare
and for periods when the monitor is not
operational or the flow rate is outside
the calibrated range of the measurement
device, you must use engineering
calculations, company records, or
similar estimates of volumetric flare gas
flow.
(ii) Heat value or carbon content
measurement. If you have a continuous
higher heating value monitor or gas
composition monitor on the flare or if
you monitor these parameters at least
weekly, you must use the measured heat
value or carbon content value in
calculating the CO2 emissions from the
flare using the applicable methods in
paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).
(A) If you monitor gas composition,
calculate the CO2 emissions from the
flare using Equation Y–1 of this section.
If daily or more frequent measurement
data are available, you must use daily
values when using Equation Y–1 of this
section; otherwise, use weekly values.
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
⎛ n
CO2 = 0.98 × 0.001× ⎜ ∑
⎜ p =1
⎝
Where:
CO2 = Annual CO2 emissions for a specific
fuel type (metric tons/year).
0.98 = Assumed combustion efficiency of a
flare.
0.001 = Unit conversion factor (metric tons
per kilogram, mt/kg).
n = Number of measurement periods. The
minimum value for n is 52 (for weekly
measurements); the maximum value for
n is 366 (for daily measurements during
a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
( MW ) p
⎡ 44
⎤⎞
× (CC ) p ⎥ ⎟
⎢ × ( Flare ) p ×
MVC
⎣ 12
⎦⎟
⎠
(Flare)p = Volume of flare gas combusted
during measurement period (standard
cubic feet per period, scf/period). If a
mass flow meter is used, measure flare
gas flow rate in kg/period and replace
the term ‘‘(MW)p/MVC’’ with ‘‘1’’.
(MW)p = Average molecular weight of the
flare gas combusted during measurement
period (kg/kg-mole). If measurements are
taken more frequently than daily, use the
arithmetic average of measurement
values within the day to calculate a daily
average.
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
(Eq. Y-1)
(CC)p = Average carbon content of the flare
gas combusted during measurement
period (kg C per kg flare gas). If
measurements are taken more frequently
than daily, use the arithmetic average of
measurement values within the day to
calculate a daily average.
(B) If you monitor heat content but do
not monitor gas composition, calculate
the CO2 emissions from the flare using
Equation Y–2 of this section. If daily or
more frequent measurement data are
available, you must use daily values
when using Equation Y–2 of this
section; otherwise, use weekly values.
n
CO2 = 0.98 × 0.001× ∑ ⎡( Flare) p × ( HHV ) p × EmF ⎤
⎣
⎦
(Eq. Y-2)
p =1
sroberts on DSKD5P82C1PROD with RULES
n
⎛
CO2 = 0.98 × 0.001× ⎜ FlareNorm × HHV × EmF + ∑
⎜
p =1
⎝
Where:
CO2 = Annual CO2 emissions for a specific
fuel type (metric tons/year).
0.98 = Assumed combustion efficiency of a
flare.
0.001 = Unit conversion factor (metric tons
per kilogram, mt/kg).
FlareNorm = 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 fuel gas or
flare gas from company records (British
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17:39 Oct 29, 2009
Jkt 220001
( MW ) p
⎡ 44
⎤⎞
× (CC ) p ⎥ ⎟
⎢ × ( FlareSSM ) p ×
MVC
⎣ 12
⎦⎟
⎠
thermal units per scf, Btu/scf = MMBtu/
MMscf).
EmF = Default CO2 emission factor for flare
gas of 60 kilograms CO2/MMBtu (HHV
basis).
n = Number of start-up, shutdown, and
malfunction events during the reporting
year exceeding 500,000 scf/day.
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)p = Volume of flare gas combusted
during indexed start-up, shutdown, or
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Fmt 4701
Sfmt 4700
(Eq. Y-3)
malfunction event from engineering
calculations, (scf/event).
(MW)p = Average molecular weight of the
flare gas, from the analysis results or
engineering calculations for the event
(kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
(CC)p = Average carbon content of the flare
gas, from analysis results or engineering
calculations for the event (kg C per kg
flare gas).
(2) Calculate CH4 using Equation Y–
4 of this section.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.089</MATH>
(iii) Alternative to heat value or
carbon content measurements. If you do
not measure the higher heating value or
carbon content of the flare gas at least
weekly, 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 (b)(1)(iii)(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 exceeding 500,000
scf/day.
(B) For periods of normal operation,
use the average heating value measured
for the fuel gas for the heating value of
the flare gas. If heating value is not
measured, the heating value may be
estimated from historic data or
engineering calculations.
(C) Calculate the CO2 emissions using
Equation Y–3 of this section.
ER30OC09.088</MATH>
(MW)p is the average molecular weight of
the flare gas combusted during
measurement period (kg/kg-mole).
(HHV)p = Higher heating value for the flare
gas combusted during measurement
period (British thermal units per scf,
Btu/scf = MMBtu/MMscf). If
measurements are taken more frequently
than daily, use the arithmetic average of
measurement values within the day to
calculate a daily average.
EmF = Default CO2 emission factor of 60
kilograms CO2/MMBtu (HHV basis).
ER30OC09.087</MATH>
Where:
CO2 = Annual CO2 emissions for a specific
fuel type (metric tons/year).
0.98 = Assumed combustion efficiency of a
flare.
0.001 = Unit conversion factor (metric tons
per kilogram, mt/kg).
n = Number of measurement periods. The
minimum value for n is 52 (for weekly
measurements); the maximum value for
n is 366 (for daily measurements during
a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted
during measurement period (million
(MM) scf/period). If a mass flow meter is
used, you must also measure molecular
weight and convert the mass flow to a
volumetric flow as follows: Flare[MMscf]
= 0.000001 × Flare[kg] × MVC/(MW)p,
where MVC is the molar volume
conversion factor (849.5 scf/kg-mole) and
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(Eq. Y-5)
Where:
N2O = Annual nitrous oxide emissions from
flared gas (metric tons N2O/year).
CO2 = Emission rate of CO2 from flared gas
calculated in paragraph (b)(1) of this
section (metric tons/year).
CO2 =
⎡
n
( %CO2 + %CO ) p
⎣
100%
∑ ⎢( Qr ) p ×
⎢
p =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
sroberts on DSKD5P82C1PROD with RULES
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).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
×
⎤
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
there is no post-combustion device,
assume %CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
( 79 ∗ Qa + (100 − %Ooxy ) ∗ Qoxy )
100 − %CO2 − %CO − %O2
Frm 00195
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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–7 of this section.
(Eq. Y-7)
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).
PO 00000
(Eq. Y-6)
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).
E:\FR\FM\30OCR2.SGM
er30oc09.093</MATH>
EmFN2O ⎞
⎛
N 2O = ⎜ CO 2 ×
EmF ⎟
⎝
⎠
(c) For catalytic cracking units and
traditional fluid coking units, calculate
the GHG emissions using the applicable
methods described in paragraphs (c)(1)
through (c)(5) of this section.
(1) If you operate and maintain a
CEMS that measures CO2 emissions
according to subpart C of this part
(General Stationary Fuel Combustion
Sources), you must calculate and report
CO2 emissions as provided in
paragraphs (c)(1)(i) and (c)(1)(ii) of this
section. Other catalytic cracking units
and traditional fluid coking units must
either install a CEMS that complies with
the Tier 4 Calculation Methodology in
subpart C of this part (General
Stationary Combustion Sources), or
follow the requirements of paragraphs
(c)(2) or (3) of this section.
(i) Calculate CO2 emissions by
following the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
(ii) If a CO boiler or other postcombustion device is used, you must
also calculate the CO2 emissions from
the fuel fired to the CO boiler or postcombustion device using the applicable
methods for stationary combustion units
in subpart C of this part. Calculate the
process emissions from the catalytic
cracking unit or fluid coking unit as the
difference in the CO2 CEMS emissions
and the calculated combustion
emissions associated with the CO boiler.
(2) For catalytic cracking units and
fluid coking units with rated capacities
greater than 10,000 barrels per stream
day (bbls/sd) that do not use a
continuous CO2 CEMS for the final
exhaust stack, you must continuously or
no less frequently than hourly monitor
the O2, CO2, and (if necessary) CO
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 (c)(2)(iii) of this section:
(i) Calculate the CO2 emissions from
each catalytic cracking unit and fluid
coking unit using Equation Y–6 of this
section.
er30oc09.092</MATH>
(3) Calculate N2O emissions using
Equation Y–5 of this section.
EmFN2O = Default N2O emission factor for
‘‘PetroleumProducts’’ from Table C–2 of
subpart C of this part (General Stationary
Fuel Combustion Sources) (kg N2O/
MMBtu).
EmF = Default CO2 emission factor for flare
gas of 60 kg CO2/MMBtu (HHV basis).
30OCR2
ER30OC09.091</MATH>
Where:
CH4 = Annual methane emissions from flared
gas (metric tons CH4/year).
CO2 = Emission rate of CO2 from flared gas
calculated in paragraph (b)(1) of this
section (metric tons/year).
EmFCH4 = Default CH4 emission factor for
‘‘PetroleumProducts’’ from Table C–2 of
subpart C of this part (General Stationary
Fuel Combustion Sources) (kg CH4/
MMBtu).
EmF = Default CO2 emission factor for flare
gas of 60 kg CO2/MMBtu (HHV basis).
0.02/0.98 = Correction factor for flare
combustion efficiency.
16/44 = Correction factor ratio of the
molecular weight of CH4 to CO2.
fCH4 = Weight fraction of carbon in the flare
gas prior to combustion that is
contributed by methane from
measurement values or engineering
calculations (kg C in methane in flare
gas/kg C in flare gas); default is 0.4.
(Eq. Y-4)
ER30OC09.090</MATH>
EmFCH4 ⎞
0.02 16
⎛
CH 4 = ⎜ CO 2 ×
+ CO2 ×
× × fCH 4
0.98 44
EmF ⎟
⎝
⎠
56453
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
under 40 CFR part 63 subpart UUU,
assume %CO to be zero.
(iii) If you have a CO boiler that uses
auxiliary fuels or combusts materials
other than catalytic cracking unit or
fluid coking unit exhaust gas, you must
determine the CO2 emissions resulting
from the combustion of these fuels or
other materials following the
requirements in subpart C and report
those emissions by following the
requirements of subpart C of this part.
(3) For catalytic cracking units and
fluid coking units with rated capacities
of 10,000 barrels per stream day (bbls/
sd) or less that do not use a continuous
CO2 CEMS for the final exhaust stack,
comply with the requirements in
paragraph (c)(3)(i) of this section or
paragraphs (c)(3)(ii) and (c)(3)(iii) of this
section, as applicable.
Where:
CO2 = Annual CO2 mass emissions (metric
tons/year).
Qunit = Annual throughput of unit from
company records (barrels (bbls) per year,
bbl/yr).
CBF = Coke burn-off factor from engineering
calculations (kg coke per barrel of feed);
default for catalytic cracking units = 7.3;
default for fluid coking units = 11.
0.001 = Conversion factor (metric ton/kg).
CC = Carbon content of coke based on
measurement or engineering estimate (kg
C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to
C (kg CO2 per kg C).
sroberts on DSKD5P82C1PROD with RULES
(iii) If you have a CO boiler that uses
auxiliary fuels or combusts materials
other than catalytic cracking unit or
fluid coking unit exhaust gas, you must
determine the CO2 emissions resulting
from the combustion of these fuels or
other materials following the
requirements in subpart C of this part
(General Stationary Fuel Combustion
Sources) and report those emissions by
following the requirements of subpart C
of this part.
(4) Calculate CH4 emissions using
either unit specific measurement data, a
unit-specific emission factor based on a
source test of the unit, or Equation Y–
9 of this section.
⎛
EmF2 ⎞
CH 4 = ⎜ CO 2 ∗
⎟
EmF1 ⎠
⎝
(Eq. Y-9)
Where:
CH4 = Annual methane emissions from coke
burn-off (metric tons CH4/year).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
44
12
(Eq. Y-8)
CO2 = Emission rate of CO2 from coke burnoff calculated in paragraphs (c)(1), (c)(2),
(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 (General Stationary
Fuel Combustion Sources) (kg CO2/
MMBtu).
EmF2 = Default CH4 emission factor for
‘‘PetroleumProducts’’ from Table C–2 of
subpart C of this part (General Stationary
Fuel Combustion Sources) (kg CH4/
MMBtu).
(5) Calculate N2O emissions using
either unit specific measurement data, a
unit-specific emission factor based on a
source test of the unit, or Equation Y–
10 of this section.
⎛
EmF3 ⎞
N 2O = ⎜ CO 2 ∗
⎟
EmF1 ⎠
⎝
(Eq. Y-10)
Where:
N2O = Annual nitrous oxide emissions from
coke burn-off (mt N2O/year).
CO2 = Emission rate of CO2 from coke burnoff calculated in paragraphs (c)(1), (c)(2),
(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 (General Stationary
Fuel Combustion Sources) (kg CO2/
MMBtu).
EmF3 = Default N2O emission factor for
‘‘PetroleumProducts’’ from Table C–2 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
fuel gas must be accounted for only
PO 00000
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Fmt 4701
Sfmt 4700
once. Typically, these emissions will be
accounted for using the methods
described in subpart C of this part
(General Stationary Fuel 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 the
applicable methods described in
paragraphs (e)(1) through (e)(3) of this
section and calculate the CH4 and N2O
emissions using the methods described
in paragraphs (c)(4) and (c)(5) of this
section, respectively.
(1) If you operate and maintain a
CEMS that measures CO2 emissions
according to subpart C of this part
(General Stationary Fuel Combustion
Sources), you must calculate CO2
emissions as provided in paragraphs
(c)(1)(i) and (c)(1)(ii) of this section.
Other catalytic reforming units must
either install a CEMS that complies with
the Tier 4 Calculation Methodology in
subpart C of this part, or follow the
requirements of paragraph (e)(2) or (e)(3)
of this section.
(2) If you continuously or no less
frequently than daily monitor the O2,
CO2, and (if necessary) CO
concentrations in the exhaust stack from
the catalytic reforming unit catalyst
regenerator prior to the combustion of
other fossil fuels, you must calculate the
CO2 emissions according to the
requirements of paragraphs (c)(2)(i)
through (c)(2)(iii) of this section.
E:\FR\FM\30OCR2.SGM
30OCR2
er30oc09.096</MATH>
CO2 = Qunit × (CBF × 0.001) × CC ×
(i) If you continuously or no less
frequently than daily monitor the O2,
CO2, and (if necessary) CO
concentrations in the exhaust stack from
the catalytic cracking unit regenerator or
fluid coking unit burner prior to the
combustion of other fossil fuels, you
must calculate the CO2 emissions
according to the requirements of
paragraphs (c)(2)(i) through (c)(2)(iii) of
this section, except that daily averages
are allowed and the summation can be
performed on a daily basis.
(ii) If you do not monitor at least daily
the O2, CO2, and (if necessary) CO
concentrations in the exhaust stack from
the catalytic cracking unit regenerator or
fluid coking unit burner prior to the
combustion of other fossil fuels,
calculate the CO2 emissions from each
catalytic cracking unit and fluid coking
unit using Equation Y–8 of this section.
er30oc09.095</MATH>
%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
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
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
er30oc09.094</MATH>
56454
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
regenerator using Equation Y–11 of this
section.
Where:
CO2 = Annual CO2 emissions (metric tons/
year).
CBQ = Coke burn-off quantity per
regeneration cycle from engineering
estimates (kg coke/cycle).
n = Number of regeneration cycles in the
calendar year.
CC = Carbon content of coke based on
measurement or engineering estimate (kg
C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to
C (kg CO2 per kg C).
0.001 = Conversion factor (metric ton/kg).
(f) For on-site sulfur recovery plants,
calculate and report CO2 process
emissions from sulfur recovery plants
according to the requirements in
paragraphs (f)(1) through (f)(5) 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
(General Stationary Fuel Combustion
Sources). For the purposes of this
subpart, the sour gas stream for which
monitoring is required according to
(
sroberts on DSKD5P82C1PROD with RULES
(5) If tail gas is recycled to the front
of the sulfur recovery plant and the
recycled flow rate and carbon content is
included in the measured data under
paragraphs (f)(2) and (f)(3) of this
section, respectively, then the annual
CO2 emissions calculated in paragraph
(f)(4) of this section must be corrected
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. Y-11)
paragraphs (f)(2) through (f)(5) of this
section is not considered a fuel.
(1) If you operate and maintain a
CEMS that measures CO2 emissions
according to subpart C of this part, you
must calculate CO2 emissions under this
subpart by following the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources). You must
monitor fuel use in the Claus burner,
tail gas incinerator, or other combustion
sources 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. Calculate 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. Other sulfur recovery plants must
either install a CEMS that complies with
the Tier 4 Calculation Methodology in
subpart C, or follow the requirements of
CO2 = FSG ∗
Where:
CO2 = Annual CO2 emissions (metric tons/
year).
FSG = Volumetric flow rate of sour gas feed
(including sour water stripper gas) 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.
44
)n × CC × 12 × 0.001⎤
⎥
⎦
44
∗ MFC ∗ 0.001
MVC
(Eq. Y-12)
to avoid double counting these
emissions. You may use engineering
estimates to perform this correction or
assume that the corrected CO2 emissions
are 95 percent of the uncorrected value
calculated using Equation Y–12 of this
section.
(g) For coke calcining units, calculate
GHG emissions according to the
applicable provisions in paragraphs
(g)(1) through (g)(3) of this section.
(1) If you operate and maintain a
CEMS that measures CO2 emissions
according to subpart C of this part, you
must calculate and report CO2 emissions
under this subpart by following the Tier
4 Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources). You must
PO 00000
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Fmt 4701
Sfmt 4700
paragraphs (f)(2) through (f)(5) of this
section.
(2) 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
gas feed to the sulfur recovery plant,
you must use engineering calculations,
company records, or similar estimates of
volumetric sour gas flow.
(3) Carbon content. If you have a
continuous gas composition monitor
capable of measuring carbon content on
the sour gas feed to the sulfur recovery
plant or if you monitor gas composition
for carbon content on a routine basis,
you must use the measured carbon
content value. Alternatively, you may
develop a site-specific carbon content
factor using limited measurement data
or engineering estimates or use the
default factor of 0.20.
(4) Calculate the CO2 emissions from
each sulfur recovery plant using
Equation Y–12 of this section.
monitor fuel use in the coke calcining
unit that discharges via the final exhaust
stack from the coke calcining unit and
calculate the combustion emissions
from the fuel use according to subpart
C of this part. Calculate the process
emissions from the coke calcining unit
as the difference in the CO2 CEMS
emissions and the calculated
combustion emissions associated with
the coke calcining unit final exhaust
stack. Other coke calcining units must
either install a CEMS that complies with
the Tier 4 Calculation Methodology in
subpart C of this part, or follow the
requirements of paragraph (g)(2) of this
section.
(2) Calculate the CO2 emissions from
the coke calcining unit using Equation
Y–13 of this section.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.098</MATH>
n
⎡
CO2 = ∑ ⎢ CBQ
1 ⎣
ER30OC09.097</MATH>
(3) Calculate CO2 emissions from the
catalytic reforming unit catalyst
56455
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
44
∗ ( M in ∗ CCGC − ( M out + M dust ) ∗ CCMPC )
12
Where:
CO2 = Annual CO2 emissions from
uncontrolled asphalt blowing (metric
tons CO2/year).
QAB = Quantity of asphalt blown (million
barrels per year, MMbbl/year).
EFAB,CO2 = Emission factor for CO2 from
uncontrolled asphalt blowing from
facility-specific test data (metric tons
sroberts on DSKD5P82C1PROD with RULES
Where:
CH4 = Annual methane emissions from
controlled asphalt blowing (metric tons
CH4/year).
0.02 = Fraction of methane uncombusted in
thermal oxidizer or flare based on
assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million
barrels per year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from
uncontrolled asphalt blowing from
facility-specific test data (metric tons
CH4/MMbbl asphalt blown); default =
580.
Where:
CH4 = Annual methane emissions from
uncontrolled asphalt blowing (metric
tons CH4/year).
QAB = Quantity of asphalt blown (million
barrels per year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from
uncontrolled asphalt blowing from
facility-specific test data (metric tons
CH4/MMbbl asphalt blown); default =
580.
(2) For asphalt blowing operations
controlled by thermal oxidizer or flare,
calculate CO2 and CH4 emissions using
Equations Y–16 and Y–17 of this
section, respectively, provided these
emissions are not already included in
the flare emissions calculated in
paragraph (b) of this section or in the
stationary combustion unit emissions
required under subpart C of this part
(General Stationary Fuel Combustion
Sources).
(Eq. Y-16)
QAB = Quantity of asphalt blown (MMbbl/
year).
CEFAB = Carbon emission factor from asphalt
blowing from facility-specific test data
CH 4 = 0.02 × ( QAB × EFAB,CH 4 )
(metric tons C/MMbbl asphalt blown);
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Eq. Y-17)
(i) For delayed coking units, calculate
the CH4 emissions from the
depressurization of the coking unit
vessel (i.e., the ‘‘coke drum’’) to
atmosphere using either of the methods
provided in paragraphs (i)(1) or (i)(2),
provided no water or steam is added to
the vessel once it is vented to the
atmosphere. You must use the method
in paragraph (i)(1) of this section if you
add water or steam to the vessel after it
is vented to the atmosphere.
(1) Use the process vent method in
paragraph (j) of this section and also
calculate the CH4 emissions from the
subsequent opening of the vessel for
coke cutting operations using Equation
Y–18 of this section. If you have coke
drums or vessels of different
dimensions, use Equation Y–18 for each
set of coke drums or vessels of the same
size and sum the resultant emissions
across each set of coke drums or vessels
to calculate the CH4 emissions for all
delayed coking units.
⎛
( P + 14.7 ) × f × π × D 2 × 16 × MF × 0.001⎞
CH 4 = ⎜ N × H × CV
⎟
void
CH 4
⎜
⎟
14.7
4
MVC
⎝
⎠
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
PO 00000
Frm 00198
Fmt 4701
Sfmt 4725
(Eq. Y-15)
E:\FR\FM\30OCR2.SGM
(Eq. Y-18)
30OCR2
ER30OC09.104</MATH>
44 ⎞
⎛
CO2 = 0.98 × ⎜ QAB × CEFAB × ⎟
12 ⎠
⎝
Where:
CO2 = Annual CO2 emissions from controlled
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of
thermal oxidizer or flare.
(Eq. Y-14)
CH 4 = ( QAB × EFAB,CH 4 )
ER30OC09.103</MATH>
CO2 = ( QAB × EFAB.CO 2 )
CO2/MMbbl asphalt blown); default =
1,100.
ER30OC09.102</MATH>
(3) For all coke calcining units, use
the CO2 emissions from the coke
calcining unit calculated in paragraphs
(g)(1) or (g)(2), as applicable, and
calculate CH4 using the methods
described in paragraph (c)(4) of this
section and N2O emissions using the
methods described in paragraph (c)(5) of
this section.
(h) For asphalt blowing operations,
calculate GHG emissions according to
the requirements in paragraph (j) of this
section or according to the applicable
provisions in paragraphs (h)(1) and
(h)(2) of this section.
(1) For uncontrolled asphalt blowing
operations or asphalt blowing
operations controlled by vapor
scrubbing, calculate CO2 and CH4
emissions using Equations Y–14 and Y–
15 of this section, respectively.
ER30OC09.101</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).
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).
(Eq. Y-13)
ER30OC09.100</MATH>
CO2 =
ER30OC09.099</MATH>
56456
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Where:
CH4 = Annual methane emissions from the
delayed coking unit vessel opening
(metric ton/year).
N = Cumulative number of vessel openings
for all delayed coking unit vessels of the
same dimensions during the year.
H = Height of coking unit vessel (feet).
PCV = Gauge pressure of the coking vessel
when opened to the atmosphere prior to
coke cutting or, if the alternative method
provided in paragraph (i)(2) of this
section is used, gauge pressure of the
coking vessel when depressurization
gases are first routed to the atmosphere
(pounds per square inch gauge, psig).
14.7 = Assumed atmospheric pressure
(pounds per square inch, psi).
fvoid = Volumetric void fraction of coking
vessel prior to steaming (cf gas/cf of
vessel); default = 0.6.
N
Ex =
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
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, wet
basis); default value is 0.01.
0.001 = Conversion factor (metric ton/kg).
(2) Calculate the CH4 emissions from
the depressurization vent and
subsequent opening of the vessel for
coke cutting operations using Equation
Y–18 of this section and the pressure of
the coking vessel when the
depressurization gases are first routed to
the atmosphere. If you have coke drums
or vessels of different dimensions, use
Equation Y–18 for each set of coke
drums or vessels of the same size and
sum the resultant emissions across each
MW
⎛
⎞
x
∑ ⎜ (VR) p × ( MFx ) p × MVC × (VT ) p × 0.001⎟
⎝
⎠
56457
set of coke drums or vessels to calculate
the CH4 emissions for all delayed coking
units.
(j) For each process vent not covered
in paragraphs (a) through (i) of this
section that can be reasonably expected
to contain greater than 2 percent by
volume CO2 or greater than 0.5 percent
by volume of CH4 or greater than 0.01
percent by volume (100 parts per
million) of N2O, calculate GHG
emissions using the Equation Y–19 of
this section. You must use Equation Y–
19 of this section for catalytic reforming
unit depressurization and purge vents
when methane is used as the purge gas
or if you elected this method as an
alternative to the methods in paragraphs
(h)(1) or (h)(2) of this section.
(Eq. Y-19)
p =1
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).
(VT)p = Venting time for the event, (hours).
0.001 = Conversion factor (metric ton/kg).
(k) For uncontrolled blowdown
systems, you must either use the
methods for process vents in paragraph
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–21 of this section.
sroberts on DSKD5P82C1PROD with RULES
CH 4 = ( 0.4 × NCD + 0.2 × N PU 1 + 0.1× N PU 2 + 4.3 × N H 2 + 6 × N FGS )
Where:
CH4 = Annual methane emissions from
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.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
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, except as
provided in paragraph (m)(3) of this
section, calculate CH4 emissions using
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Fmt 4701
Sfmt 4700
(Eq. Y-21)
the applicable methods in paragraphs
(m)(1) and (m)(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 AP–42 emission
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.107</MATH>
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.
(Eq. Y-20)
ER30OC09.106</MATH>
16
⎛
⎞
CH 4 = ⎜ QRe f × EFBD ×
× 0.001⎟
MVC
⎝
⎠
(j) of this section or calculate CH4
emissions using Equation Y–20 of this
section. Blowdown systems where the
uncondensed gas stream is routed to a
flare or similar control device is
considered to be controlled and is not
required to estimate emissions under
this paragraph (k).
ER30OC09.105</MATH>
Where:
Ex = Annual emissions of each GHG from
process vent (metric ton/yr).
N = Number of venting events per year.
P = Index of venting events.
(VR)p = Average volumetric flow rate of
process gas during the event (scf per
hour).
(MFx)p = Mole fraction of GHG x in process
vent during the event (kg-mol of GHG x/
kg-mol vent gas).
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(
CH 4 = 0.1 × QRe f
)
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).
CH 4 = ( 995,000 × Qun × ΔP ) × MFCH 4 ×
sroberts on DSKD5P82C1PROD with RULES
Where:
CH4 = Annual methane emissions from
storage tanks (metric tons/year).
Qun = Quantity of unstabilized crude oil
received at the facility (MMbbl/year).
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 (kgmole 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).
MVC = Molar volume conversion factor
(849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(3) You do not need to calculate CH4
emissions from storage tanks that meet
any of the following descriptions:
(i) Units permanently attached to
conveyances such as trucks, trailers, rail
cars, barges, or ships;
(ii) Pressure vessels designed to
operate in excess of 204.9 kilopascals
and without emissions to the
atmosphere;
(iii) Bottoms receivers or sumps;
(iv) Vessels storing wastewater; or
(v) Reactor vessels associated with a
manufacturing process unit.
(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, you may assume
zero methane emissions.
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Jkt 220001
(Eq. Y-22)
16
× 0.001
MVC
§ 98.254 Monitoring and QA/QC
requirements.
(a) Fuel flow meters, gas composition
monitors, and heating value monitors
associated with stationary combustion
sources must follow the monitoring and
QA/QC requirements in § 98.34.
(b) All flow meters, gas composition
monitors, and heating value monitors
that are used to provide data for the
GHG emissions calculations in this
subpart for sources other than stationary
combustion sources shall be calibrated
according to the procedures in the
applicable methods specified in
paragraphs (c) through (e) of this
section, the procedures specified by the
manufacturer, or §§ 98.3(i). Recalibrate
each flow meter either biennially (every
two years) or at the minimum frequency
specified by the manufacturer.
Recalibrate each gas composition
monitor and heating value monitor
either annually or at the minimum
frequency specified by the
manufacturer.
(c) For flare or sour gas flow meters,
operate and maintain the flow meter
using any of the following methods, a
method published by a consensus-based
standards organization (e.g., ASTM,
API, etc.) or follow the procedures
specified by the flow meter
manufacturer. Flow meters must have a
rated accuracy of ± 5 percent or lower.
(1) ASME MFC–3M–2004
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi
(incorporated by reference, see § 98.7).
(2) ASME MFC–4M–1986 (Reaffirmed
1997) Measurement of Gas Flow by
Turbine Meters (incorporated by
reference, see § 98.7).
(3) ASME MFC–6M–1998
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters (incorporated
by reference, see § 98.7).
(4) ASME MFC–7M–1987 (Reaffirmed
1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles
(incorporated by reference, see § 98.7).
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(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–23 of this section.
(Eq. Y-23)
(5) ASME MFC–11M–2006
Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters (incorporated
by reference, see § 98.7).
(6) ASME MFC–14M–2003
Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters
(incorporated by reference, see § 98.7).
(7) ASME MFC–18M–2001
Measurement of Fluid Flow Using
Variable Area Meters (incorporated by
reference, see § 98.7).
(8) AGA Report No. 11 Measurement
of Natural Gas by Coriolis Meter (2003)
(incorporated by reference, see § 98.7).
(d) Determine flare gas composition
using any of the following methods.
(1) Method 18 at 40 CFR part 60,
appendix A–6.
(2) ASTM D1945–03 Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(3) ASTM D1946–90 (Reapproved
2006) Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference, see § 98.7).
(4) GPA 2261–00 Analysis for Natural
Gas and Similar Gaseous Mixtures by
Gas Chromatography (incorporated by
reference, see § 98.7).
(5) UOP539–97 Refinery Gas Analysis
by Gas Chromatography (incorporated
by reference, see § 98.7).
(e) Determine flare gas higher heating
value using any of the following
methods.
(1) ASTM D4809–06 Standard Test
Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb
Calorimeter (Precision Method)
(incorporated by reference, see § 98.7).
(2) ASTM D240–02 (Reapproved
2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon
Fuels by Bomb Calorimeter
(incorporated by reference, see § 98.7).
(3) ASTM D1826–94 (Reapproved
2003) Standard Test Method for
Calorific (Heating) Value of Gases in
Natural Gas Range by Continuous
Recording Calorimeter (incorporated by
reference, see § 98.7).
E:\FR\FM\30OCR2.SGM
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ER30OC09.109</MATH>
estimation methods provided in Section
7.1 of the AP–42: ‘‘Compilation of Air
Pollutant Emission Factors, Volume 1:
Stationary Point and Area Sources’’,
including TANKS Model (Version
4.09D) or similar programs, or estimate
CH4 emissions from storage tanks using
Equation Y–22 of this section.
ER30OC09.108</MATH>
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(4) ASTM D3588–98 (Reapproved
2003) Standard Practice for Calculating
Heat Value, Compressibility Factor, and
Relative Density of Gaseous Fuels
(incorporated by reference, see § 98.7).
(5) ASTM D4891–89 (Reapproved
2006) Standard Test Method for Heating
Value of Gases in Natural Gas Range by
Stoichiometric Combustion
(incorporated by reference, see § 98.7).
(f) For exhaust gas flow meters used
to comply with the requirements in
§ 98.253(c)(2)(ii), install, operate,
calibrate, and maintain exhaust gas flow
meter according to the requirements in
40 CFR 63.1572(c) or according to the
following requirements.
(1) Locate the flow meter(s) and other
necessary equipment such as
straightening vanes in a position that
provides representative flow; reduce
swirling flow or abnormal velocity
distributions due to upstream and
downstream disturbances.
(2) Use a flow rate meter with an
accuracy within ± 5 percent.
(3) Use a continuous monitoring
system capable of correcting for the
temperature, pressure, and moisture
content to output flow in dry standard
cubic feet (standard conditions as
defined in § 98.6).
(4) Install, operate, and maintain each
continuous monitoring system
according to the manufacturer’s
specifications and requirements.
(g) For exhaust gas CO2/CO/O2
composition monitors used to comply
with the requirements in § 98.253(c)(2),
install, operate, calibrate, and maintain
exhaust gas composition monitors
according to the requirements in 40 CFR
60.105a(b)(2) or 40 CFR 63.1572(a) or
according to the manufacturer’s
specifications and requirements.
(h) Determine the mass of petroleum
coke as required by Equation Y–13 of
this subpart using mass measurement
equipment meeting the requirements for
commercial weighing equipment as
described in Specifications, Tolerances,
and Other Technical Requirements For
Weighing and Measuring Devices, NIST
Handbook 44 (2009) (incorporated by
reference, see § 98.7). Calibrate the
measurement device according to the
procedures specified by the method, the
procedures specified by the
manufacturer, or § 98.3(i). Recalibrate
either biennially or at the minimum
frequency specified by the
manufacturer.
(i) Determine the carbon content of
petroleum coke as required by Equation
Y–13 of this subpart using any one of
the following methods. Calibrate the
measurement device according to
procedures specified by the method or
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17:39 Oct 29, 2009
Jkt 220001
procedures specified by the
measurement device manufacturer.
(1) ASTM D3176–89 (Reapproved
2002) Standard Practice for Ultimate
Analysis of Coal and Coke (incorporated
by reference, see § 98.7).
(2) ASTM D5291–02 (Reapproved
2007) Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Petroleum
Products and Lubricants (incorporated
by reference, see § 98.7).
(3) ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
(j) Determine the quantity of
petroleum process streams using
company records. These quantities
include the quantity of asphalt blown,
quantity of crude oil plus the quantity
of intermediate products received from
off site, and the quantity of unstabilized
crude oil received at the facility.
(k) 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.
(l) All CO2 CEMS and flow rate
monitors used for direct measurement of
GHG emissions must comply with the
QA procedures in § 98.34(c).
§ 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
substitute data value for the missing
parameter shall be used in the
calculations.
(a) For stationary combustion sources,
use the missing data procedures in
subpart C of this part.
(b) For each missing value of the heat
content, carbon content, or molecular
weight of the fuel, substitute the
arithmetic average of the quality-assured
values of that parameter immediately
preceding and immediately following
the missing data incident. If the ‘‘after’’
value is not obtained by the end of the
reporting year, you may use the
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56459
‘‘before’’ value for the missing data
substitution. 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 CO2, CO, O2, CH4, or
N2O concentrations, gas flow rate, and
percent moisture, the substitute data
values shall be the best available
estimate(s) of the parameter(s), based on
all available process data (e.g.,
processing rates, operating hours, etc.).
The owner or operator shall document
and keep records of the procedures used
for all such estimates.
(d) For hydrogen plants, use the
missing data procedures in subpart P 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 (q) of this
section.
(a) For combustion sources, follow the
data reporting requirements under
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) For hydrogen plants, follow the
data reporting requirements under
subpart P of this part (Hydrogen
Production).
(c) [Reserved]
(d) [Reserved]
(e) For flares, owners and operators
shall report:
(1) The flare ID number (if
applicable).
(2) A description of the type of flare
(steam assisted, air-assisted).
(3) A description of the flare service
(general facility flare, unit flare,
emergency only or back-up flare).
(4) The calculated CO2, CH4, and N2O
annual emissions for each flare,
expressed in metric tons of each
pollutant emitted.
(5) A description of the method used
to calculate the CO2 emissions for each
flare (e.g., reference section and
equation number).
(6) If you use Equation Y–1 of this
subpart, the annual volume of flare gas
combusted (in scf/year) and the annual
average molecular weight (in kg/kgmole) and carbon content of the flare gas
(in kg carbon per kg flare gas).
(7) If you use Equation Y–2 of this
subpart, the annual volume of flare gas
combusted (in million (MM) scf/year)
and the annual average higher heating
value of the flare gas (in MMBtu per
MMscf).
(8) If you use Equation Y–3 of this
subpart, the annual volume of flare gas
combusted (in MMscf/year) during
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normal operations, the annual average
higher heating value of the flare gas (in
MMBtu/MMscf), the number of SSM
events exceeding 500,000 scf/day, and
the volume of gas flared (in scf/event)
and the average molecular weight (in
kg/kg-mole) and carbon content of the
flare gas (in kg carbon per kg flare) for
each SSM event over 500,000 scf/day.
(9) The fraction of carbon in the flare
gas contributed by methane used in
Equation Y–4 of this subpart and the
basis for its value.
(f) For catalytic cracking units,
traditional fluid coking units, and
catalytic reforming 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
coking unit, or catalytic reforming unit).
(3) Maximum rated throughput of the
unit, in bbl/stream day.
(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).
(6) If you use a CEMS, the relevant
information required under
§ 98.36(e)(2)(vi) for the Tier 4
Calculation Methodology, the CO2
annual emissions as measured by the
CEMS (unadjusted to remove CO2
combustion emissions associated with a
CO boiler, if present) and the process
CO2 emissions as calculated according
to § 98.253(c)(1)(ii). Report the CO2
annual emissions associated with fuel
combustion under subpart C of this part
(General Stationary Fuel Combustion
Sources).
(7) If you use Equation Y–6 of this
subpart, the annual average exhaust gas
flow rate, %CO2, and %CO.
(8) If you use Equation Y–7 of this
subpart, the annual average flow rate of
inlet air and oxygen-enriched air, %O2,
%Ooxy, %CO2, and %CO.
(9) If you use Equation Y–8 of this
subpart, the coke burn-off factor, annual
throughput of unit, and the average
carbon content of coke and the basis for
the value.
(10) Indicate whether you use a
measured value, a unit-specific
emission factor, or a default emission
factor for CH4 emissions. If you use a
unit-specific emission factor for CH4,
report the units of measure for the unitspecific factor, the activity data for
calculating emissions (e.g., if the
emission factor is based on coke burnoff rate, the annual quantity of coke
burned), and the basis for the factor.
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Jkt 220001
(11) Indicate whether you use a
measured value, a unit-specific
emission factor, or a default emission
factor for N2O emissions. If you use a
unit-specific emission factor for N2O,
report the units of measure for the unitspecific factor, the activity data for
calculating emissions (e.g., if the
emission factor is based on coke burnoff rate, the annual quantity of coke
burned), and the basis for the factor.
(12) If you use Equation Y–11 of this
subpart, the number of regeneration
cycles during the reporting year, the
average coke burn-off quantity per cycle,
and the average carbon content of the
coke.
(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,
and the applicable equation input
parameters specified in paragraphs (f)(7)
through (f)(11) of this section.
(h) For sulfur recovery plants and for
emissions from sour gas sent off-site for
sulfur recovery, the owner and operator
shall report:
(1) The plant ID number (if
applicable).
(2) Maximum rated throughput of
each independent sulfur recovery plant,
in metric tons sulfur produced/stream
day.
(3) The calculated CO2 annual
emissions for each sulfur recovery plant,
expressed in metric tons. The calculated
annual CO2 emissions from sour gas
sent off-site for sulfur recovery,
expressed in metric tons.
(4) If you use Equation Y–12 of this
subpart, the annual volumetric flow to
the sulfur recovery plant (in scf/year)
and the annual average mole fraction of
carbon in the sour gas (in kg-mole C/kgmole gas).
(5) If you recycle tail gas to the front
of the sulfur recovery plant, indicate
whether the recycled flow rate and
carbon content are included in the
measured data under § 98.253(f)(2) and
(3). Indicate whether a correction for
CO2 emissions in the tail gas was used
in Equation Y–12. If so, then report the
value of the correction, the annual
volume of recycled tail gas (in scf/year)
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and the annual average mole fraction of
carbon in the tail gas (in kg-mole C/kgmole gas). Indicate whether you used
the default (95%) or a unit specific
correction, and if used, report the
approach used.
(6) If you use a CEMS, the relevant
information required under
§ 98.36(e)(2)(vi) for the Tier 4
Calculation Methodology, the CO2
annual emissions as measured by the
CEMS and the annual process CO2
emissions calculated according to
§ 98.253(f)(1). Report the CO2 annual
emissions associated with fuel
combustion subpart C of this part
(General Stationary Fuel Combustion
Sources).
(i) For coke calcining units, the owner
and operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the
unit, in metric tons coke calcined/
stream day.
(3) The calculated CO2, CH4, and N2O
annual emissions for each unit,
expressed in metric tons of each
pollutant emitted.
(4) A description of the method used
to calculate the CO2 emissions for each
unit (e.g., reference section and equation
number).
(5) If you use Equation Y–13 of this
subpart, annual mass and carbon
content of green coke fed to the unit, the
annual mass and carbon content of
marketable coke produced, and the
annual mass of coke dust collected in
dust collection systems.
(6) If you use a CEMS, the relevant
information required under
§ 98.36(e)(2)(vi) for the Tier 4
Calculation Methodology, the CO2
annual emissions as measured by the
CEMS and the annual process CO2
emissions calculated according to
§ 98.253(g)(1). Report the CO2 annual
emissions associated with fuel
combustion under subpart C of this part
(General Stationary Fuel Combustion
Sources).
(7) Indicate whether you use a
measured value, a unit-specific
emission factor or a default for CH4
emissions. If you use a unit-specific
emission factor for CH4, the unitspecific emission factor for CH4, the
units of measure for the unit-specific
factor, the activity data for calculating
emissions (e.g., if the emission factor is
based on coke burn-off rate, the annual
quantity of coke burned), and the basis
for the factor.
(8) If you use a site-specific emission
factor in Equation Y–10 of this subpart,
the site-specific emission factor and the
basis of the factor.
(j) For asphalt blowing operations, the
owner or operator shall report:
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(1) The unit ID number (if applicable).
(2) The quantity of asphalt blown (in
Million bbl) at the facility in the
reporting year.
(3) The type of control device used to
reduce methane (and other organic)
emissions from the unit.
(4) The calculated annual CO2 and
CH4 emissions for each unit, expressed
in metric tons of each pollutant emitted.
(5) If you use Equation Y–14 of this
subpart, the CO2 emission factor used
and the basis for the value.
(6) If you use Equation Y–15 of this
subpart, the CH4 emission factor used
and the basis for the value.
(7) If you use Equation Y–16 of this
subpart, the carbon emission factor used
and the basis for the value.
(8) If you use Equation Y–17 of this
subpart, the CH4 emission factor used
and the basis for the value.
(k) For delayed coking units, the
owner or operator shall report:
(1) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for all delayed coking
units at the facility.
(2) A description of the method used
to calculate the CH4 emissions for each
unit (e.g., reference section and equation
number).
(3) The total number of delayed
coking units at the facility, the total
number of delayed coking drums at the
facility, and for each coke drum or
vessel: the dimensions, the typical
gauge pressure of the coking drum when
first vented to the atmosphere, typical
void fraction, the typical drum outage
(i.e. the unfilled distance from the top
of the drum, in feet), and annual
number of coke-cutting cycles.
(4) For each set of coking drums that
are the same dimensions: The number of
coking drums in the set, the height and
diameter of the coke drums (in feet), the
cumulative number of vessel openings
for all delayed coking drums in the set,
the typical venting pressure (in psig),
void fraction (in cf gas/cf of vessel), and
the mole fraction of methane in coking
gas (in kg-mole CF4/kg-mole gas, wet
basis).
(5) The basis for the volumetric void
fraction of the coke vessel prior to
steaming and the basis for the mole
fraction of methane in the coking gas.
(l) 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 vent,
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expressed in metric tons of each
pollutant emitted.
(5) The annual volumetric flow
discharged to the atmosphere (in scf),
mole fraction of each GHG above the
concentration threshold, and for
intermittent vents, the number of
venting events and the cumulative
venting time.
(m) For uncontrolled blowdown
systems, the owner or operator shall
report:
(1) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for uncontrolled
blowdown systems.
(2) 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.
(3) The methane emission factor used
for uncontrolled blowdown systems and
the basis for the value.
(n) For equipment leaks, the owner or
operator shall report:
(1) The cumulative CH4 emissions (in
metric tons of each pollutant emitted)
for all equipment leak sources.
(2) The method used to calculate the
reported equipment leak emissions.
(3) The number of each type of
emission source listed in Equation Y–21
of this subpart at the facility.
(o) For storage tanks, the owner or
operator shall report:
(1) 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.
(2) The method used to calculate the
reported storage tank emissions for
storage tanks other than those
processing unstabilized crude (AP–42,
TANKS 4.09D, Equation Y–22 of this
subpart, other).
(3) The total quantity (in MMbbl) of
crude oil plus the quantity of
intermediate products received from offsite that are processed at the facility in
the reporting year.
(4) The cumulative CH4 emissions (in
metric tons of each pollutant emitted)
for storage tanks used to process
unstabilized crude oil.
(5) The method used to calculate the
reported storage tank emissions for
storage tanks processing unstabilized
crude oil.
(6) The quantity of unstabilized crude
oil received during the calendar year (in
MMbbl), the average pressure
differential (in psi), and the mole
fraction of CH4 in vent gas from the
unstabilized crude oil storage tank, and
the basis for the mole fraction.
(7) The tank-specific methane
composition data and the gas generation
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56461
rate data, if you did not use Equation Y–
23.
(p) For loading operations, the owner
or operator shall report:
(1) The cumulative annual CH4
emissions (in metric tons of each
pollutant emitted) for loading
operations.
(2) The quantity and types of
materials loaded by vessel type (barge,
tanker, marine vessel, etc.) 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.
(3) 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
(submerged loading, vapor balancing,
etc.).
(q) Name of each method listed in
§ 98.254 or a description of
manufacturer’s recommended method
used to determine a measured
parameter.
§ 98.257
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.
§ 98.258
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart Z—Phosphoric Acid
Production
§ 98.260
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 the production unit or
units identified by an individual
identification number in an operating
permit and/or any process unit or group
of process units at a facility reacting
phosphate rock from a common supply
source with acid.
§ 98.261
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
(a)(2).
§ 98.262
GHGs to report.
(a) You must report CO2 process
emissions from each wet-process
phosphoric acid process line.
(b) You must report under subpart C
of this part (General Stationary Fuel
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Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
wet-process phosphoric acid process
b
z
Em = ∑ ∑ ( ICn,i ∗ Pn,i ) ∗
i =1 n =1
Where:
Em = Annual CO2 mass emissions from a wetprocess phosphoric acid process line m
(metric tons).
ICn,i = Inorganic carbon content of a grab
sample batch of phosphate rock by origin
i obtained during month n, from the
carbon analysis results (percent by
weight, expressed as a decimal fraction).
Pn,i = Mass of phosphate rock by origin i
consumed in month n by wet-process
phosphoric acid process line m (tons).
z = Number of months during which the
process line m operates.
b = Number of different types of phosphate
rock in month, by origin. If the grab
sample is a composite sample of rock
from more than one origin, b=1.
2000/2205 = Conversion factor to convert
tons to metric tons.
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) You must determine the total
emissions from the facility using
Equation Z–2 of this section:
p
CO2 = ∑ Em
(Eq. Z-2)
m =1
sroberts on DSKD5P82C1PROD with RULES
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.
(c) If GHG emissions from a wetprocess phosphoric acid process line are
vented through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraph
(b) of this section shall not be used to
calculate process emissions. The owner
or operator shall report under this
subpart the combined stack emissions
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
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2000 44
∗
2205 12
(Eq. Z-1)
associated requirements for Tier 4 in
subpart C of this part.
§ 98.264 Monitoring and QA/QC
requirements.
(a) You must obtain a monthly grab
sample of phosphate rock directly from
the rock being fed to the process line.
Conduct the representative bulk
sampling using the applicable standard
method in the Phosphate Mining States
Methods Used and Adopted by the
Association of Fertilizer and Phosphate
Chemists AFPC Manual 10th Edition
2009—Version 1.9 (incorporated by
reference, see § 98.7). If phosphate rock
is obtained from more than one origin
in a month, you must obtain a sample
from each origin of rock or obtain a
composite representative sample.
(b) You must determine the inorganic
carbon content of each monthly grab
sample of phosphate rock (consumed in
the production of phosphoric acid)
using the applicable standard method in
the Phosphate Mining States Methods
Used and Adopted by the Association of
Fertilizer and Phosphate Chemists
AFPC Manual 10th Edition 2009—
Version 1.9 (incorporated by reference,
see § 98.7).
(c) You must determine the mass of
phosphate rock consumed each month
(by origin) in each wet-process
phosphoric acid process line. You can
use existing plant procedures that are
used for accounting purposes (such as
sales records) or you can use data from
existing monitoring equipment that is
used to measure total mass flow of
phosphorous-bearing feed under 40 CFR
part 60 or part 63.
§ 98.265 Procedures for estimating
missing data.
A complete record of all measured
parameters used in the GHG emissions
calculations in § 98.263(b) 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
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(b) Calculate and report under this
subpart the process CO2 emissions using
the procedures in paragraphs (b)(1) and
(b)(2) of this section.
(1) Calculate and report the process
CO2 emissions from each wet-process
phosphoric acid process line using
Equation Z–1 of this section:
the calculations as specified in
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) For each missing value of the
inorganic carbon content of phosphate
rock (by origin), you must use the
appropriate default factor provided in
Table Z–1 of this subpart. Alternatively,
the you must determine substitute data
value by calculating the arithmetic
average of the quality-assured values of
inorganic carbon contents of phosphate
rock of origin i (see Equation Z–1 of this
subpart) from samples immediately
preceding and immediately following
the missing data incident. If no qualityassured data on inorganic carbon
contents of phosphate rock of origin i
are available prior to the missing data
incident, the substitute data value shall
be the first quality-assured value for
inorganic carbon contents for phosphate
rock of origin i obtained after the
missing data period.
(b) For each missing value of monthly
mass consumption of phosphate rock
(by origin), you must use the best
available estimate based on all available
process data or data used for accounting
purposes.
§ 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 (b) of this
section.
(a) Annual phosphoric acid
production by origin (as listed in Table
Z–1 to this subpart) of the phosphate
rock (tons).
(b) Annual phosphoric acid permitted
production capacity (tons).
(c) Annual arithmetic average percent
inorganic carbon in phosphate rock
from monthly records.
(d) Annual phosphate rock
consumption from monthly
measurement records by origin, (as
E:\FR\FM\30OCR2.SGM
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ER30OC09.111</MATH>
§ 98.263
line using the procedures in either
paragraph (a) or (b) of this section.
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining a CEMS
according to the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
ER30OC09.110</MATH>
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit following the
requirements of subpart C of this part.
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
sroberts on DSKD5P82C1PROD with 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 (c) of
this section for each wet-process
phosphoric acid production facility.
(a) Monthly mass of phosphate rock
consumed by origin (as listed in Table
Z–1 of this subpart) (tons).
(b) Records of all phosphate rock
purchases and/or deliveries (if vertically
integrated with a mine).
(c) Documentation of the procedures
used to ensure the accuracy of monthly
phosphate rock consumption by origin,
(as listed in Table Z–1 of this subpart).
§ 98.272
CO2 , CH 4 , or N 2O from biomass = (0.907.18) ∗ Solids ∗ HHV ∗ EF
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GHGs to report.
You must report the emissions listed
in paragraphs (a) through (f) of this
§ 98.268 Definitions.
section:
All terms used in this subpart have
(a) CO2, biogenic CO2, CH4, and N2O
the same meaning given in the Clean Air
emissions from each kraft or soda
Act and subpart A of this part.
chemical recovery furnace.
(b) CO2, biogenic CO2, CH4, and N2O
TABLE Z–1 TO SUBPART Z OF PART
98—DEFAULT CHEMICAL COMPOSI- emissions from each sulfite chemical
recovery combustion unit.
TION OF PHOSPHATE ROCK BY ORI(c) CO2, biogenic CO2, CH4, and N2O
GIN
emissions from each stand-alone
Total carbon semichemical chemical recovery
Origin
(percent by combustion unit.
weight)
(d) CO2, biogenic CO2, CH4, and N2O
emissions from each kraft or soda pulp
Central Florida ..........................
1.6
mill lime kiln.
North Florida .............................
1.76
(e) CO2 emissions from addition of
North Carolina (Calcined) .........
0.76
Idaho (Calcined) .......................
0.60 makeup chemicals (CaCO3, Na2CO3) in
Morocco ....................................
1.56 the chemical recovery areas of chemical
pulp mills.
(f) CO2, CH4, and N2O combustion
Subpart AA—Pulp and Paper
emissions from each stationary
Manufacturing
combustion unit. You must calculate
§ 98.270 Definition of source category.
and report these emissions under
(a) The pulp and paper manufacturing subpart C of this part (General
source category consists of facilities that Stationary Fuel Combustion Sources) by
produce market pulp (i.e., stand-alone
following the requirements of subpart C.
pulp facilities), manufacture pulp and
paper (i.e., integrated facilities), produce § 98.273 Calculating GHG emissions.
(a) For each chemical recovery
paper products from purchased pulp,
furnace located at a kraft or soda
produce secondary fiber from recycled
facility, you must determine CO2,
paper, convert paper into paperboard
biogenic CO2, CH4, and N2O emissions
products (e.g., containers), or operate
using the procedures in paragraphs
coating and laminating processes.
(b) The emission units for which GHG (a)(1) through (a)(3) of this section. CH4
emissions must be reported are listed in and N2O emissions must be calculated
paragraphs (b)(1) through (b)(5) of this
as the sum of emissions from
section:
combustion of fossil fuels and
(1) Chemical recovery furnaces at
combustion of biomass in spent liquor
kraft and soda mills (including recovery solids.
furnaces that burn spent pulping liquor
(1) Calculate fossil fuel-based CO2
produced by both the kraft and
emissions from direct measurement of
semichemical process).
fossil fuels consumed and default
(2) Chemical recovery combustion
emissions factors according to the Tier
units at sulfite facilities.
1 methodology for stationary
(3) Chemical recovery combustion
combustion sources in § 98.33(a)(1).
units at stand-alone semichemical
(2) Calculate fossil fuel-based CH4 and
facilities.
N2O emissions from direct measurement
(4) Pulp mill lime kilns at kraft and
of fossil fuels consumed, default HHV,
soda facilities.
and default emissions factors and
(5) Systems for adding makeup
convert to metric tons of CO2 equivalent
chemicals (CaCO3, Na2CO3) in the
according to the methodology for
chemical recovery areas of chemical
stationary combustion sources in
pulp mills.
§ 98.33(c).
§ 98.271 Reporting threshold.
(3) Calculate biogenic CO2 emissions
You must report GHG emissions
and emissions of CH4 and N2O from
under this subpart if your facility
biomass using measured quantities of
contains a pulp and paper
spent liquor solids fired, site-specific
manufacturing process and the facility
HHV, and default or site-specific
meets the requirements of either
emissions factors, according to Equation
§ 98.2(a)(1) or (a)(2).
AA–1 of this section:
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(Eq. AA-1)
30OCR2
ER30OC09.112</MATH>
listed in Table Z–1 to this subpart)
(tons).
(e) If you use a CEMS to measure CO2
emissions, then you must report the
information in paragraphs (e)(1) and
(e)(2) of this section.
(1) The identification number of each
wet-process phosphoric acid process
line.
(2) The annual CO2 emissions from
each wet-process phosphoric acid
process line (metric tons) and the
relevant information required under 40
CFR 98.36 (e)(2)(vi) for the Tier 4
Calculation Methodology.
(f) If you do not use a CEMS to
measure emissions, then you must
report the information in paragraphs
(f)(1) through (f)(8) of this section.
(1) Identification number of each wetprocess phosphoric acid process line.
(2) Annual CO2 emissions from each
wet-process phosphoric acid process
line (metric tons) as calculated by
Equation Z–1 of this subpart.
(3) Annual phosphoric acid permitted
production capacity (tons) for each wetprocess phosphoric acid process line
(metric tons).
(4) Method used to estimate any
missing values of inorganic carbon
content of phosphate rock for each wetprocess phosphoric acid process line.
(5) Monthly inorganic carbon content
of phosphate rock for each wet-process
phosphoric acid process line (percent by
weight, expressed as a decimal fraction).
(6) Monthly mass of phosphate rock
consumed by origin, (as listed in Table
Z–1 of this subpart) in production for
each wet-process phosphoric acid
process line (tons).
(7) Number of wet-process phosphoric
acid process lines.
(8) Number of times missing data
procedures were used to estimate
phosphate rock consumption (months)
and inorganic carbon contents of the
phosphate rock (months).
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(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
paragraphs (b)(1) through (b)(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).
Biogenic CO2 =
Where:
Biogenic CO2 = Annual CO2 mass emissions
for spent liquor solids combustion
(metric tons per year).
Solids = Mass of the spent liquor solids
combusted (short tons per year)
determined according to § 98.274(b).
CC = Annual carbon content of the spent
liquor solids, determined according to
§ 98.274(b) (percent by weight, expressed
as a decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to
carbon.
0.90718 = Conversion from short tons to
metric tons.
(4) Calculate CH4 and N2O emissions
from biomass using Equation AA–1 of
this section 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 by
multiplying each annual CH4 and N2O
44
∗ Solids ∗ CC ∗ (0.90718)
12
(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
methodology for stationary combustion
sources in § 98.33(c).
(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:
(Eq. AA-2)
emissions total by the appropriate global
warming potential (GWP) factor from
Table A–1 of subpart A of this part.
(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 (c)(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 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); use the default
HHV listed in Table C–1 of subpart C
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
included in the biogenic CO2 estimates
calculated for the chemical recovery
furnace 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 ⎤
⎡
CO2 = ⎢ M CaCO ∗
+ M Na CO
(
( 2 3 ) 105.99 ⎥ ∗1000 kg/metric ton
3 ) 100
⎣
⎦
sroberts on DSKD5P82C1PROD with RULES
Where:
CO2 = CO2 mass emissions from makeup
chemicals (kilograms/yr).
M (CaCO3) = Make-up quantity of CaCO3
used for the reporting year (metric tons
per year).
M (NaCO3) = Make-up quantity of Na2CO3
used for the reporting year (metric tons
per year).
44 = Molecular weight of CO2.
100 = 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
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must be available for inspection upon
request.
(b) Fuel properties needed to perform
the calculations in Equations AA–1 and
AA–2 of this subpart must be
determined according to paragraphs
(b)(1) through (b)(3) of this section.
(1) High heat values of black liquor
must be determined no less than
annually using T684 om–06 Gross
Heating Value of Black Liquor, TAPPI
(incorporated by reference, see § 98.7). If
measurements are performed more
frequently than annually, then the high
heat value used in Equation AA–1 of
this subpart must be based on the
average of the representative
measurements made during the year.
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(Eq. AA-3)
(2) The annual mass of spent liquor
solids must be determined using either
of the methods specified in paragraph
(b)(2)(i) or (b)(2)(ii) of this section.
(i) Measure the mass of spent liquor
solids annually (or more frequently)
using T–650 om–05 Solids Content of
Black Liquor, TAPPI (incorporated by
reference in § 98.7). If measurements are
performed more frequently than
annually, then the mass of spent liquor
solids used in Equation AA–1 of this
subpart must be based on the average of
the representative measurements made
during the year.
(ii) Determine the annual mass of
spent liquor solids based on records of
measurements made with an online
measurement system that determines
E:\FR\FM\30OCR2.SGM
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ER30OC09.114</MATH>
Where:
CO2, CH4, or N2O, from Biomass = Biogenic
CO2 emissions or emissions of CH4 or
N2O from spent liquor solids combustion
(metric tons per year).
Solids = Mass of spent liquor solids
combusted (short tons per year)
determined according to § 98.274(b).
HHV = Annual high heat value of the spent
liquor solids (mmBtu per kilogram)
determined according to § 98.274(b).
EF = Default emission factor for CO2, CH4, or
N2O, from Table AA–1 of this subpart (kg
CO2, CH4, or N2O per mmBtu).
0.90718 = Conversion factor from short tons
to metric tons.
ER30OC09.113</MATH>
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
the mass of spent liquor solids fired in
a chemical recovery furnace or chemical
recovery combustion unit.
(3) Carbon analyses for spent pulping
liquor must be determined no less than
annually using ASTM D5373–08
Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and
Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see § 98.7). If
measurements using ASTM D5373–08
are performed more frequently than
annually, then the spent pulping liquor
carbon content used in Equation AA–2
of this subpart must be based on the
average of the representative
measurements made during the year.
(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, spent liquor solids, 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 pulping 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.
§ 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 annual
measurements are determined to be
invalid.
(b) For missing measurements of the
mass of spent liquor solids or spent
pulping liquor flow rates, use the lesser
value of either the maximum mass or
fuel flow rate for the combustion unit,
or the maximum mass or flow rate that
the fuel 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 (k) of this section
as applicable:
(a) Annual emissions of CO2, biogenic
CO2, CH4, biogenic CH4 N2O, and
biogenic N2O (metric tons per year).
(b) Annual quantities fossil fuels by
type used in chemical recovery furnaces
and chemical recovery combustion units
in short tons for solid fuels, gallons for
liquid fuels and scf for gaseous fuels.
(c) Annual mass of the spent liquor
solids combusted (short tons per year),
and basis for determining the annual
mass of the spent liquor solids
combusted (whether based on T650 om05 Solids Content of Black Liquor,
TAPPI (incorporated by reference, see
§ 98.7) or an online measurement
system).
(d) The high heat value (HHV) of the
spent liquor solids used in Equation
AA–1 of this subpart (mmBtu per
kilogram).
(e) The default emission factor for
CO2, CH4, or N2O, used in Equation AA–
1 of this subpart (kg CO2, CH4, or N2O
per mmBtu).
(f) The carbon content (CC) of the
spent liquor solids, used in Equation
AA–2 of this subpart (percent by weight,
expressed as a decimal fraction, e.g.,
95% = 0.95).
56465
(g) Annual quantities of fossil fuels by
type used in pulp mill lime kilns in
short tons for solid fuels, gallons for
liquid fuels and scf for gaseous fuels.
(h) Make-up quantity of CaCO3 used
for the reporting year (metric tons per
year) used in Equation AA–3 of this
subpart.
(i) Make-up quantity of Na2CO3 used
for the reporting year (metric tons per
year) used in Equation AA–3 of this
subpart.
(j) Annual steam purchases (pounds
of steam per year).
(k) Annual production of pulp and/or
paper products produced (metric tons).
§ 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 (f)
of this section.
(a) GHG emission estimates (including
separate estimates of biogenic CO2) for
each emissions source listed under
§ 98.270(b).
(b) Annual analyses of spent pulping
liquor HHV for each chemical recovery
furnace at kraft and soda facilities.
(c) Annual analyses of spent pulping
liquor carbon content for each chemical
recovery combustion unit at a sulfite or
semichemical pulp facility.
(d) Annual quantity of spent liquor
solids combusted in each chemical
recovery furnace and chemical recovery
combustion unit, and the basis for
detemining the annual quantity of the
spent liquor solids combusted (whether
based on T650 om–05 Solids Content of
Black Liquor, TAPPI (incorporated by
reference, see § 98.7) or an online
measurement system). If an online
measurement system is used, you must
retain records of the calculations used to
determine the annual quantity of spent
liquor solids combusted from the
continuous measurements.
(e) Annual steam purchases.
(f) Annual 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.
sroberts on DSKD5P82C1PROD with RULES
TABLE AA–1 TO SUBPART AA OF PART 98—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 ................................................................................................................................................................
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30OCR2
94.4
93.7
95.5
93.7
CH4
0.030
N2O
0.005
56466
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
TABLE AA–1 TO SUBPART AA OF PART 98—KRAFT PULPING LIQUOR EMISSIONS FACTORS FOR BIOMASS-BASED CO2,
CH4, AND N2O—Continued
Biomass-based emissions factors
(kg/mmBtu HHV)
Wood furnish
CO2a
Straw ....................................................................................................................................................................
a Includes
CH4
N2O
95.1
emissions from both the recovery furnace and pulp mill lime kiln.
TABLE AA–2 TO SUBPART AA OF PART 98—KRAFT LIME KILN AND CALCINER EMISSIONS FACTORS FOR FOSSIL FUELBASED CO2, CH4, AND N2O
Fossil fuel-based emissions factors (kg/mmBtu HHV)
Kraft lime kilns
Residual Oil ......................................................................
Distillate Oil ......................................................................
Natural Gas ......................................................................
Biogas ..............................................................................
Definition of the source category.
Silicon carbide production includes
any process that produces silicon
carbide for abrasive purposes.
§ 98.281
Reporting threshold.
§ 98.283
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
(a)(2).
§ 98.282
76.7
73.5
56.0
0
You must report:
sroberts on DSKD5P82C1PROD with RULES
12
n =1
2000
2205
Jkt 220001
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Fmt 4701
Sfmt 4700
0.0027
N2O
0.0003
0.0004
0.0001
0.0001
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining CEMS
according to the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart the process CO2 emissions using
the procedures in paragraphs (b)(1) and
(b)(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
measured monthly and used to calculate
a monthly CO2 emisssions factor:
44/12 = Ratio of molecular weights, CO2 to
carbon.
(2) Use Equation BB–2 of this section
to calculate annual CO2 process
emissions from all silicone carbide
production:
(Eq. BB-2)
CO2 = Annual CO2 emissions from silicon
carbide production facility (metric tons
CO2).
17:39 Oct 29, 2009
76.7
73.5
56.0
CH4
(Eq. BB-1)
CCFn = Carbon content factor for petroleum
coke consumed in month n from the
supplier or as measured by the
applicable method incorporated by
reference in § 98.7 according to
§ 98.284(c) (percent by weight expressed
as a decimal fraction).
CO2 = ∑ ⎡Tn ∗ EFCO 2, n ⎤ ∗
⎣
⎦
VerDate Nov<24>2008
0
Calculating GHG emissions.
⎛ 44 ⎞
EFCO 2,n = 0.65 ∗ CCFn ∗ ⎜ ⎟
⎝ 12 ⎠
Where:
EFCO2,n = CO2 emissions factor in month n
(metric tons CO2/metric ton of petroleum
coke consumed).
0.65 = Adjustment factor for the amount of
carbon in silicon carbide product
(assuming 35 percent of carbon input is
in the carbide product).
CO2
0.0027
You must calculate and report the
annual process CO2 emissions from each
silicon carbide process unit or
production furnace using the
procedures in either paragraph (a) or (b)
of this section. You must determine CH4
process emissions in accordance with
the procedures specified in paragraph
(d) of this section.
GHGs to report.
Where:
N2O
(a) CO2 and CH4 process emissions
from all silicon carbide process units or
furnaces combined.
(b) CO2, CH4, and N2O emissions from
each stationary combustion unit. You
must report these emissions under
subpart C of this part (General
Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
Subpart BB—Silicon Carbide
Production
§ 98.280
CH4
Tn = Petroleum coke consumption in month
n (tons).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.116</MATH>
CO2
Kraft calciners
ER30OC09.115</MATH>
Fuel
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(c) If GHG emissions from a silicon
carbide production furnace or process
unit are vented through the same stack
as any combustion unit or process
equipment that reports CO2 emissions
using a CEMS that complies with the
Tier 4 Calculation Methodology in
subpart C of this part (General
Stationary Fuel Combustion Sources),
then the calculation methodology in
paragraph (b) of this section shall not be
used to calculate process emissions. The
owner or operator shall report under
this subpart the combined stack
12
CH 4 = ∑ [Tn ∗ 10.2] ∗
n =1
Where:
CH4 = Annual CH4 emissions from silicon
carbide production facility (metric tons
CH4).
Tn = Petroleum coke consumption in month
n (tons).
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.
n = Number of month.
sroberts on DSKD5P82C1PROD with RULES
§ 98.284 Monitoring and QA/QC
requirements.
(a) You must measure your
consumption of petroleum coke using
plant instruments used for accounting
purposes including direct measurement
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 petroleum coke
consumption measurements.
(c) For CO2 process emissions, you
must determine the monthly carbon
content of the petroleum coke using
reports from the supplier. Alternatively,
facilities can measure monthly carbon
contents of the petroleum coke using
ASTM D3176–89 (Reapproved 2002)
Standard Practice for Ultimate Analysis
of Coal and Coke (incorporated by
reference, see § 98.7) and ASTM D5373–
08 Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Laboratory
Samples of Coal (incorporated by
reference, see § 98.7).
(d) For quality assurance and quality
control of the supplier data, you must
conduct an annual measurement of the
carbon content of the petroleum coke
using ASTM D3176–89 and ASTM
D5373–08 Standard Test Methods for
Instrumental Determination of Carbon,
Hydrogen, and Nitrogen in Laboratory
Samples of Coal (incorporated by
reference, see § 98.7).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
2000
∗ 0.001
2205
(Eq. BB-3)
§ 98.285 Procedures for estimating
missing data.
For the petroleum coke input
procedure in § 98.283(b), a complete
record of all measured parameters used
in the GHG emissions calculations is
required (e.g., 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 as specified in the
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) For each missing value of the
monthly carbon content of petroleum
coke, the substitute data value shall be
the arithmetic average of the qualityassured values of carbon contents
immediately preceding and immediately
following the missing data incident. If
no quality-assured data on carbon
contents are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value for carbon contents
obtained after the missing data period.
(b) For each missing value of the
monthly petroleum coke consumption,
the substitute data value shall be the
best available estimate of the petroleum
coke consumption based on all available
process data or information used for
accounting purposes (such as purchase
records).
§ 98.286
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as applicable for each silicon carbide
production facility.
(a) If a CEMS is used to measure
process CO2 emissions, you must report
under this subpart the relevant
information required for the Tier 4
Calculation Methodology in § 98.36 and
the information listed in this paragraph
(a):
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Sfmt 4700
emissions according to the Tier 4
Calculation Methodology in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part.
(d) You must calculate annual process
CH4 emissions from all silicon carbide
production combined using Equation
BB–3 of this section:
(1) Annual consumption of petroleum
coke (tons).
(2) Annual production of silicon
carbide (tons).
(3) Annual production capacity of
silicon carbide (tons).
(b) If a CEMS is not used to measure
process CO2 emissions, you must report
the information listed in this paragraph
(b) for all furnaces combined:
(1) Monthly consumption of
petroleum coke (tons).
(2) Annual production of silicon
carbide (tons).
(3) Annual production capacity of
silicon carbide (tons).
(4) Carbon content factor of petroleum
coke from the supplier or as measured
by the applicable method in § 98.284(c)
for each month (percent by weight
expressed as a decimal fraction).
(5) Whether carbon content of the
petroleum coke is based on reports from
the supplier or through self
measurement using applicable ASTM
standard method.
(6) CO2 emissions factor calculated for
each month (metric tons CO2/metric ton
of petroleum coke consumed).
(7) Sampling analysis results for
carbon content of consumed petroleum
coke as determined for QA/QC of
supplier data under § 98.284(d) (percent
by weight expressed as a decimal
fraction).
(8) Number of times in the reporting
year that missing data procedures were
followed to measure the carbon contents
of petroleum coke (number of months)
and petroleum coke consumption
(number of months).
§ 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) and (b) of
this section for each silicon carbide
production facility.
(a) If a CEMS is used to measure CO2
emissions, you must retain under this
subpart the records required for the Tier
4 Calculation Methodology in § 98.37
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.117</MATH>
EFCO2,n = CO2 emissions factor from month
n (calculated in Equation BB–1 of this
section).
2000/2205 = Conversion factor to convert
tons to metric tons.
n = Number of month.
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
§ 98.291
and the information listed in this
paragraph (a):
(1) Records of all petroleum coke
purchases.
(2) Annual operating hours.
(b) If a CEMS is not used to measure
emissions, you must retain records for
the information listed in this paragraph
(b):
(1) Records of all analyses and
calculations conducted for reported data
listed in § 98.286(b).
(2) Records of all petroleum coke
purchases.
(3) Annual operating hours.
§ 98.288
§ 98.292
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) A soda ash manufacturing facility
is any facility with a manufacturing line
that produces soda ash by one of the
methods in paragraphs (a)(1) through (3)
of this section:
(1) Calcining trona.
(2) Calcining sodium sesquicarbonate.
(3) Using a liquid alkaline feedstock
process that directly produces CO2.
(b) In the context of the soda ash
manufacturing sector, ‘‘calcining’’
means the thermal/chemical conversion
of the bicarbonate fraction of the
feedstock to sodium carbonate.
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
(a)(2).
GHGs to report.
You must report:
(a) CO2 process emissions from each
soda ash manufacturing line combined.
(b) CO2 combustion emissions from
each soda ash manufacturing line.
(c) CH4 and N2O combustion
emissions from each soda ash
manufacturing line. You must calculate
and report these emissions under
subpart C of this part (General
Stationary Fuel Combustion Sources) by
following the requirements of subpart C.
(d) CO2, CH4, and N2O emissions from
each stationary combustion unit other
than soda ash manufacturing lines. You
must calculate and report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
§ 98.293
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions from each
soda ash manufacturing line using the
procedures specified in paragraph (a) or
(b) of this section.
(a) For each soda ash manufacturing
line that meets the conditions specified
in § 98.33(b)(4)(ii) or (b)(4)(iii), you must
calculate and report under this subpart
the combined process and combustion
CO2 emissions by operating and
maintaining a CEMS to measure CO2
emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(b) For each soda ash manufacturing
line that is not subject to the
requirements in paragraph (a) of this
section, calculate and report the process
CO2 emissions from the soda ash
manufacturing line by using the
procedure in either paragraphs (b)(1),
(b)(2), or (b)(3) of this section; and the
combustion CO2 emissions using the
procedure in paragraph (b)(4) of this
section.
(1) Calculate and report under this
subpart the combined process and
combustion CO2 emissions by operating
and maintaining a CEMS to measure
CO2 emissions according to the Tier 4
Calculation Methodology specified in
§ 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part (General Stationary Fuel
Combustion Sources).
(2) Use either Equation CC–1 or
Equation CC–2 of this section to
calculate annual CO2 process emissions
from each manufacturing line that
calcines trona to produce soda ash:
12
2000 0.097
E k = ∑ ⎡( ICT )n ∗ ( Tt )n ⎤ ∗
⎣
⎦ 2205 ∗ 1
(Eq. CC-1)
12
2000 0.138
E k = ∑ ⎡( ICsa )n ∗ ( Tsa )n ⎤ ∗
⎣
⎦ 2205 ∗ 1
(Eq. CC-2)
n =1
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17:39 Oct 29, 2009
Jkt 220001
(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 soda ash produced.
(3) Site-specific emission factor
method. Use Equations CC–3, CC–4, and
CC–5 of this section to determine
annual CO2 process emissions from
manufacturing lines that use the liquid
alkaline feedstock process to produce
soda ash. You must conduct an annual
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performance test and measure CO2
emissions and flow rates at all process
vents from the mine water stripper/
evaporator for each manufacturing line
and calculate CO2 emissions as
described in paragraphs (b)(3)(i) through
(b)(3)(iv) of this section.
(i) During the performance test, you
must measure the process vent flow
from each process vent during the test
and calculate the average rate for the
test period in metric tons per hour.
(ii) Using the test data, you must
calculate the hourly CO2 emission rate
using Equation CC–3 of this section:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.119</MATH>
Where:
Ek = Annual CO2 process emissions from
each manufacturing line, k (metric tons).
(ICT)n = Inorganic carbon content (percent by
weight, expressed as a decimal fraction)
in trona input, from the carbon analysis
results for month n. This represents the
ratio of trona to trona ore.
(ICsa)n = Inorganic carbon content (percent by
weight, expressed as a decimal fraction)
in soda ash output, from the carbon
analysis results for month n. This
represents the purity of the soda ash
produced.
(Tt)n = Mass of trona input in month n (tons).
ER30OC09.118</MATH>
sroberts on DSKD5P82C1PROD with RULES
n =1
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
ERCO 2 = ⎡( Cco 2 ∗10000 ) ∗ 2.59 x10−9 ∗ 44 ⎤ ∗ (Q ∗ 60) ∗ 4.53 x10−4
⎣
⎦
4.53 × 10 ¥4 = Conversion factor (metric tons/
pound)
(iii) Using the test data, you must
calculate a CO2 emission factor for the
process using Equation CC–4 of this
section:
(V ∗ 4.53 x10 )
−4
t
Where:
Ek = EFCO 2 ∗ (Va ∗ 0.453) ∗ H
Where:
Ek = Annual CO2 process emissions for each
manufacturing line, k (metric tons).
EFCO2 = CO2 emission factor (metric tons
CO2/metric ton of process vent flow from
mine water stripper/evaporator).
Va = Annual process vent flow rate from
mine water stripper/evaporator
(thousand pounds/hour).
H = Annual operating hours for the each
manufacturing line.
0.453 = Conversion factor (metric tons/
thousand pounds).
(4) Calculate and report under subpart
C of this part (General Stationary Fuel
Combustion Sources) the combustion
CO2, CH4, and N2O emissions in the
soda ash manufacturing line according
to the applicable requirements in
subpart C.
sroberts on DSKD5P82C1PROD with RULES
§ 98.294 Monitoring and QA/QC
requirements.
Section 98.293 provides three
different procedures for emission
calculations. The appropriate
paragraphs (a) through (c) of this section
should be used for the procedure
chosen.
(a) If you determine your emissions
using § 98.293(b)(2) (Equation CC–1 of
this subpart) you must:
(1) Determine the monthly inorganic
carbon content of the trona from a
weekly composite analysis for each soda
ash manufacturing line, using a
modified version of ASTM E359–00
(Reapproved 2005)e1, Standard Test
Methods for Analysis of Soda Ash
(Sodium Carbonate) (incorporated by
reference, see § 98.7). ASTM E359–
00(Reapproved 2005) e1 is designed to
measure the total alkalinity in soda ash
not in trona. The modified method of
ASTM E359–00 adjusts the regular
ASTM method to expresse the results in
terms of trona. Although ASTM E359–
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. CC-4)
(Eq. CC-5)
00 (Reapproved 2005) e1 uses manual
titration, suitable autotitrators may also
be used for this determination.
(2) Measure the mass of trona input
produced by each soda ash
manufacturing line on a monthly basis
using belt scales or methods used for
accounting purposes.
(3) Document the procedures used to
ensure the accuracy of the monthly
measurements of trona consumed.
(b) If you calculate CO2 process
emissions based on soda ash production
(§ 98.293(b)(2) Equation CC–2 of this
subpart), you must:
(1) Determine the inorganic carbon
content of the soda ash (i.e., soda ash
purity) using ASTM E359–00
(Reapproved 2005) e1 Standard Test
Methods for Analysis of Soda Ash
(Sodium Carbonate) (incorporated by
reference, see § 98.7). Although ASTM
E359–00 (Reapproved 2005) e1 uses
manual titration, suitable autotitrators
may also be used for this determination.
(2) Measure the mass of soda ash
produced by each soda ash
manufacturing line on a monthly basis
using belt scales, by weighing the soda
ash at the truck or rail loadout points of
your facility, or methods used for
accounting purposes.
(3) Document the procedures used to
ensure the accuracy of the monthly
measurements of soda ash produced.
(c) If you calculate CO2 emissions
using the site-specific emission factor
method in § 98.293(b)(3), you must:
(1) Conduct an annual performance
test that is based on representative
performance (i.e., performance based on
normal operating conditions) of the
affected process.
(2) Sample the stack gas and conduct
three emissions test runs of 1 hour each.
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(iv) You must calculate annual CO2
process emissions from each
manufacturing line using Equation CC–
5 of this section:
(3) Conduct the stack test using EPA
Method 3A at 40 CFR part 60, appendix
A–2 to measure the CO2 concentration,
Method 2, 2A, 2C, 2D, or 2F at 40 CFR
part 60, appendix A–1 or Method 26 at
40 CFR part 60, appendix A–2 to
determine the stack gas volumetric flow
rate. 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)(3)(i) through
(c)(3)(iii) of this section.
(i) Analysis of samples, determination
of emissions, and raw data.
(ii) All information and data used to
derive the emissions factor(s).
(iii) You must determine the average
process vent flow rate from the mine
water stripper/evaporater during each
test and document how it was
determined.
(4) You must also determine the
annual vent flow rate from the mine
water stripper/evaporater from monthly
information using the same plant
instruments or procedures used for
accounting purposes (i.e., volumetric
flow meter).
§ 98.295 Procedures for estimating
missing data.
For the emission calculation
methodologies in § 98.293(b)(2) and
(b)(3), a complete record of all measured
parameters used in the GHG emissions
calculations is required (e.g., inorganic
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 as specified in the
paragraphs (a) through (d) of this
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.122</MATH>
ERCO 2
EFCO2 = CO2 emission factor (metric tons
CO2/metric ton of process vent flow from
mine water stripper/evaporator).
ERCO2 = CO2 mass emission rate (metric tons/
hour).
Vt = Process vent flow rate from mine water
stripper/evaporator during annual
performance test (pounds/hour).
4.53 × 10¥4 = Conversion factor (metric tons/
pound)
ER30OC09.121</MATH>
EFCO 2 =
(Eq. CC-3)
C
ER30OC09.120</MATH>
Where:
ERCO2 = CO2 mass emission rate (metric tons/
hour).
CCO2 = Hourly CO2 concentration (percent
CO2) as determined by § 98.294(c).
10000 = Parts per million per percent
2.59 x 10¥9 = Conversion factor (poundsmole/dscf/ppm).
44 = Pounds per pound-mole of carbon
dioxide.
Q = Stack gas volumetric flow rate per
minute (dscfm).
60 = Minutes per hour
56469
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
section. You must document and keep
records of the procedures used for all
such missing value estimates.
(a) For each missing value of the
weekly composite of inorganic carbon
content of either soda ash or trona, the
substitute data value shall be the
arithmetic average of the quality-assured
values of inorganic carbon contents
from the week immediately preceding
and the week immediately following the
missing data incident. If no qualityassured data on inorganic carbon
contents are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value for carbon contents
obtained after the missing data period.
(b) For each missing value of either
the monthly soda ash production or the
trona consumption, the substitute data
value shall be the best available
estimate(s) of the parameter(s), based on
all available process data or data used
for accounting purposes.
(c) For each missing value collected
during the performance test (hourly CO2
concentration, stack gas volumetric flow
rate, or average process vent flow from
mine water stripper/evaporator during
performance test), you must repeat the
annual performance test following the
calculation and monitoring and QA/QC
requirements under §§ 98.293(b)(3) and
98.294(c).
(d) For each missing value of the
monthly process vent flow rate from
mine water stripper/evaporator, the
subsititute data value shall be the best
available estimate(s) of the parameter(s),
based on all available process data or
the lesser of the maximum capacity of
the system or the maximum rate the
meter can measure.
sroberts on DSKD5P82C1PROD with RULES
§ 98.296
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as appropriate for each soda ash
manufacturing facility.
(a) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required under § 98.36 and the
following information in this paragraph
(a):
(1) Annual consumption of trona or
liquid alkaline feedstock for each
manufacturing line (metric tons).
(2) Annual production of soda ash for
each manufacturing line (tons).
(3) Annual production capacity of
soda ash for each manufacturing line
(tons).
(4) Identification number of each
manufacturing line.
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17:39 Oct 29, 2009
Jkt 220001
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
information listed in this paragraph (b):
(1) Identification number of each
manufacturing line.
(2) Annual process CO2 emissions
from each soda ash manufacturing line
(metric tons).
(3) Annual production of soda ash
(tons).
(4) Annual production capacity of
soda ash for each manufacturing line
(tons).
(5) Monthly consumption of trona or
liquid alkaline feedstock for each
manufacturing line (tons).
(6) Monthly production of soda ash
for each manufacturing line (metric
tons).
(7) Inorganic carbon content factor of
trona or soda ash (depending on use of
Equations CC–1 or CC–2 of this subpart)
as measured by the applicable method
in § 98.294(b) or (c) for each month
(percent by weight expressed as a
decimal fraction).
(8) Whether CO2 emissions for each
manufacturing line were calculated
using a trona input method as described
in Equation CC–1 of this subpart, a soda
ash output method as described in
Equation CC–2 of this subpart, or a sitespecific emission factor method as
described in Equations CC–3 through
CC–5 of this subpart.
(9) Number of manufacturing lines
located used to produce soda ash.
(10) If you produce soda ash using the
liquid alkaline feedstock process and
use the site-specific emission factor
method (§ 98.293(b)(3)) to estimate
emissions then you must report the
following relevant information:
(i) Stack gas volumetric flow rate per
minute (dscfm)
(ii) Hourly CO2 concentration (percent
CO2)
(iii) CO2 emission factor (metric tons
CO2/metric tons of process vent flow
from mine water stripper/evaporator).
(iv) CO2 mass emission rate (metric
tons/hour).
(v) Average process vent flow from
mine water stripper/evaporater during
performance test (pounds/hour).
(vi) Annual process vent flow rate
from mine stripper/evaporator
(thousand pounds/hour).
(vii) Annual operating hours for each
manufacturing line used to produce
soda ash using liquid alkaline feedstock
(hours).
(11) Number of times missing data
procedures were used and for which
parameter as specified in this paragraph
(b)(11):
(i) Trona or soda ash (number of
months).
(ii) Inorganic carbon contents of trona
or soda ash (weeks).
PO 00000
Frm 00212
Fmt 4701
Sfmt 4700
(iii) Process vent flow rate from mine
water stripper/evaporator (number of
months).
(iv) Stack gas volumetric flow rate
during performance test (number of
times).
(v) Hourly CO2 concentration (number
of times).
(vi) Average vent process vent flow
rate from mine stripper/evaporator
during performance test (number of
times).
§ 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) and (b) of
this section for each soda ash
manufacturing line.
(a) If a CEMS is used to measure CO2
emissions, then you must retain under
this subpart the records required for the
Tier 4 Calculation Methodology
specified in subpart C of this part and
the information listed in this paragraph
(a):
(1) Monthly production of soda ash
(tons)
(2) Monthly consumption of trona or
liquid alkaline feedstock (tons)
(3) Annual operating hours (hours).
(b) If a CEMS is not used to measure
emissions, then you must retain records
for the information listed in this
paragraph (b):
(1) Records of all analyses and
calculations conducted for determining
all reported data as listed in § 98.296(b).
(2) If using Equation CC–1 or CC–2 of
this subpart, weekly inorganic carbon
content factor of trona or soda ash,
depending on method chosen, as
measured by the applicable method in
§ 98.294(b) (percent by weight expressed
as a decimal fraction).
(3) Annual operating hours for each
manufacturing line used to produce
soda ash (hours).
(4) You must document the
procedures used to ensure the accuracy
of the monthly trona consumption or
soda ash production measurements
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.
(5) If you produce soda ash using the
liquid alkaline feedstock process and
use the site-specific emission factor
method to estimate emissions
(§ 98.293(b)(3)) then you must also
retain the following relevant
information:
(i) Records of performance test results.
(ii) You must document the
procedures used to ensure the accuracy
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All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
Subpart DD—[Reserved]
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
contains a titanium dioxide production
process and the facility meets the
requirements of either § 98.2(a)(1) or
(a)(2).
§ 98.313
12
Ep = ∑
n =1
sroberts on DSKD5P82C1PROD with RULES
Where:
Ep = Annual CO2 mass emissions from
chloride process line p (metric tons).
Cp,n = Calcined petroleum coke consumption
for process line p in month n (tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion of tons to metric
tons.
CCFn = Carbon content factor for petroleum
coke consumed in month n from the
supplier or as measured by the
applicable method incorporated by
reference in § 98.7 according to
§ 98.314(c) (percent by weight expressed
as a decimal fraction).
n = Number of month.
(3) If facility generates carboncontaining waste, you must calculate
the total annual quantity of carboncontaining waste produced from all
process lines using Equation EE–3 of
this section and its carbon contents
according to § 98.314(e) and (f):
TWC =
m 12
∑ ∑WC p,n
(Eq. EE-3)
p =1 n =1
Where:
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions for each
chloride process line using the
procedures in either paragraph (a) or (b)
of this section.
(a) Calculate and report under this
subpart the process CO2 emissions by
operating and maintaining a CEMS
according to the Tier 4 Calculation
Methodology specified in § 98.33(a)(4)
and all associated requirements for Tier
4 in subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart the annual process CO2
emissions for each chloride process line
by determining the mass of calcined
petroleum coke consumed in each line
as specified in paragraphs (b)(1) through
(b)(3) of this section. Use Equation EE–
1 of this section to calulate annual
44
2000
∗ C p,n ∗
∗ CCFn
12
2205
(c) If GHG emissions from a chloride
process line are vented through the
same stack as any combustion unit or
process equipment that reports CO2
emissions using a CEMS that complies
with the Tier 4 Calculation
Methodology in subpart C of this part
(General Stationary Fuel Combustion
Sources), then the calculation
methodology in paragraph (b) of this
section shall not be used to calculate
process CO2 emissions. The owner or
operator shall report under this subpart
the combined stack emissions according
to the Tier 4 Calculation Methodology
in § 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of
this part.
Frm 00213
Fmt 4701
Sfmt 4700
CO2 =
m
∑ Ep
(Eq. EE-1)
p =1
Where:
CO2 = Annual CO2 emissions from titanium
dioxide production facility (metric tons/
year).
Ep = Annual CO2 emissions from chloride
process line p (metric tons), determined
using Equation EE–2 of this section.
p = Process line.
m = Number of separate chloride process
lines located at the facility.
(2) You must calculate the annual CO2
process emissions from each process
lines at the facility using Equation EE–
2 of this section:
(Eq. EE-2)
TWC = Annual production of carboncontaining waste from titanium dioxide
production facility (tons).
WCp,n = Production of carbon-containing
waste in month n from chloride process
line p (tons).
p = Process line.
m = Total number of process lines.
n = Number of month.
PO 00000
combined process CO2 emissions from
all process lines and use Equation EE–
2 of this section to calculate annual
process CO2 emissions for each process
line. If your facility generates carboncontaining waste, use Equation EE–3 of
this section to estimate the annual
quantity of carbon-containing waste
generated and its carbon contents
according to § 98.314(e) and (f):
(1) You must calculate the annual CO2
process emissions from all process lines
at the facility using Equation EE–1 of
this section:
§ 98.314 Monitoring and QA/QC
requirements.
(a) You must measure your
consumption of calcined petroleum
coke using plant instruments used for
accounting purposes including direct
measurement 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 measurements.
(c) You must determine the carbon
content of the calcined petroleum coke
each month based on reports from the
supplier. Alternatively, facilities can
measure monthly carbon contents of the
petroleum coke using ASTM D3176–89
(Reapproved 2002) Standard Practice for
Ultimate Analysis of Coal and Coke
(incorporated by reference, see § 98.7)
and ASTM D5373–08 Standard Test
Methods for Instrumental Determination
of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal
(incorporated by reference, see § 98.7).
E:\FR\FM\30OCR2.SGM
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ER30OC09.125</MATH>
Definitions.
GHGs to report.
(a) You must report CO2 process
emissions from each chloride process
line as required in this subpart.
(b) You must report CO2, CH4, and
N2O emissions from each stationary
combustion unit under subpart C of this
part (General Stationary Fuel
Combustion Sources) by following the
requirements of subpart C.
ER30OC09.124</MATH>
§ 98.298
§ 98.312
ER30OC09.123</MATH>
of the annual average vent flow
measurements including, but not
limited to, calibration of flow rate
meters 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.
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(d) For quality assurance and quality
control of the supplier data, you must
conduct an annual measurement of the
carbon content from a representative
sample of the petroleum coke consumed
using ASTM D3176–89 and ASTM
D5373–08.
(e) You must determine the quantity
of carbon-containing waste generated
from the each titanium production line
dioxide using plant instruments used
for accounting purposes including
direct measurement weighing the
carbon-containing waste not used
during the process (by belt scales or a
similar device) or through the use of
sales records.
(f) You must determine the carbon
contents of the carbon-containing waste
from each titanium production line on
an annual basis by collecting and
analyzing a representative sample of the
material using ASTM D3176–89 and
ASTM D5373–08.
sroberts on DSKD5P82C1PROD with RULES
§ 98.315 Procedures for estimating
missing data.
For the petroleum coke input
procedure in § 98.313(b), a complete
record of all measured parameters used
in the GHG emissions calculations is
required (e.g., carbon content values,
etc.). Therefore, whenever the
monitoring and quality assurance
procedures in § 98.315 cannot be
followed, a substitute data value for the
missing parameter shall be used in the
calculations as specified in the
paragraphs (a) through (c) of this
section. You must document and keep
records of the procedures used for all
such estimates.
(a) For each missing value of the
monthly carbon content of calcined
petroleum coke the substitute data value
shall be the arithmetic average of the
quality-assured values of carbon
contents for the month immediately
preceding and the month immediately
following the missing data incident. If
no quality-assured data on carbon
contents are available prior to the
missing data incident, the substitute
data value shall be the first qualityassured value for carbon contents
obtained after the missing data period.
(b) For each missing value of the
monthly calcined petroleum coke
consumption and/or carbon-containing
waste, the substitute data value shall be
the best available estimate of the
monthly petroleum coke consumption
based on all available process data or
information used for accounting
purposes (such as purchase records).
(c) For each missing value of the
carbon content of carbon-containing
waste, you must conduct a new analysis
following the procedures in § 98.314(f).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
§ 98.316
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as applicable for each titanium dioxide
production line.
(a) If a CEMS is used to measure CO2
emissions, then you must report the
relevant information required under
§ 98.36(e)(2)(vi) for the Tier 4
Calculation Methodology and the
following information in this paragraph
(a).
(1) Identification number of each
process line.
(2) Annual consumption of calcined
petroleum coke (tons).
(3) Annual production of titanium
dioxide (tons).
(4) Annual production capacity of
titanium dioxide (tons).
(5) Annual production of carboncontaining waste (tons), if applicable.
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
information listed in this paragraph (b):
(1) Identification number of each
process line.
(2) Annual CO2 emissions from each
chloride process line (metric tons/year).
(3) Annual consumption of calcined
petroleum coke for each process line
(tons).
(4) Annual production of titanium
dioxide for each process line (tons).
(5) Annual production capacity of
titanium dioxide for each process line
(tons).
(6) Calcined petroleum coke
consumption for each process line for
each month (tons).
(7) Annual production of carboncontaining waste for each process line
(tons), if applicable.
(8) Monthly production of titanium
dioxide for each process line (tons).
(9) Monthly carbon content factor of
petroleum coke from the supplier
(percent by weight expressed as a
decimal fraction).
(10) Whether monthly carbon content
of the petroleum coke is based on
reports from the supplier or through self
measurement using applicable ASTM
standard methods.
(11) Carbon content for carboncontaining waste (percent by weight
expressed as a decimal fraction).
(12) If carbon content of petroleum
coke is based on self measurement, the
ASTM standard methods used.
(13) Sampling analysis results of
carbon content of petroleum coke as
determined for QA/QC of supplier data
under § 98.314(d) (percent by weight
expressed as a decimal fraction).
(14) Number of separate chloride
process lines located at the facility.
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Fmt 4701
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(15) The number of times in the
reporting year that missing data
procedures were followed to measure
the carbon contents of petroleum coke
(number of months); petroleum coke
consumption (number of months);
carbon-containing waste generated
(number of months); and carbon
contents of the carbon-containing waste
(number of times during year).
§ 98.317
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 for each titanium dioxide
production facility.
(a) If a CEMS is used to measure CO2
emissions, then you must retain under
this subpart required for the Tier 4
Calculation Methodology in § 98.37 and
the information listed in this paragraph
(a):
(1) Records of all calcined petroleum
coke purchases.
(2) Annual operating hours for each
titanium dioxide process line.
(b) If a CEMS is not used to measure
CO2 emissions, then you must retain
records for the information listed in this
paraghraph:
(1) Records of all calcined petroleum
coke purchases (tons).
(2) Records of all analyses and
calculations conducted for all reported
data as listed in § 98.316(b).
(3) Sampling analysis results for
carbon content of consumed calcined
petroleum coke (percent by weight
expressed as a decimal fraction).
(4) Sampling analysis results for the
carbon content of carbon containing
waste (percent by weight expressed as a
decimal fraction), if applicable.
(5) Monthly production of carboncontaining waste (tons).
(6) You must document the
procedures used to ensure the accuracy
of the monthly petroleum coke
consumption and quantity of carboncontaining waste measurement
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.
(7) Annual operating hours for each
titanium dioxide process line (hours).
§ 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.
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§ 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.
You must report:
(a) CO2 process emissions from each
Waelz kiln and electrothermic furnace
used for zinc production.
(b) CO2, CH4, and N2O combustion
emissions from each Waelz kiln. You
must calculate and report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
sroberts on DSKD5P82C1PROD with RULES
E CO2k =
Calculating GHG emissions.
You must calculate and report the
annual process CO2 emissions using the
procedures specified in either paragraph
(a) or (b) of this section.
(a) Calculate and report under this
subpart the process or combined process
and combustion CO2 emissions by
operating and maintaining a CEMS
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part (General
Stationary Fuel Combustion Sources).
(b) Calculate and report under this
subpart the process CO2 emissions by
44 2000
∗
∗ ⎡( Zinc )k ∗ ( CZinc )k + ( Flux) k ∗ (CFlux ) k + ( Electrode) k ∗ ( CElectrode )k + (Carbon) k ∗ ( Ccarbon )k ⎤
⎦
12 2205 ⎣
Where:
ECO2k = Annual CO2 process emissions from
individual Waelz kiln or electrothermic
furnace ‘‘k’’ (metric tons).
44/12 = Ratio of molecular weights, CO2 to
carbon.
2000/2205 = Conversion factor to convert
tons to metric tons.
(Zinc)k = Annual mass of zinc bearing
material charged to kiln or furnace ’’k’’
(tons).
(CZinc)k = Carbon content of the zinc bearing
material, from the annual carbon
analysis for kiln or furnace ‘‘k’’ (percent
by weight, expressed as a decimal
fraction).
(Flux)k = Annual mass of flux materials (e.g.,
limestone, dolomite) charged to kiln or
furnace ‘‘k’’ (tons).
(CFlux)k = Carbon content of the flux materials
charged to kiln or furnace ‘‘k’’, from the
annual carbon analysis (percent by
weight, expressed as a decimal fraction).
(Electrode)k = Annual mass of carbon
electrode consumed in kiln or furnace
‘‘k’’ (tons).
(CElectrode)k = Carbon content of the carbon
electrode consumed in kiln or furnace
‘‘k’’, from the annual carbon analysis
(percent by weight, expressed as a
decimal fraction).
(Carbon)k = Annual mass of carbonaceous
materials (e.g., coal, coke) charged to the
kiln or furnace ‘‘k’’(tons).
(CCarbon)k Carbon content of the carbonaceous
materials charged to kiln or furnace, ‘‘k’’,
from the annual carbon analysis (percent
by weight, expressed as a decimal
fraction).
VerDate Nov<24>2008
§ 98.333
following paragraphs (b)(1) and (b)(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 year and calculate annual CO2
process emissions from each affected
unit at your facility using Equation GG–
1 of this section. 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. If you document that a
specific material contributes less than 1
percent of the total carbon into the
process, you do not have to include the
material in your calculation using
Equation R–1 of § 98.183.
17:39 Oct 29, 2009
Jkt 220001
(2) You must determine the CO2
emissions from all of the Waelz kilns or
electrothermic furnaces at your facility
using Equation GG–2 of this section.
n
CO 2 = ∑ E CO 2k
(Eq. GG-2)
k =1
Where:
CO2 = Annual combined CO2 emissions from
all Waelz kilns or electrothermic
furnaces (tons).
ECO2k = Annual CO2 emissions from each
Waelz kiln or electrothermic furnace k
calculated using Equation GG–1 of this
section (tons).
n = Total number of Waelz kilns or
electrothermic furnaces at facility used
for the zinc production.
(c) If GHG emissions from a Waelz
kiln or electrothermic furnace are
vented through the same stack as any
combustion unit or process equipment
that reports CO2 emissions using a
CEMS that complies with the Tier 4
Calculation Methodology in subpart C of
this part (General Stationary Fuel
Combustion Sources), then the
calculation methodology in paragraph
(b) of this section shall not be used to
calculate process emissions. The owner
or operator shall report under this
subpart the combined stack emissions
according to the Tier 4 Calculation
Methodology in § 98.33(a)(4) and all
associated requirements for Tier 4 in
subpart C of this part.
PO 00000
Frm 00215
Fmt 4701
Sfmt 4700
(Eq. GG-1)
§ 98.334 Monitoring and QA/QC
requirements.
If you determine CO2 emissions using
the carbon input procedure in
§ 98.333(b)(1) and (b)(2), you must meet
the requirements specified in
paragraphs (a) and (b) of this section.
(a) Determine the mass of each solid
carbon-containing input material
consumed using facility instruments,
procedures, or records used for
accounting purposes including direct
measurement weighing or through the
use of purchase records same plant
instruments or procedures that are used
for accounting purposes (such as weigh
hoppers, belt weigh feeders, weighed
purchased quantities in shipments or
containers, combination of bulk density
and volume measurements, etc.). Record
the total mass for the materials
consumed each calendar month and
sum the monthly mass to determine the
annual mass for each input material.
(b) For each input material identified
in paragraph (a) of this section, you
must determine the average carbon
content of the material consumed or
used in the calendar year using the
methods specified in either paragraph
(b)(1) or (b)(2) of this section.
(1) Information provided by your
material supplier.
(2) Collecting and analyzing at least
three representative samples of the
material using the appropriate testing
method. For each carbon-containing
E:\FR\FM\30OCR2.SGM
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ER30OC09.127</MATH>
Subpart GG—Zinc Production
Sources) by following the requirements
of subpart C.
(c) CO2, CH4, and N2O emissions from
each stationary combustion unit other
than Waelz kilns. You must report these
emissions under subpart C of this part
(General Stationary Fuel Combustion
Sources) by following the requirements
of subpart C.
ER30OC09.126</MATH>
Subpart FF—[Reserved]
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
input material identified for which the
carbon content is not provided by your
material supplier, the carbon content of
the material must be analyzed at least
annually using the appropriate standard
methods (and their QA/QC procedures),
which are identified in paragraphs
(b)(2)(i) through (b)(2)(iii) of this
section, as applicable. If you document
that a specific process input or output
contributes less than one percent of the
total mass of carbon into or out of the
process, you do not have to determine
the monthly mass or annual carbon
content of that input or output.
(i) Using ASTM E1941–04 Standard
Test Method for Determination of
Carbon in Refractory and Reactive
Metals and Their Alloys (incorporated
by reference, see § 98.7), analyze zinc
bearing materials.
(ii) Using ASTM D5373–08 Standard
Test Methods for Instrumental
Determination of Carbon, Hydrogen, and
Nitrogen in Laboratory Samples of Coal
(incorporated by reference, see § 98.7),
analyze carbonaceous reducing agents
and carbon electrodes.
(iii) Using ASTM C25–06 Standard
Test Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated
Lime (incorporated by reference, see
§ 98.7), analyze flux materials such as
limestone or dolomite.
sroberts on DSKD5P82C1PROD with RULES
§ 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 as specified in
paragraphs (a) and (b) of this section.
You must document and keep records of
the procedures used for all such
estimates.
(a) For missing records of the carbon
content of inputs for facilities that
estimate emissions using the carbon
input procedure in § 98.333(b); 100
percent data availability is required.
You must repeat the test for average
carbon contents of inputs according to
the procedures in § 98.335(b) if data are
missing.
(b) For missing records of the annual
mass of carbon-containing inputs using
the carbon input procedure in
§ 98.333(b), the substitute data value
must be based on the best available
estimate of the mass of the input
material from all available process data
or information used for accounting
purposes, such as purchase records.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
§ 98.336
Data reporting requirements.
In addition to the information
required by § 98.3(c), each annual report
must contain the information specified
in paragraphs (a) or (b) of this section,
as applicable, for each Waelz kiln or
electrothermic furnace.
(a) If a CEMS is used to measure CO2
emissions, then you must report under
this subpart the relevant information
required for the Tier 4 Calculation
Methodology in § 98.37 and the
information listed in this paragraph (a):
(1) Annual zinc product production
capacity (tons).
(2) Annual production quantity for
each zinc product (tons).
(3) Annual facility production
quantity for each zinc product (tons).
(4) Number of Waelz kilns at each
facility used for zinc production.
(5) Number of electrothermic furnaces
at each facility used for zinc production.
(b) If a CEMS is not used to measure
CO2 emissions, then you must report the
information listed in this paragraph (b):
(1) Kiln identification number and
annual process CO2 emissions from each
individual Waelz kiln or electrothermic
furnace (metric tons).
(2) Annual zinc product production
capacity (tons).
(3) Annual production quantity for
each zinc product (tons).
(4) Number of Waelz kilns at each
facility used for zinc production.
(5) Number of electrothermic furnaces
at each facility used for zinc production.
(6) Annual mass of each carboncontaining input material charged to
each kiln or furnace (including zinc
bearing material, flux materials (e.g.,
limestone, dolomite), carbon electrode,
and other carbonaceous materials (e.g.,
coal, coke)) (tons).
(7) Carbon content of each carboncontaining input material charged to
each kiln or furnace (including zinc
bearing material, flux materials, and
other carbonaceous materials) from the
annual carbon analysis for each kiln or
furnace (percent by weight, expressed as
a decimal fraction).
(8) Whether carbon content of each
carbon-containing input material
charged to each kiln or furnace is based
on reports from the supplier or through
self measurement using applicable
ASTM standard method.
(9) If carbon content of each carboncontaining input material charged to
each kiln or furnace is based on self
measurement, the ASTM Standard Test
Method used.
(10) Carbon content of the carbon
electrode used in each furnace from the
annual carbon analysis (percent by
weight, expressed as a decimal fraction).
(11) Whether carbon content of the
carbon electrode used in each furnace is
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based on reports from the supplier or
through self measurement using
applicable ASTM standard method.
(12) If carbon content of carbon
electrode used in each furnace is based
on self measurement, the ASTM
standard method used.
(13) If you use the missing data
procedures in § 98.335(b), you must
report how the monthly mass of carboncontaining materials with missing data
was determined and the number of
months the missing data procedures
were used.
§ 98.337
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 (b)
of this section for each zinc production
facility.
(a) If a CEMS is used to measure
emissions, then you must retain under
this subpart the records required for the
Tier 4 Calculation Methodology in
§ 98.37 and the information listed in
this paragraph (a):
(1) Monthly facility production
quantity for each zinc product (tons).
(2) Annual operating hours for all
Waelz kilns and electrothermic furnaces
used in zinc production.
(b) If a CEMS is not used to measure
emissions, you must also retain the
records specified in paragraphs (b)(1)
through (b)(7) of this section.
(1) Records of all analyses and
calculations conducted for data reported
as listed in § 98.336(b).
(2) Annual operating hours for Waelz
kilns and electrothermic furnaces used
in zinc production.
(3) Monthly production quantity for
each zinc product (tons).
(4) Monthly mass of zinc bearing
materials, flux materials (e.g., limestone,
dolomite), and carbonaceous materials
(e.g., coal, coke) charged to the kiln or
furnace (tons).
(5) Sampling and analysis records for
carbon content of zinc bearing materials,
flux materials (e.g., limestone,
dolomite), carbonaceous materials (e.g.,
coal, coke), charged to the kiln or
furnace (percent by weight, expressed as
a decimal fraction).
(6) Monthly mass of carbon electrode
consumed in for each electrothermic
furnace (tons).
(7) Sampling and analysis records for
carbon content of electrode materials.
(8) 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,
including documentation of any
materials excluded from Equation GG–
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.340
Definition of the source category.
(a) This source category applies to
municipal solid waste (MSW) landfills
that accepted waste on or after January
1, 1980.
(b) This source category does not
include hazardous waste landfills,
construction and demolition landfills,
or industrial landfills.
(c) This source category consists of
the following sources at municipal solid
waste (MSW) landfills: Landfills,
landfill gas collection systems, and
landfill gas destruction devices
(including flares).
§ 98.341
Reporting threshold.
You must report GHG emissions
under this subpart if your facility
contains a MSW landfill and the facility
meets the requirements of § 98.2(a)(1).
⎡ 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);
default is 1.
DOC = Degradable organic carbon from Table
HH–1 of this subpart or measurement
data, if available [fraction (metric tons C/
metric ton waste)].
DOCF = Fraction of DOC dissimilated
(fraction); default is 0.5.
F = Fraction by volume of CH4 in landfill gas
from measurement data, if available
(fraction); default is 0.5.
)}
(
(2) For years when material-specific
waste quantity data are available, 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 of this subpart. 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. You may use the bulk waste
parameters for a portion of your waste
materials when using the materialspecific modeling approach for mixed
waste streams that cannot be 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
sroberts on DSKD5P82C1PROD with RULES
Where:
Wx = Quantity of waste placed in the landfill
in year × (metric tons, wet basis).
POPx = Population of served by the landfill
in year × from city population, census
data, or other estimates (capita).
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17:39 Oct 29, 2009
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% SWDS x
100%
Frm 00217
Fmt 4701
Sfmt 4700
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 (a)(3) of this section.
(1) Calculate annual modeled CH4
generation using Equation HH–1 of this
section.
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, Wx shall be estimated
using one of the applicable methods in
paragraphs (a)(3)(i) through (a)(3)(iii) of
this section. You must determine which
method is most applicable to the
conditions and disposal history of your
facility and use that method to estimate
waste disposal quantities.
(i) Assume all prior year waste
disposal quantities are the same as the
waste quantity in the first reporting
year.
(ii) Use the estimated population
served by the landfill in each year, the
values for national average per capita
waste generation, and fraction of
generated waste disposed of in solid
waste disposal sites found in Table HH–
2 of this subpart, and calculate the
waste quantity landfilled using Equation
HH–2 of this section.
(Eq. HH-2)
WGR = Average per capita waste generation
rate for year x from Table HH–2 of this
subpart (metric tons per capita per year,
wet basis; tons/cap/yr).
%SWDS = Percent of waste generated
subsequently managed in solid waste
PO 00000
§ 98.343
(Eq. HH-1)
)
k = Rate constant from Table HH–1 of this
subpart or measurement data, if available
(yr¥1).
Wx = POPx × WGRx ×
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 under subpart C
of this part (General Stationary Fuel
Combustion Sources) the emissions of
CO2, CH4, and N2O from each stationary
combustion unit following the
requirements of subpart C.
disposal sites (i.e., landfills) for year ×
from Table HH–2 of this subpart.
(iii) Use a constant average waste
disposal quantity calculated using
Equation HH–3 of this section for each
year the landfill was in operation (i.e.,
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.129</MATH>
§ 98.338
§ 98.342
Subpart HH—Municipal Solid Waste
Landfills
ER30OC09.128</MATH>
1 of this subpart that contribute less
than 1 percent of the total carbon inputs
to the process. 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.
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
year for which waste disposal data is
unavailable, inclusive).
Where:
WAR = Annual average waste acceptance rate
(metric tons per year).
LFC = Landfill capacity or, for operating
landfills, capacity of the landfill
currently used from design drawings or
engineering estimates (metric tons).
YrData = Year in which the landfill last
received waste or, for operating landfills,
the year prior to the first reporting year
when waste disposal data is first
available from company records, or best
available data.
YrOpen = Year in which the landfill first
received waste from company records or
LFC
(YrData − YrOpen + 1)
(Eq. HH-3)
best available data. If no data are
available for estimating YrOpen for a
closed landfill, use 30 years as the
default operating life of the landfill.
(b) For landfills with gas collection
systems, calculate the quantity of CH4
destroyed according to the requirements
in paragraphs (b)(1) and (b)(2) of this
section.
(1) If you continuously monitor the
flow rate, CH4 concentration,
temperature, pressure, and moisture
content of the landfill gas that is
collected and routed to a destruction
device (before any treatment equipment)
using a monitoring meter specifically for
CH4 gas, as specified in § 98.344, you
must use this monitoring system and
calculate the quantity of CH4 recovered
for destruction using Equation HH–4 of
this section. A fully integrated system
that directly reports CH4 content
requires no other calculation than
summing the results of all monitoring
periods for a given year.
N ⎛
( C) n
520oR (P) n
0.454 ⎞
× 0.0423 ×
×
× 1, 440 ×
R = ∑ ⎜ (V) n × ⎡1 − ( f H 20 )n ⎤ ×
⎟
⎣
⎦ 100%
(T) n 1 atm
1, 000 ⎠
n =1 ⎝
sroberts on DSKD5P82C1PROD with RULES
Where:
R = Annual quantity of recovered CH4 (metric
tons CH4).
N = Total number of measurement periods in
a year. Use daily averaging periods for
continuous monitoring system (N = 365).
For weekly sampling, use N = 52.
n = Index for measurement period.
(V)n = Daily average volumetric flow rate for
day n (acfm). If the flow rate meter
automatically corrects for temperature
and pressure, replace ‘‘520 °R/(T)n × (P)n/
1 atm’’ with ‘‘1’’. If the CH4
concentration is determined on a dry
basis and the flow rate meter
automatically corrects for moisture/
content, replace the term [1 ¥ (fH20)n]
with 1.
(fH2O)n = Daily average moisture content of
landfill gas, volumetric basis (cubic feet
water per cubic feet landfill gas).
(C)n = Daily average CH4 concentration of
landfill gas for day n (volume %, dry
basis). If the CH4 concentration is
determined on a wet basis, replace the
term [1 ¥ (fH20)n] with 1.
0.0423 = Density of CH4 lb/cf at 520 °R or 60
°F and 1 atm.
(T)n = Temperature at which flow is
measured for day n (°R).
(P)n = 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).
(2) If you do not continuously monitor
according to paragraph (b)(1) of this
section, you must determine the flow
rate, CH4 concentration, temperature,
pressure, and moisture content of the
landfill gas that is collected and routed
to a destruction device (before any
treatment equipment) at least weekly
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according to the requirements in
paragraphs (b)(2)(i) through (b)(2)(iii) of
this section and calculate the quantity of
CH4 recovered for destruction using
Equation HH–4 of this section.
(i) Continuously monitor gas flow rate
and determine the cumulative volume
of landfill gas each week and the
cumulative volume of landfill gas each
year that is collected and routed to a
destruction device (before any treatment
equipment). Under this option, the gas
flow meter is not required to
automatically correct for temperature,
pressure, or, if necessary, moisture
content. If the gas flow meter is not
equipped with automatic correction for
temperature, pressure, or, if necessary,
moisture content, you must determine
these parameters as specified in
paragraph (b)(2)(iii) of this section.
(ii) Determine the CH4 concentration
in the landfill gas that is collected and
routed to a destruction device (before
any treatment equipment) in a location
near or representative of the location of
the gas flow meter no less than weekly.
(iii) If the gas flow meter is not
equipped with automatic correction for
temperature, pressure, or, if necessary,
moisture content:
(A) Determine the temperature,
pressure in the landfill gas that is
collected and routed to a destruction
device (before any treatment equipment)
in a location near or representative of
the location of the gas flow meter no
less than weekly.
(B) If the CH4 concentration is
determined on a dry basis, determine
PO 00000
Frm 00218
Fmt 4701
Sfmt 4700
(Eq. HH-4)
the moisture content in the landfill gas
that is collected and routed to a
destruction device (before any treatment
equipment) in a location near or
representative of the location of the gas
flow meter no less than weekly
(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
(c)(1) through (c)(3) of this section.
(1) Calculate CH4 generation, adjusted
for oxidation, from the modeled CH4
(GCH4 from Equation HH–1 of this
section) using Equation HH–5 of this
section.
MG = G CH 4 × (1 − OX)
(Eq. HH-5)
Where:
MG = Methane generation, adjusted for
oxidation, 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 (metric tons CH4).
OX = Oxidation fraction. Use the default
value of 0.1 (10%).
(2) For landfills that do not have
landfill gas collection systems, the CH4
emissions are equal to the CH4
generation (MG) 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
(c)(3)(ii) of this section.
E:\FR\FM\30OCR2.SGM
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ER30OC09.132</MATH>
WAR =
ER30OC09.131</MATH>
from first accepting waste until the last
ER30OC09.130</MATH>
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CH4 recovery using Equation HH–6 of
this section.
Emissions = ⎡( G CH 4 − R ) × (1 − OX ) + R × (1 − ( DE × f Dest ) ) ⎤
⎣
⎦
R = Quantity of recovered CH4 from Equation
HH–4 of this section (metric tons).
OX = Oxidation fraction. Use the oxidation
fraction default value of 0.1 (10%).
DE = Destruction efficiency (lesser of
manufacturer’s specified destruction
efficiency and 0.99). If the gas is
transported off-site for destruction, use
DE = 1.
fDest = Fraction of hours the destruction
device was operating (annual operating
R
× (1 − OX)
CE × f Re c
(ii) Calculate CH4 generation and CH4
emissions using measured CH4 recovery
and estimated gas collection efficiency
and Equations HH–7 and HH–8 of this
section.
(Eq. HH-7)
⎡⎛
⎤
⎞
R
Emissions = ⎢⎜
− R ⎟ × (1 − OX ) + R × (1 − ( DE × f Dest ) ) ⎥
⎢
⎥
⎠
⎣⎝ CE × f Re c
⎦
sroberts on DSKD5P82C1PROD with RULES
Where:
MG = Methane generation, adjusted for
oxidation, 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 from Table HH–3 of this
subpart. If area by soil cover type
information is not available, use default
value of 0.75 (CE4 in table HH–3 of this
subpart) for all areas under active
influence of the collection system.
fRec = Fraction of hours the recovery system
was operating (annual operating hours/
8760 hours per year).
OX = Oxidation fraction. Use the oxidation
fractions default value of 0.1 (10%).
DE = Destruction efficiency, (lesser of
manufacturer’s specified destruction
efficiency and 0.99). If the gas is
transported off-site for destruction, use
DE = 1.
fDest = Fraction of hours the destruction
device was operating (device operating
hours/8760 hours per year). If the gas is
destroyed in a back-up flare (or similar
device) or if the gas is transported off-site
for destruction, use fDest = 1.
§ 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
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17:39 Oct 29, 2009
Jkt 220001
‘‘Specifications, Tolerances, and Other
Technical Requirements For Weighing
and Measuring Devices’’ NIST
Handbook 44 (2009)(incorporated by
reference, see § 98.7).
(b) For landfills with gas collection
systems, install, operate, maintain, and
calibrate a gas composition monitor
capable of measuring the concentration
of CH4 in the recovered landfill gas
using one of the methods specified in
paragraphs (b)(1) through (b)(6) of this
section or as specified by the
manufacturer. Gas composition
monitors shall be calibrated prior to the
first reporting year and recalibrated
either annually or at the minimum
frequency specified by the
manufacturer, whichever is more
frequent, or whenever the error in the
midrange calibration check exceeds ± 10
percent.
(1) Method 18 at 40 CFR part 60,
appendix A–6.
(2) ASTM D1945–03, Standard Test
Method for Analysis of Natural Gas by
Gas Chromatography (incorporated by
reference, see § 98.7).
(3) ASTM D1946–90 (Reapproved
2006), Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference, see § 98.7).
(4) GPA Standard 2261–00, Analysis
for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography.
(5) UOP539–97 Refinery Gas Analysis
by Gas Chromatography (incorporated
by reference, see § 98.7).
PO 00000
Frm 00219
Fmt 4701
Sfmt 4700
(Eq. HH-8)
(6) As an alternative to the gas
chromatography methods provided in
paragraphs (b)(1) through (b)(5) of this
section, you may use total gaseous
organic concentration analyzers and
calculate the methane concentration
following the requirements in
paragraphs (b)(6)(i) through (b)(6)(iii) of
this section.
(i) Use Method 25A or 25B at 40 CFR
part 60, appendix A–7 to determine
total gaseous organic concentration. You
must calibrate the instrument with
methane and determine the total
gaseous organic concentration as carbon
(or as methane; K=1 in Equation 25A–
1 of Method 25A at 40 CFR part 60,
appendix A–7).
(ii) Determine a non-methane organic
carbon correction factor no less
frequently than once a reporting year
following the requirements in
paragraphs (b)(6)(ii)(A) through
(b)(6)(ii)(C) of this section.
(A) Take a minimum of three grab
samples of the landfill gas that is
collected and routed to a destruction
device (before any treatment equipment)
with a minimum of 20 minutes between
samples and determine the methane
composition of the landfill gas using
one of the methods specificed in
paragraphs (b)(1) through (b)(5) of this
section.
(B) As soon as practical after each
grab sample is collected and prior to the
collection of a subsequent grab sample,
determine the total gaseous organic
concentration of the landfilll gas that is
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.135</MATH>
MG =
hours/8760 hours per year). If the gas is
destroyed in a back-up flare (or simlar
device) or if the gas is transported off-site
for destruction, use fDest = 1.
ER30OC09.134</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-6)
ER30OC09.133</MATH>
(i) Calculate CH4 emissions from the
modeled CH4 generation and measured
56477
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
collected and routed to a destruction
device (before any treatment equipment)
using either Method 25A or 25B at 40
CFR part 60, appendix A–7 as specified
in paragaph (b)(6)(i) of this section.
(C) Determine the arithmetic average
methane concentration and the
arithmetic average total gaseous organic
concentration of the samples analyzed
according to paragraphs (b)(6)(ii)(A) and
(b)(6)(ii)(B) of this section, respectively,
and calculate the non-methane organic
carbon correction factor as the ratio of
the average methane concentration to
the average total gaseous organic
concentration. If the ratio exceeds 1, use
1 for the non-methane organic carbon
correction factor.
(iii) Calculate the methane
concentration as specified in Equation
HH–9 of this section.
CCH4 = f NMOC × CTGOC
(Eq. HH-9)
sroberts on DSKD5P82C1PROD with RULES
Where:
CCH4 = Methane concentration in the landfill
gas (volume %).
fNMOC = Non-methane organic carbon
correction factor from the most recent
determination of the non-methane
organic carbon correction factor as
specified in paragraph (b)(6)(ii) of this
section (unitless).
CTGOC = Total gaseous organic carbon
concentration measured using Method
25A or 25B at 40 CFR part 60, appendix
A–7 during routine monitoring of the
landfill gas (volume %).
(c) For landfills with gas collection
systems, install, operate, maintain, and
calibrate a gas flow meter capable of
measuring the volumetric flow rate of
the recovered landfill gas using one of
the methods specified in paragraphs
(c)(1) through (c)(8) of this section or as
specified by the manufacturer. Each gas
flow meter shall be calibrated prior to
the first year of reporting and
recalibrated either biennially (every 2
years) or at the minimum frequency
specified by the manufacturer. Except as
provided in § 98.343(b)(2)(i), each gas
flow meter must be capable of correcting
for the temperature and pressure and, if
the gas composition monitor determines
CH4 concentration on a dry basis,
moisture content.
(1) ASME MFC–3M–2004,
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi
(incorporated by reference, see § 98.7).
(2) ASME MFC–4M–1986 (Reaffirmed
1997), Measurement of Gas Flow by
Turbine Meters (incorporated by
reference, see § 98.7).
(3) ASME MFC–6M–1998,
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters (incorporated
by reference, see § 98.7).
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17:39 Oct 29, 2009
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(4) ASME MFC–7M–1987 (Reaffirmed
1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles
(incorporated by reference, see § 98.7).
(5) ASME MFC–11M–2006
Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters (incorporated
by reference, see § 98.7). The mass flow
must be corrected to volumetric flow
based on the measured temperature,
pressure, and gas composition.
(6) ASME MFC–14M–2003
Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters
(incorporated by reference, see § 98.7).
(7) ASME MFC–18M–2001
Measurement of Fluid Flow using
Variable Area Meters (incorporated by
reference, see § 98.7).
(8) Method 2A or 2D at 40 CFR part
60, appendix A–1.
(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
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
the ‘‘after’’ value is not obtained by the
end of the reporting year, you may use
the ‘‘before’’ value for the missing data
substitution. 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.
PO 00000
Frm 00220
Fmt 4701
Sfmt 4700
(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 the ‘‘after’’
value is not obtained by the end of the
reporting year, you may use the
‘‘before’’ value for the missing data
substitution. 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
quantity 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) A classification of the landfill as
‘‘open’’ (actively received waste in the
reporting year) or ‘‘closed’’ (no longer
receiving waste), the year in which the
landfill first started accepting waste for
disposal, the last year the landfill
accepted waste (for open landfills, enter
the estimated year of landfill closure),
the capacity (in metric tons) of the
landfill, an indication of whether
leachate recirculation is used, and the
waste disposal quantity for each year of
landfilling.
(b) Method for estimating waste
disposal quantity, and reason for its
selection.
(c) Waste composition for each year of
landfilling, if available, in percentage
categorized as:
(1) Municipal.
(2) Biosolids or biological sludges.
(3) Other, or more refined categories,
such as those for which k rates are
available in Table HH–1 of this subpart,
and the method or basis for estimating
waste composition.
(d) For each waste type used to
calculate CH4 generation using Equation
HH–1 of this subpart, you must report:
(1) Degradable organic carbon (DOC)
value used in the calculations.
(2) Decay rate (k) value used in the
calculations.
(e) Fraction of CH4 in landfill gas (F)
and an indication of whether the
fraction of CH4 was determined based
on measured values or the default value.
(f) The surface area of the landfill
containing waste (in square meters), the
cover types applicable to the landfill,
the surface area and oxidation fraction
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.136</MATH>
56478
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
for each cover type used to calculate the
average oxidation fraction, and the
average oxidation fraction used in the
calculations.
(g) The modeled annual methane
generation rate for the reporting year
(metric tons CH4) calculated using
Equation HH–1 of this subpart.
(h) For landfills without gas collection
systems, the annual methane emissions
(i.e., the methane generation, adjusted
for oxidation, calculated using Equation
HH–5 of this subpart), reported in
metric tons CH4.
(i) For landfills with gas collection
systems, you must report:
(1) Total volumetric flow of landfill
gas collected for destruction (cubic feet
at 520 °R or 60 °F and 1 atm).
(2) CH4 concentration of landfill gas
collected for destruction (percent by
volume).
(3) Monthly average temperature for
each month at which flow is measured
for landfill gas collected for destruction,
or statement that temperature is
incorporated into internal calculations
run by the monitoring equipment.
(4) Monthly average pressure for each
month at which flow is measured for
landfill gas collected for destruction, or
statement that temperature is
incorporated into internal calculations
run by the monitoring equipment.
(5) An indication of whether
destruction occurs at the landfill facility
or off-site. If destruction occurs at the
landfill facility, also report an
indication of whether a back-up
destruction device is present at the
landfill, the annual operating hours for
the primary destruction device, the
annual operating hours for the back-up
destruction device (if present), and the
destruction efficiency used (percent).
(6) Annual quantity of recovered CH4
(metric tons CH4) calculated using
Equation HH–4 of this subpart.
(7) A description of the gas collection
system (manufacture, capacity, number
of wells, etc.), the surface area (square
meters) and estimated waste depth
(meters) for each area specified in Table
HH–3 of this subpart, the estimated gas
collection system efficiency for landfills
with this gas collection system, and the
annual operating hours of the gas
collection system.
(8) Methane generation corrected for
oxidation calculated using Equation
HH–5 of this subpart, reported in metric
tons CH4.
(9) Methane generation (GCH4) value
used as an input to Equation HH–6 of
this subpart. Specify whether the value
is modeled (GCH4 from HH–1 of this
subpart) or measured (R from Equation
HH–4 of this subpart).
(10) Methane generation corrected for
oxidation calculated using Equation
HH–7 of this subpart, reported in metric
tons CH4.
(11) Methane emissions calculated
using Equation HH–6 of this subpart,
reported in metric tons CH4.
(12) Methane emissions calculated
using Equation HH–8 of this subpart,
reported in metric tons CH4.
§ 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, including the
method or manufacturer’s specification
used for calibration.
§ 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 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS
Factor
Default value
Units
Waste model—bulk waste option
k (precipitation <20 inches/year and no leachate recirculation)
k (precipitation 20–40 inches/year and no leachate recirculation).
k (precipitation >40 inches/year or for landfill areas with leachate recirculation).
L0 (Equivalent to DOC = 0.2028 when MCF = 1, DOCF = 0.5,
and F = 0.5).
0.02 .........................................
0.038 .......................................
yr¥1
yr¥1
0.057 .......................................
yr¥1
0.067 .......................................
metric tons CH4/metric ton waste
Waste model—All MSW landfills
MCF ............................................................................................
DOCF ...........................................................................................
F ..................................................................................................
1 ..............................................
0.5 ...........................................
0.5 ...........................................
sroberts on DSKD5P82C1PROD with RULES
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 0.185a .........................
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,
Calculating methane generation and emissions
OX ...............................................................................................
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0.1 ...........................................
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56479
E:\FR\FM\30OCR2.SGM
30OCR2
wet
wet
wet
wet
wet
wet
wet
wet
basis
basis
basis
basis
basis
basis
basis
basis
56480
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued
Factor
Default value
DE ...............................................................................................
Units
0.99 .........................................
a Use
the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and leachate recirculation is not
used. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate or when leachate recirculation is used.
TABLE HH–2 TO SUBPART HH OF PART 98—U.S. PER CAPITA WASTE DISPOSAL RATES
Waste per
capita
ton/cap/yr
sroberts on DSKD5P82C1PROD with RULES
Year
1950
1951
1952
1953
1954
1955
1956
1957
1958
1959
1960
1961
1962
1963
1964
1965
1966
1967
1968
1969
1970
1971
1972
1973
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
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
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.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
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.........................................................................................................................................................................
.........................................................................................................................................................................
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.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
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.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
.........................................................................................................................................................................
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E:\FR\FM\30OCR2.SGM
30OCR2
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
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
% 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
100
100
100
100
100
84
77
76
72
71
67
63
62
61
61
60
61
63
66
65
64
64
64
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
56481
TABLE HH–3 TO SUBPART HH OF PART 98—LANDFILL GAS COLLECTION EFFICIENCIES
Description
Landfill Gas Collection Efficiency
Subpart II—[Reserved]
Subpart JJ—Manure Management
§ 98.360
Definition of the source category.
(a) This source category consists of
livestock facilities with manure
management systems that emit 25,000
metric tons CO2e or more per year.
Not applicable; do not use this area in the calculation.
CE2: 0%.
CE3: 60%.
CE4: 75%.
CE5: 95%.
CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2+A3+A4+A5).
(1) Table JJ–1 presents the minimum
average annual animal population by
animal group that is estimated to emit
25,000 metric tons CO2e or more per
year. Facilities with an average annual
animal population, as described in
§ 98.363(a)(1) and (2), below those listed
in Table JJ–1 do not need to report
under this rule. A facility with an
annual animal population that exceeds
⎛ AAAPAG, Facility ⎞
CAGF = ∑ Animal Groups ⎜
⎟
APTL AG
⎝
⎠
sroberts on DSKD5P82C1PROD with RULES
Where:
CAGF = Combined Animal Group Factor
AAAPAG,Facility = Average annual animal
population at the facility, by animal
group
APTL AG = Animal population threshold
level, as specified in Table JJ–1 of this
section
(ii) If the calculated CAGF for a
facility is less than 1, the facility is not
required to report under this rule. If the
CAGF is equal to or greater than 1, the
facility must use more detailed
applicability tables and tools to
determine if they are required to report
under this rule.
(b) A manure management system
(MMS) is a system that stabilizes and/
or stores livestock manure, litter, or
manure wastewater in one or more of
the following system components:
Uncovered anaerobic lagoons, liquid/
slurry systems with and without crust
covers (including but not limited to
ponds and tanks), storage pits, digesters,
solid manure storage, dry lots (including
feedlots), high-rise houses for poultry
production (poultry without litter),
poultry production with litter, deep
bedding systems for cattle and swine,
manure composting, and aerobic
treatment.
(c) This source category does not
include system components at a
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(Eq. JJ-1)
livestock facility that are unrelated to
the stabilization and/or storage of
manure such as daily spread or pasture/
range/paddock systems or land
application activities or any method of
manure utilization that is not listed in
§ 98.360(b).
(d) This source category does not
include manure management activities
located off site from a livestock facility
or off-site manure composting
operations.
§ 98.361
Reporting threshold.
Livestock facilities must report GHG
emissions under this subpart if the
facility meets the reporting threshold as
defined in 98.360(a) above, contains a
manure management system as defined
in 98.360(b) above, and meets the
requirements of § 98.2(a)(1).
§ 98.362
GHGs to report.
(a) Livestock facilities must report
annual aggregate CH4 and N2O
emissions for the following MMS
components at the facility:
(1) Uncovered anaerobic lagoons.
(2) Liquid/slurry systems (with and
without crust covers, and including but
not limited to ponds and tanks).
(3) Storage pits.
(4) Digesters, including covered
anaerobic lagoons.
PO 00000
Frm 00223
Fmt 4701
Sfmt 4700
those listed in Table JJ–1 should
conduct a more thorough analysis to
determine applicability.
(2) (i) If a facility has more than one
animal group present (e.g., swine and
poultry), the facility must determine if
they are required to report by
calculating the combined animal group
factor (CAGF) using equation JJ–1:
(5) Solid manure storage.
(6) Dry lots, including feedlots.
(7) High-rise houses for poultry
production (poultry without litter)
(8) Poultry production with litter.
(9) Deep bedding systems for cattle
and swine.
(10) Manure composting.
(11) Aerobic treatment.
(b) A livestock facility that is subject
to this rule only because of emissions
from manure management system
components is not required to report
emissions from subparts C through PP
(other than subpart JJ) of this part.
(c) A livestock facility that is subject
to this part because of emissions from
source categories described in subparts
C through PP of this part is not required
to report emissions under subpart JJ of
this part unless emissions from manure
management systems are 25,000 metric
tons CO2e per year or more.
§ 98.363
Calculating GHG emissions.
(a) For all manure management
system components listed in 98.360(b)
except digesters, estimate the annual
CH4 emissions and sum for all the
components to obtain total emissions
from the manure management system
for all animal types using Equation JJ–
1.
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.137</MATH>
A1: Area with no waste in-place ..............................................................
A2: Area without active gas collection, regardless of cover type ............
H2: Average depth of waste in area A2 ...................................................
A3: Area with daily soil cover and active gas collection ..........................
H3: Average depth of waste in area A3 ...................................................
A4: Area with an intermediate soil cover and active gas collection ........
H4: Average depth of waste in area A4 ...................................................
A5: Area with a final soil and geomembrane cover system and active
gas collection.
H5: Average depth of waste in area A5 ...................................................
Area weighted average collection efficiency for landfills .........................
56482
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
CH 4 Emissions MMS (metric tons/yr) = ∑ animal types ⎡ ∑ MMSC ⎡( TVSAT x VSMMSC
⎣
⎣
)
x (1 − VSss ) x 365 days/yr x ( B0 )AT x MCFMMSC x 0.662 kg CH 4 /m3 x 1 metric ton/1000 kg ⎤
⎦
Where:
MMSC = Manure management systems
component.
TVSAT = Total volatile solids excreted by
animal type, calculated using Equation
JJ–3 of this section (kg/day).
VSMMSC = Fraction of the total manure for
each animal type that is managed in
MMS component MMSC, assumed to be
equivalent to the fraction of VS in each
MMS component.
VSss = Volatile solids removal through solid
separation; if solid separation occurs
prior to the MMS component, use a
default value from Table JJ–4 of this
section; if no solid separation occurs,
this value is set to 0.
TVSAT = Population AT × TAM AT × VSAT /1000
Where:
TVSAT = Daily total volatile solids excreted
per animal type (kg/day).
PopulationAT = Average annual animal
population contributing manure to the
manure management system by animal
type (head) (see description in
§ 98.363(a)(i) and (ii) below).
TAMAT = Typical animal mass for each
animal type, using either default values
in Table JJ–2 of this section or farmspecific data (kg/head).
VSAT = Volatile solids excretion rate for each
animal type, using default values in
Table JJ–2 or JJ–3 of this section (kg VS/
day/1000 kg animal mass).
(1) Average annual animal
populations for static populations (e.g.,
dairy cows, breeding swine, layers)
must be estimated by performing an
animal inventory or review of facility
records once each reporting year.
(2) Average annual animal
populations for growing populations
⎛ NAPA AT ⎞
Population AT = Days onsite AT × ⎜
⎟
⎝ 365 ⎠
Days onsiteAT = Average number of days the
animal is kept at the facility, by animal
type.
NAPAAT = Number of animals produced
annually, by animal type.
Where:
PopulationAT = Average annual animal
population (by animal type).
(Eq. JJ-2)
(B0)AT = Maximum CH4-producing capacity
for each animal type, as specified in
Table JJ–2 of this section (m3 CH4/kg
VS).
MCFMMSC = CH4 conversion factor for the
MMS component, as specified in Table
JJ–5 of this section (decimal).
(Eq. JJ-3)
(meat animals such as beef and veal
cattle, market swine, broilers, and
turkeys) must be estimated each year
using the average number of days each
animal is kept at the facility and the
number of animals produced annually,
and an equation similar or equal to
Equation JJ–4 below, adapted from
Equation 10.1 in 2006 IPCC Guidelines
for National Greenhouse Gas
Inventories, Volume 4, Chapter 10.
(Eq. JJ-4)
(b) For each digester, calculate the
total amount of CH4 emissions, and then
sum the emissions from all digesters, as
shown in Equation JJ–5 of this section.
AD
H 4 Emissions AD = ∑ ( CH 4C − CH 4 D + CH 4 L )
(Eq. JJ-5)
⎛
C
520oR
P
0.454 metric ton ⎞
CH 4C = ⎜ V ×
× 0.0423 ×
×
×
⎟
100%
T
1 atm
1,000 pounds ⎠
⎝
Where:
CH4C = CH4 flow to digester combustion
device (metric tons CH4/yr).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
V = Average annual volumetric flow rate,
calculated in Equation JJ–7 of this
subsection (cubic feet CH4/yr).
PO 00000
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Fmt 4701
Sfmt 4700
(Eq. JJ-6)
C = Average annual CH4 concentration of
digester gas, calculated in Equation JJ–8
of this section (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 °R or
60 °F and 1 atm).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.141</MATH>
ER30OC09.140</MATH>
(1) For each digester, calculate the
annual CH4 flow to the combustion
device (CH4C) using Equation JJ–6 of
this section. A fully integrated system
that directly reports the quantity of CH4
flow to the digester combustion device
requires only summing the results of all
monitoring periods for a given year to
obtain CH4C.
ER30OC09.139</MATH>
CH4D = CH4 destruction at digesters,
calculated using Equation JJ–11 of this
section (metric tons CH4/yr) .
CH4L = Leakage at digesters calculated using
Equation JJ–12 of this section (metric
tons CH4/yr).
ER30OC09.138</MATH>
sroberts on DSKD5P82C1PROD with RULES
Where:
CH4 EmissionsAD = CH4 emissions from
anaerobic digestion (metric tons/yr).
AD = Number of anaerobic digesters at the
manure management facility.
CH4C = CH4 flow to digester combustion
device, calculated using Equation JJ–6 of
this section (metric tons CH4/yr).
ER30OC09.142</MATH>
1
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
P = Average annual pressure at which flow
is measured, calculated in Equation JJ–10
of this section (atm).
(2) For each digester, calculate the
average annual volumetric flow rate,
OD
T=
∑ Tn
n =1
OD
(Eq. JJ-9)
Where:
T = Average annual temperature at which
flow is measured (°R).
OD = Operating days, number of days per
year that the digester was operating
(days/yr).
Tn = Temperature at which flow is measured
for day n(°R).
(Eq. JJ-8)
Where:
C = Average annual CH4 concentration of
digester gas (%, wet basis).
CH 4 D = CH 4C × DE × OH/Hours
⎛ 1
⎞
CH 4 L = CH 4C × ⎜
− 1⎟
CE ⎠
⎝
Where:
CH4L = Leakage at digesters (metric tons/yr).
CH4C = Annual quantity of CH4 flow to
digester combustion device, as
calculated in Equation JJ–6 of this
section (metric tons CH4).
∑ Pn
n =1
(Eq. JJ-10)
Where:
P = Average annual pressure at which flow
is measured (atm).
OD = Operating days, number of days per
year that the digester was operating
(days/yr).
Pn = Pressure at which flow is measured for
day n (atm).
(3) For each digester, calculate the
CH4 destruction at the digester
combustion device using Equation JJ–11
of this section.
OH = Number of hours combustion device is
functioning in reporting year.
Hours = Hours in reporting year.
(4) For each digester, calculate the
CH4 leakage using Equation JJ–12 of this
section.
(Eq. JJ-12)
CE = CH4 collection efficiency of anaerobic
digester, as specified in Table JJ–6 of this
section (decimal).
(c) For each MMS component,
estimate the annual N2O emissions and
sum for all MMS components to obtain
total emissions from the manure
management system for all animal types
using Equation JJ–13 of this section.
Direct N 2O Emissions (metric tons/year) = ∑ animal types ⎡ ∑ MMSC N ex AT × N ex,MMSC
⎣
sroberts on DSKD5P82C1PROD with RULES
OD
(Eq. JJ-11)
DE = CH4 destruction efficiency from flaring
or burning in engine (lesser of
manufacturer’s specified destruction
efficiency and 0.99). If the gas is
transported off-site for destruction, use
DE = 1.
Where:
CH4D = CH4 destruction at digester
combustion device (metric tons/yr).
CH4C = Annual quantity of CH4 flow to
digester combustion device, as
calculated in Equation JJ–6 of this
section (metric tons CH4).
P=
(Eq. JJ-13)
× (1 − Nss ) × EFMMSC × 365 days/yr ⎤ × 44 N 2O/28 N 2O − N × 1 metric ton/1000 kg ⎤
⎦
⎦
Where:
Nex AT = Daily total nitrogen excreted per
animal type, calculated using Equation
JJ–14 of this section (kg N/day).
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
Nex,MMSC = Fraction of the total manure for
each animal type that is managed in
MMS component MMSC, assumed to be
equivalent to the fraction of Nex in each
MMS component.
PO 00000
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Fmt 4701
Sfmt 4700
Nss = Nitrogen removal through solid
separation; if solid separation occurs
prior to the MMS component, use a
default value from Table JJ–4 of this
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.149</MATH>
n =1
OD
OD
ER30OC09.148</MATH>
C=
∑ Cn
OD = Operating days, number of days per
year that the digester was operating
(days/yr).
Cn = Average daily CH4 concentration of
digester gas for day n, as determined
from daily monitoring as specified in
§ 98.364 (%, wet basis).
ER30OC09.147</MATH>
OD
(Eq. JJ-7)
ER30OC09.146</MATH>
Where:
V = Average annual volumetric flow rate
(cubic feet CH4/yr).
OD = Operating days, number of days per
year that that the digester was operating
(days/yr).
Vn = Daily average volumetric flow rate for
day n, as determined from daily
monitoring as specified in § 98.364
(acfm).
n =1 ⎝
1, 440 minutes ⎞
⎟
day
⎠
OD
ER30OC09.145</MATH>
V=
⎛
∑ ⎜ Vn ×
ER30OC09.144</MATH>
OD
CH4 concentration of digester gas,
temperature, and pressure at which flow
are measured using Equations JJ–7
through JJ–10 of this section.
ER30OC09.143</MATH>
T = Average annual temperature at which
flow is measured, calculated in Equation
JJ–9 of this section (°R).
56483
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
EFMMSC = Emission factor for MMS
component, as specified in Table JJ–7 of
this section (kg N2O-N/kg N).
N ex AT = Population AT × TAM AT × N AT /1000
Where:
Nex AT = Total nitrogen excreted per animal
type (kg/day).
PopulationAT = Average annual animal
population contributing manure to the
manure management system by animal
(Eq. JJ-14)
type (head) (see description in
§ 98.363(a)(i) and (ii)).
TAMAT = Typical animal mass by animal
type, using either default values in Table
JJ–2 of this section or farm-specific data
(kg/head).
NAT = Nitrogen excretion rate by animal type,
using default values in Tables JJ–2 or JJ–
3 of this section (kg N/day/1000 kg
animal mass).
(d) Estimate the annual total facility
emissions using Equation JJ–15 of this
section.
Total Emissions (metric tons CO 2e /yr ) = ⎡( CH 4 emissions MMS + CH 4 emissions AD ) x 21] + [Direct N 2O emissions x 310]
⎣
Where:
CH4 emissionsMMS = From Equation JJ–2 of
this section.
CH4 emissionsAD = From Equation JJ–5 of this
section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = From Equation JJ–13
of this section.
310 = Global Warming Potential of N2O.
sroberts on DSKD5P82C1PROD with RULES
§ 98.364 Monitoring and QA/QC
requirements.
(a) Perform an annual animal
inventory or review of facility records
(for static populations) or population
calculation (for growing populations) to
determine the average annual animal
population for each animal type (see
description in § 98.363(a)(1) and (2)).
(b) Perform an analysis on your
operation to determine the fraction of
total manure by weight for each animal
type that is managed in each on-site
manure management system
component. If your system changes from
previous reporting periods, you must
reevaluate the fraction of total manure
managed in each system component.
(c) The CH4 concentration of gas from
digesters must be determined using
ASTM D1946–90 (Reapproved 2006)
Standard Practice for Analysis of
Reformed Gas by Gas Chromatography
(incorporated by reference see § 98.7).
All gas composition monitors shall be
calibrated prior to the first reporting
year for biogas methane and carbon
dioxide content using ASTM D1946–90
(Reapproved 2006) Standard Practice for
Analysis of Reformed Gas by Gas
Chromatography (incorporated by
reference see § 98.7)and recalibrated
either annually or at the minimum
frequency specified by the
manufacturer, whichever is more
frequent, or whenever the error in the
midrange calibration check exceeds ± 10
percent. All monitors shall be
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maintained as specified by the
manufacturer.
(d) All temperature and pressure
monitors must be calibrated using the
procedures and frequencies specified by
the manufacturer. All equipment
(temperature and pressure monitors)
shall be maintained as specified by the
manufacturer.
(e) For digesters with gas collection
systems, install, operate, maintain, and
calibrate a gas flow meter capable of
measuring the volumetric flow rate to
provide data for the GHG emissions
calculations, using the applicable
methods specified in paragraphs (e)(1)
through (e)(6) of this section or as
specified by the manufacturer.
(1) ASME MFC–3M–2004
Measurement of Fluid Flow in Pipes
Using Orifice, Nozzle, and Venturi
(incorporated by reference, see § 98.7).
(2) ASME MFC–4M–1986 (Reaffirmed
1997) Measurement of Gas Flow by
Turbine Meters (incorporated by
reference, see § 98.7).
(3) ASME MFC–6M–1998
Measurement of Fluid Flow in Pipes
Using Vortex Flowmeters (incorporated
by reference, see § 98.7).
(4) ASME MFC–7M–1987 (Reaffirmed
1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles
(incorporated by reference, see § 98.7).
(5) ASME MFC–14M–2003
Measurement of Fluid Flow Using Small
Bore Precision Orifice Meters
(incorporated by reference, see § 98.7).
(6) ASME MFC–18M–2001
Measurement of Fluid Flow using
Variable Area Meters (incorporated by
reference, see § 98.7).
(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
PO 00000
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Sfmt 4700
(Eq. JJ-15)
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.
(g) Each gas flow meter shall be
calibrated prior to the first reporting
year and recalibrated either annually or
at the minimum frequency specified by
the manufacturer, whichever is more
frequent. Each gas flow meter must have
a rated accuracy of ± 5 percent or lower
and be capable of correcting for the
temperature and pressure and, if the gas
composition monitor determines CH4
concentration on a dry basis, moisture
content.
§ 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 or CH4
content data, 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.
§ 98.366
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), each annual report
must contain the following information:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.151</MATH>
section; if no solid separation occurs,
this value is set to 0.
ER30OC09.150</MATH>
56484
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(1) List of manure management
system components at the facility.
(2) Fraction of manure from each
animal type that is handled in each
manure management system
component.
(3) Average annual animal population
(for each animal type) for static
populations or the results of Equation
JJ–4 for growing populations.
(4) Average number of days that
growing animals are kept at the facility
(for each animal type).
(5) The number of animals produced
annually for growing populations (for
each animal type).
(6) Typical animal mass (for each
animal type).
(7) Total facility emissions (results of
Equation JJ–15).
(8) CH4 emissions from manure
management system components listed
in § 98.360(b), except digesters (results
of Equation JJ–2).
(9) VS value used (for each animal
type).
(10) B0 value used (for each animal
type).
(11) Methane conversion factor used
for each MMS component.
(12) Average ambient temperature
used to select each methane conversion
factor.
(13) N2O emissions (results of
Equation JJ–13).
(14) N value used for each animal
type.
(15) N2O emission factor selected for
each MMS component.
(b) Facilities with anaerobic digesters
must also report:
(1) CH4 emissions from anaerobic
digesters (results of Equation JJ–5).
(2) CH4 flow to the digester
combustion device for each digester
(results of Equation JJ–6, or value from
fully integrated monitoring system as
described in 98.363(b)).
(3) CH4 destruction for each digester
(results of Equation JJ–11).
(4) CH4 leakage for each digester
(results of Equation JJ–12).
(5) Total annual volumetric biogas
flow for each digester (results of
Equation JJ–7).
56485
(6) Average annual CH4 concentration
for each digester (results of Equation JJ–
8).
(7) Average annual temperature at
which gas flow is measured for each
digester (results of Equation JJ–9).
(8) Average annual gas flow pressure
at which gas flow is measured for each
digester (results of Equation JJ–10).
(9) Destruction efficiency used for
each digester.
(10) Number of days per year that
each digester was operating.
(11) Collection efficiency used for
each digester.
§ 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, including the
method or manufacturer’s specification
used for calibration.
§ 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 TO SUBPART JJ OF PART 98—ANIMAL POPULATION THRESHOLD LEVEL BELOW WHICH FACILITIES ARE NOT
REQUIRED TO REPORT EMISSIONS UNDER SUBPART JJ 1,2
Average annual animal
population
(Head) 3
Animal group
Beef ......................................................................................................................................................................................................
Dairy .....................................................................................................................................................................................................
Swine ...................................................................................................................................................................................................
Poultry:
Layers ...........................................................................................................................................................................................
Broilers ..........................................................................................................................................................................................
Turkeys .........................................................................................................................................................................................
29,300
3,200
34,100
723,600
38,160,000
7,710,000
1 The threshold head populations in this table were calculated using the most conservative assumptions (high VS and N values, maximum ambient temperatures, and the application of an uncertainty factor) to ensure that facilities at or near the 25,000 metric ton CO2e threshold level
were not excluded from reporting.
2 For facilities with more than one animal group present refer to § 98.360 (2) to estimate the combined animal group factor (CAGF), which is
used to determine if a facility may be required to report.
3 For all animal groups except dairy, the average annual animal population represents the total number of animals present at the facility. For
dairy facilities, the average annual animal population represents the number of mature dairy cows present at the facility (note that heifers and
calves were included in the emission estimates for dairy facilities using the assumption that the average annual animal population of heifers and
calves at dairy facilities are equal to 30 percent of the mature dairy cow average annual animal population, therefore the average annual population for dairy facilities should not include heifers and calves, only dairy cows).
TABLE JJ–2 TO SUBPART JJ OF PART 98—WASTE CHARACTERISTICS DATA
Typical animal
mass
(kg)
sroberts on DSKD5P82C1PROD with RULES
Animal type
Volatile solids excretion rate
(kg VS/day/1000 kg animal mass)
Nitrogen excretion rate
(kg N/day/1000 kg animal mass)
604
476
118
420
420
16
41
68
91
198
See Table JJ–3 ..............................
See Table JJ–3 ..............................
6.41 ................................................
See Table JJ–3 ..............................
See Table JJ–3 ..............................
8.80 ................................................
5.40 ................................................
5.40 ................................................
5.40 ................................................
2.60 ................................................
See Table JJ–3 ..............................
See Table JJ–3 ..............................
0.30 ................................................
See Table JJ–3 ..............................
See Table JJ–3 ..............................
0.60 ................................................
0.42 ................................................
0.42 ................................................
0.42 ................................................
0.24 ................................................
Dairy Cows .....................................
Dairy Heifers ...................................
Dairy Calves ...................................
Feedlot Steers ................................
Feedlot heifers ................................
Market Swine <60 lbs .....................
Market Swine 60–119 lbs ...............
Market Swine 120–179 lbs .............
Market Swine >180 lbs ...................
Breeding Swine ..............................
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30OCR2
Maximum
methane generation potential, Bo
(m3 CH4/kg
VS added)
0.24
0.17
0.17
0.33
0.33
0.48
0.48
0.48
0.48
0.48
56486
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
TABLE JJ–2 TO SUBPART JJ OF PART 98—WASTE CHARACTERISTICS DATA—Continued
Typical animal
mass
(kg)
Animal type
Volatile solids excretion rate
(kg VS/day/1000 kg animal mass)
25
64
450
1.8
1.8
1.8
0.9
6.8
9.20 ................................................
9.50 ................................................
10.00 ..............................................
10.09 ..............................................
10.09 ..............................................
10.80 ..............................................
15.00 ..............................................
9.70 ................................................
Feedlot Sheep ................................
Goats ..............................................
Horses ............................................
Hens >/= 1 yr ..................................
Pullets .............................................
Other Chickens ...............................
Broilers ............................................
Turkeys ...........................................
Nitrogen excretion rate
(kg N/day/1000 kg animal mass)
0.42
0.45
0.30
0.83
0.62
0.83
1.10
0.74
Maximum
methane generation potential, Bo
(m3 CH4/kg
VS added)
................................................
................................................
................................................
................................................
................................................
................................................
................................................
................................................
0.36
0.17
0.33
0.39
0.39
0.39
0.36
0.36
TABLE JJ–3 TO SUBPART JJ OF PART 98—STATE-SPECIFIC VOLATILE SOLIDS (VS) AND NITROGEN (N) EXCRETION
RATES FOR CATTLE
Volatile solids excretion rate (kg VS/day/1000
kg animal mass)
Nitrogen excretion rate (kg VS/day/1000 kg
animal mass)
State
sroberts on DSKD5P82C1PROD with RULES
Dairy
cows
Alabama ...........................................................
Alaska ..............................................................
Arizona .............................................................
Arkansas ..........................................................
California ..........................................................
Colorado ...........................................................
Connecticut ......................................................
Delaware ..........................................................
Florida ..............................................................
Georgia ............................................................
Hawaii ..............................................................
Idaho ................................................................
Illinois ...............................................................
Indiana .............................................................
Iowa ..................................................................
Kansas .............................................................
Kentucky ..........................................................
Louisiana ..........................................................
Maine ...............................................................
Maryland ..........................................................
Massachusetts .................................................
Michigan ...........................................................
Minnesota .........................................................
Mississippi ........................................................
Missouri ............................................................
Montana ...........................................................
Nebraska ..........................................................
Nevada .............................................................
New Hampshire ...............................................
New Jersey ......................................................
New Mexico .....................................................
New York .........................................................
North Carolina ..................................................
North Dakota ....................................................
Ohio ..................................................................
Oklahoma .........................................................
Oregon .............................................................
Pennsylvania ....................................................
Rhode Island ....................................................
South Carolina .................................................
South Dakota ...................................................
Tennessee .......................................................
Texas ...............................................................
Utah ..................................................................
Vermont ............................................................
Virginia .............................................................
Washington ......................................................
West Virginia ....................................................
Wisconsin .........................................................
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8.40
7.30
10.37
7.59
10.02
10.25
9.22
8.63
8.90
9.07
7.00
10.11
9.07
9.38
9.46
9.63
7.89
7.39
8.99
9.02
8.63
10.05
9.17
8.19
8.02
9.03
9.09
9.65
9.44
8.51
10.34
9.42
9.38
8.40
9.01
8.58
9.40
9.26
8.94
9.05
9.45
8.60
9.51
9.70
9.03
9.02
10.36
8.13
9.34
Frm 00228
Dairy
heifers
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
8.35
Fmt 4701
Feedlot
steer
4.27
4.15
3.91
3.98
3.96
3.97
4.41
4.19
4.15
4.18
4.15
4.03
4.15
3.98
3.93
3.97
4.20
4.07
4.07
4.05
4.15
4.00
3.89
4.14
4.08
4.23
3.98
4.07
3.94
3.98
3.88
3.75
4.20
3.88
3.96
3.98
4.06
3.98
4.36
4.15
4.01
4.48
3.95
3.88
4.10
3.98
4.07
4.65
3.95
Sfmt 4700
Feedlot
heifers
4.74
4.58
4.27
4.35
4.33
4.34
4.93
4.64
4.58
4.63
4.58
4.42
4.59
4.35
4.28
4.35
4.65
4.48
4.47
4.45
4.58
4.38
4.24
4.57
4.49
4.69
4.35
4.48
4.30
4.36
4.22
4.05
4.65
4.22
4.33
4.35
4.46
4.35
4.87
4.58
4.39
5.02
4.32
4.22
4.52
4.35
4.47
5.25
4.31
Dairy
cows
Dairy
heifers
0.50
0.45
0.58
0.46
0.56
0.58
0.53
0.51
0.52
0.53
0.44
0.57
0.52
0.54
0.54
0.55
0.48
0.45
0.52
0.52
0.51
0.57
0.53
0.49
0.48
0.52
0.53
0.55
0.54
0.50
0.58
0.54
0.55
0.50
0.52
0.50
0.54
0.53
0.52
0.53
0.54
0.51
0.54
0.55
0.52
0.53
0.58
0.48
0.54
E:\FR\FM\30OCR2.SGM
30OCR2
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
0.46
Feedlot
steer
0.36
0.35
0.33
0.33
0.33
0.33
0.37
0.35
0.35
0.35
0.35
0.34
0.35
0.33
0.33
0.33
0.35
0.34
0.34
0.34
0.35
0.34
0.33
0.35
0.34
0.36
0.33
0.34
0.33
0.33
0.32
0.31
0.35
0.32
0.33
0.33
0.34
0.33
0.37
0.35
0.34
0.38
0.33
0.32
0.34
0.33
0.34
0.40
0.33
Feedlot
heifers
0.38
0.37
0.34
0.35
0.34
0.35
0.40
0.37
0.37
0.37
0.37
0.35
0.37
0.35
0.34
0.35
0.37
0.36
0.36
0.35
0.37
0.35
0.34
0.37
0.36
0.38
0.35
0.36
0.34
0.35
0.33
0.32
0.37
0.34
0.34
0.35
0.36
0.35
0.39
0.37
0.35
0.40
0.34
0.34
0.36
0.35
0.36
0.42
0.34
56487
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TABLE JJ–3 TO SUBPART JJ OF PART 98—STATE-SPECIFIC VOLATILE SOLIDS (VS) AND NITROGEN (N) EXCRETION
RATES FOR CATTLE—Continued
Volatile solids excretion rate (kg VS/day/1000
kg animal mass)
Nitrogen excretion rate (kg VS/day/1000 kg
animal mass)
State
Dairy
cows
Wyoming ..........................................................
Dairy
heifers
9.29
8.35
Feedlot
steer
4.17
Feedlot
heifers
Dairy
cows
4.61
Dairy
heifers
0.53
0.46
Feedlot
steer
0.35
Feedlot
heifers
0.37
TABLE JJ–4 TO SUBPART JJ OF PART 98—VOLATILE SOLIDS AND NITROGEN REMOVAL THROUGH SOLIDS SEPARATION
Volatile solids removal (decimal)
Type of solids separation
Gravity ......................................................................................................................................................
Mechanical:
Stationary Screen .............................................................................................................................
Vibrating Screen ...............................................................................................................................
Screw Press .....................................................................................................................................
Centrifuge .........................................................................................................................................
Roller drum .......................................................................................................................................
Belt press/screen ..............................................................................................................................
0.60
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0.60
0.20
0.15
0.25
0.50
0.25
0.50
BILLING CODE 6560–50–P
VerDate Nov<24>2008
Nitrogen removal
(decimal)
0.10
0.15
0.15
0.25
0.15
0.30
56488
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ER30OC09.192</MATH>
sroberts on DSKD5P82C1PROD with RULES
BILLING CODE 6560–50–C
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
56489
TABLE JJ–6 TO SUBPART JJ OF PART 98—COLLECTION EFFICIENCIES OF ANAEROBIC DIGESTERS
Methane collection efficiency
Anaerobic digester type
Cover type
Covered anaerobic lagoon (biogas capture) ..............................
Bank to bank, impermeable .......................................................
Modular, impermeable ................................................................
Enclosed Vessel .........................................................................
Complete mix, fixed film, or plug flow digester ..........................
TABLE JJ–7 TO SUBPART JJ OF PART combustion or oxidation of fossil-fuel
98—NITROUS OXIDE EMISSION FAC- products (besides coal or crude oil) that
you produce, use as feedstock, import,
TORS (KG N2O–N/KG KJDL N)
Manure management system
component
Uncovered anaerobic lagoon ...
Liquid/Slurry (with crust cover)
Liquid/Slurry (without crust
cover) ....................................
Storage pits ..............................
Digesters ...................................
Solid manure storage ...............
Dry lots (including feedlots) ......
High-rise house for poultry
(poultry without litter) ............
Poultry production with litter .....
Deep bedding for cattle and
swine (active mix) .................
Deep bedding for cattle and
swine (no mix) .......................
Manure Composting (in vessel)
Manure Composting (intensive)
Manure Composting (passive)
Manure Composting (static) .....
Aerobic Treatment (forced aeration) .....................................
Aerobic Treatment (natural aeration) .....................................
N2O emission factor
0
0.005
0
0.002
0
0.005
0.02
0.001
0.001
0.07
0.01
0.006
0.1
0.01
0.006
0.005
0.01
Subpart KK—[Reserved]
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
products listed in Table MM–1 of
subpart MM that are coal-based (coal-toliquid products).
(a) A producer is the owner or
operator of a coal-to-liquids facility. A
coal-to-liquids facility is any facility
engaged in converting coal into liquid
products using a process involving
conversion of coal into gas and then into
liquids (e.g., Fischer-Tropsch) or
conversion of coal directly into liquids
(i.e., direct liquefaction).
(b) An importer or exporter shall have
the same meaning given in § 98.6.
sroberts on DSKD5P82C1PROD with RULES
§ 98.381
Reporting threshold.
Any supplier of coal-to-liquid
products who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
§ 98.382
GHGs to report.
You must report the CO2 emissions
that would result from the complete
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or export during the calendar year.
Additionally, producers must report
CO2 emissions that would result from
the complete combustion or oxidation of
any biomass co-processed with fossil
fuel-based feedstocks.
§ 98.383
Calculating GHG emissions.
You must follow the calculation
methodologies of § 98.393 as if they
applied to the appropriate coal-to-liquid
product supplier (i.e., calculation
methodologies for refiners apply to
producers of coal-to-liquid products and
calculation methodologies for importers
and exporters of petroleum products
apply to importers and exporters of
coal-to-liquid products).
(a) In calculation methodologies in
§ 98.393 for petroleum products or
petroleum-based products, suppliers of
coal-to-liquid products shall also
include coal-to-liquid products.
(b) In calculation methodologies in
§ 98.393 for non-crude feedstocks or
non-crude petroleum feedstocks,
producers of coal-to-liquid products
shall also include coal-to-liquid
products that enter the facility to be
further processed or otherwise used on
site.
(c) In calculation methodologies in
§ 98.393 for petroleum feedstocks,
suppliers of coal-to-liquid products
shall also include coal and coal-toliquid products that enter the facility to
be further processed or otherwise used
on site.
§ 98.384 Monitoring and QA/QC
requirements.
You must follow the monitoring and
QA/QC requirements in § 98.394 as if
they applied to the appropriate coal-toliquid product supplier. Any monitoring
and QA/QC requirement for petroleum
products in § 98.394 also applies to
coal-to-liquid products.
§ 98.385 Procedures for estimating
missing data.
You must follow the procedures for
estimating missing data in § 98.395 as if
they applied to the appropriate coal-toliquid product supplier. Any procedure
for estimating missing data for
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0.975
0.70
0.99
petroleum products in § 98.395 also
applies to coal-to-liquid products.
§ 98.386
Data reporting requirements.
In addition to the information
required by § 98.3(c), the following
requirements apply:
(a) Producers shall report the
following information for each coal-toliquid facility:
(1) For each product listed in Table
MM–1 of subpart MM of this part that
enters the coal-to-liquid facility to be
further processed or otherwise used on
site, report the annual quantity in metric
tons or barrels by each quantity
measurement standard method or other
industry standard practice used. For
natural gas liquids, quantity shall reflect
the individual components of the
product.
(2) For each product listed in Table
MM–1 of subpart MM of this part that
enters the coal-to-liquid facility to be
further processed or otherwise used on
site, report the total annual quantity in
metric tons or barrels. For natural gas
liquids, quantity shall reflect the
individual components of the product.
(3) For each feedstock reported in
paragraph (a)(2) that was produced by
blending a fossil fuel-based product
with a biomass-based product, report
the percent of the volume reported in
paragraph (a)(2) of this section that is
fossil fuel-based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(1) of this section.
(5) For each product (leaving the coalto-liquid facility) listed in Table MM–1
of subpart MM of this part, report the
annual quantity in metric tons or barrels
by each quantity measurement standard
method or other industry standard
practice used. For natural gas liquids,
quantity shall reflect the individual
components of the product.
(6) For each product (leaving the coalto-liquid facility) listed in Table MM–1
of subpart MM of this part, report the
total annual quantity in metric tons or
barrels. For natural gas liquids, quantity
shall reflect the individual components
of the product.
(7) For each product reported in
paragraph (a)(6) of this section that was
produced by blending a fossil fuel-based
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product with a biomass-based product,
report the percent of the volume
reported in paragraph (a)(6) of this
section that is fossil fuel-based.
(8) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(5) of this section.
(9) For every feedstock reported in
paragraph (a)(2) of this section for
which Calculation Methodology 2 of
subpart MM of this part was used to
determine an emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percent mass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor.
(10) For every non-solid feedstock
reported in paragraph (a)(2) of this
section for which Calculation
Methodology 2 of subpart MM of this
part was used to determine an emissions
factor, report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(11) For every product reported in
paragraph (a)(6) of this section for
which Calculation Methodology 2 of
this subpart was used to determine an
emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percent mass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor.
(12) For every non-solid product
reported in paragraph (a)(6) of this
section for which Calculation
Methodology 2 of subpart MM of this
part was used to determine an emissions
factor, report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(13) For each specific type of biomass
that enters the coal-to-liquid facility to
be co-processed with fossil fuel-based
feedstock to produce a product reported
in paragraph (a)(6) of this section, report
the annual quantity in metric tons or
barrels by each quantity measurement
standard method or other industry
standard practice used.
(14) For each specific type of biomass
that enters the coal-to-liquid facility to
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be co-processed with fossil fuel-based
feedstock to produce a product reported
in paragraph (a)(6) of this section, report
the total annual quantity in metric tons
or barrels.
(15) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(3) of this section.
(16) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
feedstock reported in paragraph (a)(2) of
this section, calculated according to
§ 98.393(b) or (h).
(17) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
product (leaving the coal-to-liquid
facility) reported in paragraph (a)(6) of
this section, calculated according to
§ 98.393(a) or (h).
(18) Annual CO2 emissions in metric
tons that would result from the
complete combustion or oxidation of
each type of biomass feedstock coprocessed with fossil fuel-based
feedstocks reported in paragraph (a)(3)
of this section, calculated according to
§ 98.393(c).
(19) Annual CO2 emissions that
would result from the complete
combustion or oxidation of all products,
calculated according to § 98.393(d).
(20) Annual quantity of bulk NGLs in
metric tons or barrels received for
processing during the reporting year.
(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) For each product listed in Table
MM–1 of subpart MM of this part, report
the annual quantity in metric tons or
barrels by each quantity measurement
standard method or other industry
standard practice used. For natural gas
liquids, quantity shall reflect the
individual components of the product.
(2) For each product listed in Table
MM–1 of subpart MM of this part, report
the total annual quantity in metric tons
or barrels. For natural gas liquids,
quantity shall reflect the individual
components of the product as listed in
Table MM–1 of subpart MM of this part.
(3) For each product reported in
paragraph (b)(2) of this section that was
produced by blending a fossil fuel-based
product with a biomass-based product,
report the percent of the volume
reported in paragraph (b)(2) of this
section that is fossil fuel-based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (b)(1) of this section.
(5) For each product reported in
paragraph (b)(2) of this section for
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which Calculation Methodology 2 of
this subpart used was used to determine
an emissions factor, report:
(i) The number of samples collected
according to § 98.394(c)
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percent mass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons.
(6) For each non-solid product
reported in paragraph (b)(2) of this
section for which Calculation
Methodology 2 of this subpart was used
to determine an emissions factor, report:
(i) The density test results in metric
tons ber barrel.
(ii) The standard method used to test
density.
(7) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
imported product reported in paragraph
(b)(2) of this section, calculated
according to § 98.393(a).
(8) The total sum of CO2 emissions
that would result from the complete
combustion or oxidation of all imported
products, calculated according to
§ 98.393(e).
(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) For each product listed in Table
MM–1 of subpart MM of this part, report
the annual quantity in metric tons or
barrels by each quantity measurement
standard method or other industry
standard practice used. For natural gas
liquids, quantity shall reflect the
individual components of the product.
(2) For each product listed in table
MM–1 of subpart MM of this part, report
the total annual quantity in metric tons
or barrels. For natural gas liquids,
quantity shall reflect the individual
components of the product.
(3) For each product reported in
paragraph (c)(2) of this section that was
produced by blending a fossil fuel-based
product with a biomass-based product,
report the percent of the volume
reported in paragraph (c)(2) of this
section that is fossil fuel-based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (c)(1) of this section.
(5) For each product reported in
paragraph (c)(2) of this section for
which Calculation Methodology 2 of
this subpart was used to determine an
emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
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§ 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
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§ 98.390
Definition of the source category.
This source category consists of
petroleum refineries and importers and
exporters of petroleum products and
natural gas liquids as listed in Table
MM–1 of this subpart.
(a) A petroleum refinery for the
purpose of this subpart is any facility
engaged in producing petroleum
products through the distillation of
crude oil.
(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 entity
that imports petroleum products or
natural gas liquids as listed in Table
MM–1 of this subpart. Any blender or
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Reporting threshold.
Any supplier of petroleum products
who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
§ 98.392
GHGs To report.
Suppliers of petroleum products 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, refiners
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) Calculation for individual
products produced, imported, or
exported.
(1) Except as provided in paragraph
(h) 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 CO2 emissions that would
result from the complete combustion or
oxidation of each petroleum product or
natural gas liquid ‘‘i’’ (metric tons).
Producti = Annual volume of product ‘‘i’’
produced, imported, or exported by the
reporting party (barrels). For refiners,
this volume only includes products ex
refinery gate. For natural gas liquids,
volumes shall reflect the individual
components of the product as listed in
Table MM–1 of this subpart.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
(2) In the event that an individual
petroleum product is produced as a solid
rather than liquid any refiner, importer, or
exporter shall calculate CO2 emissions using
Equation MM–1 of this section.
Where:
CO2i = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each petroleum product ‘‘i’’
(metric tons).
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(b) Calculation for individual
products that enter a refinery as a noncrude feedstock.
(1) Except as provided in paragraph
(h) of this section, any refiner shall
calculate CO2 emissions from each noncrude feedstock using Equation MM–2
of this section.
CO 2j = Feedstock j EFj
(Eq. MM-2)
Where:
CO2j = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each non-crude feedstock
‘‘j’’ (metric tons).
Feedstockj = Annual volume of a petroleum
product or natural gas liquid ‘‘j’’ that
enters the refinery to be further refined
or otherwise used on site (barrels). For
natural gas liquids, volumes shall reflect
the individual components of the
product as listed in table MM–1 of this
subpart.
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
(2) In the event that a non-crude
feedstock enters a refinery as a solid
rather than liquid, the refiner shall
calculate CO2 emissions using Equation
MM–2 of this section.
Where:
CO2j = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each non-crude feedstock
‘‘j’’ (metric tons).
Feedstockj = Annual mass of a petroleum
product ‘‘j’’ that enters the refinery to be
further refined or otherwise used on site
(metric tons).
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per metric ton of
feedstock).
(c) Calculation for biomass coprocessed with petroleum feedstocks.
(1) Refiners shall calculate CO2
emissions from each type of biomass
that enters a refinery and is coprocessed with petroleum feedstocks
using Equation MM–3 of this section.
CO 2m = Biomass m
EFm
(Eq. MM-3)
Where:
CO2m = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each type of biomass ‘‘m’’
(metric tons).
Biomassm = Annual volume of a specific type
of biomass that enters the refinery and is
co-processed with petroleum feedstocks
to produce a petroleum product reported
under paragraph (a) of this section
(barrels).
E:\FR\FM\30OCR2.SGM
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ER30OC09.154</GPH>
Records that must be retained.
You must retain records according to
the requirements in § 98.397 as if they
applied to the appropriate coal-to-liquid
product supplier (e.g., retaining copies
of all reports submitted to EPA under
§ 98.386 and records to support
information contained in those reports).
Any records for petroleum products that
are required to be retained in § 98.397
are also required for coal-to-liquid
products.
§ 98.391
Producti = Annual mass of product ‘‘i’’
produced, imported, or exported by the
reporting party (metric tons). For
refiners, this mass only includes
products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per metric ton of
product).
ER30OC09.153</GPH>
§ 98.387
refiner of refined or semi-refined
petroleum products shall be considered
an importer if it otherwise satisfies the
aforementioned definition.
(d) Exporter has the same meaning
given in § 98.6 and includes any entity
that exports petroleum products or
natural gas liquids as listed in Table
MM–1 of this subpart. Any blender or
refiner of refined or semi-refined
petroleum products shall be considered
an exporter if it otherwise satisfies the
aforementioned definition.
ER30OC09.152</GPH>
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percent mass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons.
(6) For each non-solid product
reported in paragraph (c)(2) of this
section for which Calculation
Methodology 2 of this subpart used was
used to determine an emissions factor,
report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(7) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
exported product reported in paragraph
(c)(2) of this section, calculated
according to § 98.393(a).
(8) Total sum of CO2 emissions that
would result from the complete
combustion or oxidation of all exported
products, calculated according to
§ 98.393(e).
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)
Where:
CO2r = Annual CO2 emissions that would
result 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 CO2 emissions that would
result from the complete combustion or
oxidation of each petroleum product or
natural gas liquid ‘‘i’’ (metric tons).
CO2j = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each non-crude feedstock
‘‘j’’ (metric tons).
CO2m = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each type of biomass ‘‘m’’
(metric tons).
(e) Summary calculation for importer
and exporter products. Importers and
exporters shall calculate annual CO2
emissions from all petroleum products
and natural gas liquids imported or
(Eq. MM-5)
Where:
CO2i = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each petroleum product or
natural gas liquid ‘‘i’’ (metric tons).
CO2x = Annual CO2 emissions that would
result from the complete combustion or
oxidation of all petroleum products and
natural gas liquids.
(f) Emission factors for petroleum
products and natural gas liquids. The
emission factor (EFi,j) for each
petroleum product and natural gas
liquid shall be determined using either
of the calculation methods described in
paragraphs (f)(1) or (f)(2) of this section.
The same calculation method must be
used for the entire quantity of the
product for the reporting year. For
refiners, the quantity of a product that
EFi, j = Density
Where:
EFi,j = Emission factor of the petroleum
product or natural gas liquid (metric tons
CO2 per barrel or per metric ton of
product).
Density = Density of the petroleum product
or natural gas liquid (metric tons per
Carbon Share (44 /12)
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%Massi...n )
%Massi* * *n = Percent of total mass that
carbon represents in each molecular
component of the petroleum product or
natural gas liquid.
(g) Emission factors for biomass coprocessed with petroleum feedstocks.
Refiners shall use the most appropriate
default CO2 emission factor (EFm) for
biomass in Table MM–2 of this subpart
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enters a refinery (i.e., a non-crude
feedstock) is considered separate from
the quantity of a product ex refinery
gate.
(1) Calculation Method 1. For solid
products, use the default carbon share
factor (i.e., percent carbon by mass) in
column B of Table MM–1 of this subpart
for the appropriate product. For all
other products, use the default CO2
emission factor listed in column C of
Table MM–1 of this subpart for the
appropriate product.
(2) Calculation Method 2.
(i) For solid products, develop
emission factors according to Equation
MM–6 of this section using a value of
1 for density and direct measurements
of carbon share according to methods
set forth in § 98.394(c). For all other
products, 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).
(Eq. MM-6)
barrel for non-solid products, 1 for solid
products).
Carbon share = Percent of total mass that
carbon represents in the petroleum
product or natural gas liquid, expressed
as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).
44/12 = Conversion factor for carbon to
carbon dioxide.
Carbon Share = ∑ ( %Composition i...n
Where:
Carbon Share = Percent of total mass that
carbon represents in the petroleum
product or natural gas liquid.
%Composition i* * *n = Percent of total
mass that each molecular component in
the petroleum product or natural gas
liquid represents as determined by the
procedures in the selected standard
method.
(Eq. MM-4)
exported, respectively, using Equations
MM–1 and MM–5 of this section.
CO 2 x = ∑ ( CO 2i )
(d) Summary calculation for refinery
products. Refiners shall calculate
annual CO2 emissions from all products
using Equation MM–4 of this section.
(ii) If you use a standard method that
involves gas chromatography to
determine the percent mass of each
component in a product, calculate the
product’s carbon share using Equation
MM–7 of this section.
(Eq. MM-7)
to calculate CO2 emissions in paragraph
(c) of this section.
(h) Special procedures for blended
biomass-based fuels. In the event that
some portion of a petroleum product is
biomass-based and was not derived by
co-processing biomass and petroleum
feedstocks together (i.e., the petroleum
product was produced by blending a
E:\FR\FM\30OCR2.SGM
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ER30OC09.158</GPH>
(
CO 2r = ∑ ( CO 2i ) −∑ CO 2j −∑ ( CO 2m )
product reported under paragraph (a) of
this section (metric tons).
EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per metric ton of
biomass).
ER30OC09.157</GPH>
(2) In the event that biomass enters a
refinery as a solid rather than liquid and
is co-processed with petroleum
feedstocks, the refiner shall calculate
CO2 emissions from each type of
biomass using Equation MM–3 of this
section.
Where:
CO2m = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each type of biomass ‘‘m’’
(metric tons).
Biomassm = Total annual mass of a specific
type of biomass that enters the refinery
to be co-processed with petroleum
feedstocks to produce a petroleum
ER30OC09.156</MATH>
EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per barrel).
ER30OC09.155</MATH>
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through (h)(4) of this section, as
appropriate.
(1) A reporter using Calculation
Methodology 1 to determine the
emission factor of a petroleum product
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17:39 Oct 29, 2009
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EFi ) − ( Product i
EFm
)
EFj − ( Feedstock i
EFm
(Eq. MM-9)
%Volm )
% Volm )
EFm = Default CO2 emission factor from Table
MM–2 of this subpart that most closely
represents the component of petroleum
product ‘‘j’’ that is biomass-based.
%Volm = Percent volume of non-crude
feedstock ‘‘j’’ that is biomass-based, not
including 2.5% of the volume of any
ethanol product blended with the
petroleum-based product, which
represents the denaturant in that ethanol
product, expressed as a fraction (e.g.,
75% would be expressed as 0.75 in the
above equation).
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(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–
9 of this section in place of Equation
MM–2 of this section.
(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–10 of this
section in place of Equation MM–1 of
this section.
(Eq. MM-10)
75% would be expressed as 0.75 in the
above equation).
(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–
11 of this section in place of Equation
MM–2 of this section.
( Eq. MM-11)
§ 98.394 Monitoring and QA/QC
requirements.
(a) Determination of quantity.
(1) The quantity of petroleum
products, natural gas liquids, biomass,
and crude oil shall be determined as
follows:
(i) Where an appropriate standard
method published by a consensus-based
standards organization exists, such a
method shall be used. Consensus-based
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ER30OC09.162</GPH>
(
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%Vol j
EFm = Default CO2 emission factor from Table
MM–2 of this subpart that most closely
represents the component of product ‘‘i’’
that is biomass-based.
%Volm = Percent volume of petroleum
product ‘‘i’’ that is biomass-based, not
including 2.5% of the volume of any
ethanol product blended with the
petroleum-based product, which
represents the denaturant in that ethanol
product, expressed as a fraction (e.g.,
CO 2 j = Feedstock j
Where:
CO2j = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each non-crude feedstock
‘‘j’’ (metric tons).
Feedstockj = Annual volume of each
petroleum product ‘‘j’’ that enters the
refinery to be further refined or
otherwise used on site (barrels).
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
EFi
EFj = Non-crude petroleum feedstock-specific
CO2 emission factor (metric tons CO2 per
barrel).
%Volj = Percent volume of feedstock ‘‘j’’ that
is petroleum-based, including 2.5% of
the volume of any ethanol product
blended with the petroleum-based
product to represent the denaturant in
that ethanol product, expressed as a
fraction (e.g., 75% would be expressed as
0.75 in the above equation).
CO 2i = ( Product i
Where:
CO2i = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each product ‘‘i’’ (metric
tons).
Producti = Annual volume of each petroleum
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).
(Eq. MM-8)
EFi = Petroleum product-specific CO2
emission factor (metric tons CO2 per
barrel) from Table MM–1 of this subpart.
%Voli = Percent volume of product ‘‘i’’ that
is petroleum-based, including 2.5% of
the volume of any ethanol product
blended into a petroleum-based product
to represent the denaturant in that
ethanol product, expressed as a fraction
(e.g., 75% would be expressed as 0.75 in
the above equation).
CO 2 j = Feedstock j
Where:
CO2j = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each non-crude feedstock
‘‘j’’ (metric tons).
Feedstockj = Annual volume of each
petroleum product ‘‘j’’ that enters the
refinery as a feedstock to be further
refined or otherwise used on site
(barrels).
%Voli
ER30OC09.161</MATH>
Where:
CO2i = Annual CO2 emissions that would
result from the complete combustion or
oxidation of each petroleum product ‘‘i’’
(metric tons).
Producti = Annual volume of each petroleum
product ‘‘i’’ produced, imported, or
exported by the reporting party (barrels).
For refiners, this volume only includes
products ex refinery gate.
EFi
ER30OC09.160</GPH>
CO 2i = Product i
shall calculate the CO2 emissions
associated with that product using
Equation MM–8 of this section in place
of Equation MM–1 of this section.
ER30OC09.159</GPH>
petroleum-based product with a
biomass-based fuel), the reporting party
shall calculate emissions for the
petroleum product according to one of
the methods in paragraphs (h)(1)
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standards organizations include, but are
not limited to, the following: ASTM
International, the American National
Standards Institute (ANSI), the
American Gas Association (AGA), the
American Society of Mechanical
Engineers (ASME), the American
Petroleum Institute (API), and the North
American Energy Standards Board
(NAESB).
(ii) Where no appropriate standard
method developed by a consensus-based
standards organization exists, industry
standard practices shall be followed.
(iii) For products that are liquid at 60
degrees Fahrenheit and one standard
atmosphere, all measurements of
quantity shall be temperature-adjusted
and pressure-adjusted to these
conditions. For all other products,
reporters shall use appropriate standard
conditions specified in the standard
method; if temperature and pressure
conditions are not specified in the
standard method or if a reporter uses an
industry standard practice to determine
quantity, the reporter shall use
appropriate standard conditions
according to established industry
practices.
(2) All measurement equipment
(including, but not limited to, flow
meters and tank gauges) used for
compliance with this subpart shall be
appropriate for the standard method or
industry standard practice followed
under paragraph (a)(1)(i) or (a)(1)(ii) of
this section.
(b) Equipment Calibration.
(1) All measurement equipment shall
be calibrated prior to its first use for
reporting under this subpart, using an
appropriate standard method published
by a consensus based standards
organization or according to the
equipment manufacturer’s directions.
(2) Measurement equipment shall be
recalibrated at the minimum frequency
specified by the standard method used
or by the equipment manufacturer’s
directions.
(c) Procedures for Calculation
Methodology 2 of this subpart.
(1) Reporting parties shall collect one
sample of each petroleum product or
natural gas liquid on any day of each
calendar month of the reporting year in
which the quantity of that product was
measured in accordance with the
requirements of this subpart. For
example, if a given product was
measured as entering the refinery
continuously throughout the reporting
year, twelve samples of that product
shall be collected over the reporting
year, one on any day of each calendar
month of that year. If a given product
was only measured from April 15
through June 10 of the reporting year, a
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17:39 Oct 29, 2009
Jkt 220001
refiner would collect three samples
during that year, one during each of the
calendar months of April, May and June
on a day when the product was
measured as either entering or exiting
the refinery. Each sample shall be
collected using an appropriate standard
method published by a consensus-based
standards organization.
(2) Mixing and handling of samples
shall be performed using an appropriate
standard method published by a
consensus-based standards organization.
(3) Density measurement.
(i) For all products that are not solid,
reporters shall test for density using an
appropriate standard method published
by a consensus-based standards
organization.
(ii) The density value for a given
petroleum product shall be generated by
either making a physical composite of
all of the samples collected for the
reporting year and testing that single
sample or by measuring the individual
samples throughout the year and
defining the representative density
value for the sample set by numerical
means, i.e., a mathematical composite. If
a physical composite is chosen as the
option to obtain the density value, the
reporter shall submit each of the
individual samples collected during the
reporting year to the laboratory
responsible for generating the composite
sample.
(iii) For physical composites, the
reporter shall handle the individual
samples and the laboratory shall mix
them in accordance with an appropriate
standard method published by a
consensus-based standards organization.
(iv) All measurements of density shall
be temperature-adjusted and pressureadjusted to the conditions assumed for
determining the quantities of the
product reported under this subpart.
(4) Carbon share measurement.
(i) Reporters shall test for carbon
share using an appropriate standard
method published by a consensus-based
standards organization.
(ii) If a standard method that involves
gas chromatography is used to
determine the percent mass of each
component in a product, the molecular
formula for each component shall be
obtained from the information provided
in the standard method and the atomic
mass of each element in a given
molecular component shall be obtained
from the periodic table of the elements.
(iii) The carbon share value for a
given petroleum product shall be
generated by either making a physical
composite of all of the samples collected
for the reporting year and testing that
single sample or by measuring the
individual samples throughout the year
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and defining the representative carbon
share value for the sample set by
numerical means, i.e., a mathematical
composite. If a physical composite is
chosen as the option to obtain the
carbon share value, the reporter shall
submit each of the individual samples
collected during the reporting year to
the laboratory responsible for generating
the composite sample.
(iv) For physical composites, the
reporter shall handle the individual
samples and the laboratory shall mix
them in accordance with an appropriate
standard method published by a
consensus-based standards organization.
(d) Measurement of API gravity and
sulfur content of crude oil.
(1) Samples of each batch of crude oil
shall be taken according to an
appropriate standard method published
by a consensus-based standards
organization.
(2) Samples shall be handled
according to an appropriate standard
method published by a consensus-based
standards organization.
(3) API gravity shall be measured
using an appropriate standard method
published by a consensus-based
standards organization.
(4) Sulfur content shall be measured
using an appropriate standard method
published by a consensus-based
standards organization.
(5) All measurements shall be
temperature-adjusted and pressureadjusted to the conditions assumed for
determining the quantities of crude oil
reported under this subpart.
§ 98.395 Procedures for estimating
missing data.
(a) Determination of quantity.
Whenever the quality assurance
procedures in § 98.394(a) cannot be
followed to measure the quantity of one
or more petroleum products, natural gas
liquids, types of biomass, feedstocks, or
crude oil batches during any period
(e.g., if a meter malfunctions), the
following missing data procedures shall
be used:
(1) For quantities of a product that are
purchased or sold, a period of missing
data shall be substituted using a
reporter’s established procedures for
billing purposes in that period as agreed
to by the party selling or purchasing the
product.
(2) For quantities of a product that are
not purchased or sold but of which the
custody is transferred, a period of
missing data shall be substituted using
a reporter’s established procedures for
tracking purposes in that period as
agreed to by the party involved in
custody transfer of the product.
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(b) Determination of emission factor.
Whenever any of the procedures in
§ 98.394(c) cannot be followed to
develop an emission factor for any
reason, Calculation Methodology 1 of
this subpart must be used in place of
Calculation Methodology 2 of this
subpart for the entire reporting year.
(c) Determination of API gravity and
sulfur content of crude oil. For missing
data on sulfur content or API gravity,
the substitute data value shall be the
arithmetic average of the quality-assured
values of API gravity or sulfur content
in the batch preceding and the batch
immediately following the missing data
incident. If no quality-assured data are
available prior to the missing data
incident, the substitute data value shall
be the first quality-assured values for
API gravity and sulfur content obtained
from the batch after the missing data
period.
sroberts on DSKD5P82C1PROD with RULES
§ 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) For each petroleum product or
natural gas liquid listed in table MM–1
of this subpart that enters the refinery to
be further refined or otherwise used on
site, report the annual quantity in metric
tons or barrels by each quantity
measurement standard method or other
industry standard practice used. For
natural gas liquids, quantity shall reflect
the individual components of the
product.
(2) For each petroleum product or
natural gas liquid listed in Table MM–
1 of this subpart that enters the refinery
to be further refined or otherwise used
on site, report the annual quantity in
metric tons or barrels. For natural gas
liquids, quantity shall reflect the
individual components of the product.
(3) For each feedstock reported in
paragraph (a)(2) of this section that was
produced by blending a petroleumbased product with a biomass-based
product, report the percent of the
volume reported in paragraph (a)(2) of
this section that is petroleum-based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(1) of this section.
(5) For each petroleum product and
natural gas liquid (ex refinery gate)
listed in Table MM–1 of this subpart,
report the annual quantity in metric
tons or barrels by each quantity
measurement standard method or other
industry standard practice used. For
natural gas liquids, quantity shall reflect
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the individual components of the
product.
(6) For each petroleum product and
natural gas liquid (ex refinery gate)
listed in Table MM–1 of this subpart,
report the annual quantity in metric
tons or barrels. For natural gas liquids,
quantity shall reflect the individual
components of the product.
(7) For each product reported in
paragraph (a)(6) of this section that was
produced by blending a petroleumbased product with a biomass-based
product, report the percent of the
volume reported in paragraph (a)(6) of
this section that is petroleum-based.
(8) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(5) of this section.
(9) For every feedstock reported in
paragraph (a)(2) of this section for
which Calculation Methodology 2 of
this subpart was used to determine an
emissions factor, report:
(i) The number of samples collected
according to § 98.394(c)
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percentmass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons.
(10) For every non-solid feedstock
reported in paragraph (a)(2) of this
section for which Calculation
Methodology 2 of this subpart was used
to determine an emissions factor, report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(11) For every petroleum product and
natural gas liquid reported in paragraph
(a)(6) of this section for which
Calculation Methodology 2 of this
subpart was used to determine an
emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percentmass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons CO2 per barrel or
per metric ton of product.
(12) For every non-solid petroleum
product and natural gas liquid reported
in paragraph (a)(6) for which
Calculation Method 2 was used to
determine an emissions factor, report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
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56495
(13) For each specific type of biomass
that enters the refinery to be coprocessed with petroleum feedstocks to
produce a petroleum product reported
in paragraph (a)(6) of this section, report
the annual quantity in metric tons or
barrels by each quantity measurement
standard method or other industry
standard practice used.
(14) For each specific type of biomass
that enters the refinery to be coprocessed with petroleum feedstocks to
produce a petroleum product reported
in paragraph (a)(6) of this section, report
the annual quantity in metric tons or
barrels.
(15) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (a)(13) of this section.
(16) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
petroleum product and natural gas
liquid (ex refinery gate) reported in
paragraph (a)(6) of this section,
calculated according to § 98.393(a) or
(h).
(17) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
feedstock reported in paragraph (a)(2) of
this section, calculated according to
§ 98.393(b) or (h).
(18) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each type of
biomass feedstock co-processed with
petroleum feedstocks reported in
paragraph (a)(13) of this section,
calculated according to § 98.393(c).
(19) The sum of CO2 emissions that
would result from the complete
combustion or oxidation of all products,
calculated according to § 98.393(d).
(20) All of the following information
for all crude oil feedstocks used at the
refinery:
(i) Batch volume in barrels.
(ii) API gravity of the batch at the
point of entry at the refinery.
(iii) Sulfur content of the batch at the
point of entry at the refinery.
(iv) Country of origin of the batch, if
known.
(21) The quantity of bulk NGLs in
metric tons or barrels received for
processing during the reporting year.
(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) For each petroleum product and
natural gas liquid listed in Table MM–
1 of this subpart, report the annual
quantity in metric tons or barrels by
each quantity measurement standard
method or other industry standard
practice used. For natural gas liquids,
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sroberts on DSKD5P82C1PROD with RULES
quantity shall reflect the individual
components of the product.
(2) For each petroleum product and
natural gas liquid listed in Table MM–
1 of this subpart, report the annual
quantity in metric tons or barrels. For
natural gas liquids, quantity shall reflect
the individual components of the
product as listed in Table MM–1 of this
subpart.
(3) For each product reported in
paragraph (b)(2) of this section that was
produced by blending a petroleumbased product with a biomass-based
product, report the percent of the
volume reported in paragraph (b)(2) of
this section that is petroleum-based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (b)(1) of this section.
(5) For each product reported in
paragraph (b)(2) of this section for
which Calculation Methodology 2 of
this subpart used was used to determine
an emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percent mass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons CO2 per barrel or
per metric ton of product.
(6) For each non-solid product
reported in paragraph (b)(2) of this
section for which Calculation
Methodology 2 of this subpart was used
to determine an emissions factor, report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(7) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of each
imported petroleum product and natural
gas liquid reported in paragraph (b)(2) of
this section, calculated according to
§ 98.393(a).
(8) The sum of CO2 emissions that
would result from the complete
combustion oxidation of all imported
products, calculated according to
§ 98.393(e).
(c) In addition to the information
required by § 98.3(c), each exporter shall
report all of the following information at
the corporate level:
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(1) For each petroleum product and
natural gas liquid listed in Table MM–
1 of this subpart, report the annual
quantity in metric tons or barrels by
each quantity measurement standard
method or other industry standard
practice used. For natural gas liquids,
quantity shall reflect the individual
components of the product.
(2) For each petroleum product and
natural gas liquid listed in Table MM–
1 of this subpart, report the annual
quantity in metric tons or barrels. For
natural gas liquids, quantity shall reflect
the individual components of the
product.
(3) For each product reported in
paragraph (c)(2) of this section that was
produced by blending a petroleumbased product with a biomass-based
product, report the percent of the
volume reported in paragraph (c)(2) of
this section that is petroleum based.
(4) Each standard method or other
industry standard practice used to
measure each quantity reported in
paragraph (c)(1) of this section.
(5) For each product reported in
paragraph (c)(2) of this section for
which Calculation Methodology 2 of
this subpart was used to determine an
emissions factor, report:
(i) The number of samples collected
according to § 98.394(c).
(ii) The sampling standard method
used.
(iii) The carbon share test results in
percentmass.
(iv) The standard method used to test
carbon share.
(v) The calculated CO2 emissions
factor in metric tons CO2 per barrel or
per metric ton of product.
(6) For each non-solid product
reported in paragraph (c)(2) of this
section for which Calculation
Methodology 2 of this subpart used was
used to determine an emissions factor,
report:
(i) The density test results in metric
tons per barrel.
(ii) The standard method used to test
density.
(7) The CO2 emissions in metric tons
that would result from the complete
combustion or oxidation of for each
exported petroleum product and natural
gas liquid reported in paragraph (c)(2) of
this section, calculated according to
§ 98.393(a).
(8) The sum of CO2 emissions that
would result from the complete
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combustion or oxidation of all exported
products, calculated according to
§ 98.393(e).
§ 98.397
Records that must be retained.
(a) All reporters shall retain copies of
all reports submitted to EPA under
§ 98.396. In addition, all reporters 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 quantities that are reported
under this subpart, including records
documenting any estimations of missing
data and the number of calendar days in
the reporting year for which substitute
data procedures were followed. For all
quantities of petroleum products,
natural gas liquids, biomass, and
feedstocks, reporters shall maintain
metering, guaging, and other records
normally maintained in the course of
business to document product and
feedstock flows including the date of
initial calibration and the frequency of
recalibration for the measurement
equipment used
(c) Reporters shall retain laboratory
reports, calculations and worksheets
used to estimate the CO2 emissions of
the quantities of petroleum products,
natural gas liquids, biomass, and
feedstocks reported under this subpart.
(d) Reporters shall maintain
laboratory reports, calculations and
worksheets used in the measurement of
density and carbon share for any
petroleum product or natural gas liquid
for which CO2 emissions were
calculated using Calculation
Methodology 2.
(e) Reporters shall maintain laboratory
reports, calculations and worksheets
used in the measurement of API gravity
and sulfur content for every crude oil
batch reported under this subpart.
(f) Estimates of missing data shall be
documented and records maintained
showing the calculations.
(g) 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.
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56497
TABLE MM–1 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR PETROLEUM PRODUCTS AND NATURAL GAS
LIQUIDS 1 2
Column A:
density
(metric tons/
bbl)
Products
Column B:
carbon
share
(% of mass)
Column C:
emission
factor
(metric tons
CO2/bbl)
0.1181
0.1183
0.1185
86.66
86.63
86.61
0.3753
0.3758
0.3763
0.1155
0.1161
0.1167
86.50
86.55
86.59
0.3663
0.3684
0.3705
0.1167
0.1165
0.1164
86.13
86.07
86.00
0.3686
0.3677
0.3670
0.1165
0.1165
0.1166
0.1185
86.05
86.06
86.06
86.61
0.3676
0.3676
0.3679
0.3763
0.1181
0.1183
0.1185
86.66
86.63
86.61
0.3753
0.3758
0.3763
0.1155
0.1161
0.1167
86.50
86.55
86.59
0.3663
0.3684
0.3705
0.1167
0.1165
0.1164
86.13
86.07
86.00
0.3686
0.3677
0.3670
0.1165
0.1165
0.1166
0.1185
86.05
86.06
86.06
86.61
0.3676
0.3676
0.3679
0.3763
0.1268
0.1257
0.1181
0.1182
0.1229
0.1156
37.48
64.82
68.13
70.53
70.53
70.53
0.1743
0.2988
0.2950
0.3057
0.3178
0.2990
0.1346
0.1346
0.1346
86.40
86.40
86.40
0.4264
0.4264
0.4264
0.1342
0.1342
0.1342
0.1452
0.1365
0.1528
0.1294
0.1346
0.1452
87.30
87.30
87.30
86.47
85.67
84.67
86.30
86.40
86.47
0.4296
0.4296
0.4296
0.4604
0.4288
0.4744
0.4095
0.4264
0.4604
Finished Motor Gasoline
Conventional—Summer
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
Conventional—Winter
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
Reformulated—Summer
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
Reformulated—Winter
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
Gasoline—Other ......................................................................................................................................
Blendstocks
CBOB—Summer
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
CBOB—Winter
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
RBOB—Summer
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
RBOB—Winter
Regular .............................................................................................................................................
Midgrade ...........................................................................................................................................
Premium ...........................................................................................................................................
Blendstocks—Other .................................................................................................................................
Oxygenates
Methanol ..................................................................................................................................................
GTBA .......................................................................................................................................................
MTBE .......................................................................................................................................................
ETBE ........................................................................................................................................................
TAME .......................................................................................................................................................
DIPE .........................................................................................................................................................
sroberts on DSKD5P82C1PROD with RULES
Distillate Fuel Oil
Distillate No. 1
Ultra Low Sulfur ................................................................................................................................
Low Sulfur .........................................................................................................................................
High Sulfur ........................................................................................................................................
Distillate No. 2
Ultra Low Sulfur ................................................................................................................................
Low Sulfur .........................................................................................................................................
High Sulfur ........................................................................................................................................
Distillate Fuel Oil No. 4 ............................................................................................................................
Residual Fuel Oil No. 5 (Navy Special) ..................................................................................................
Residual Fuel Oil No. 6 (a.k.a. Bunker C) ..............................................................................................
Kerosene-Type Jet Fuel ..........................................................................................................................
Kerosene ..................................................................................................................................................
Diesel—Other ..........................................................................................................................................
Petrochemical Feedstocks
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TABLE MM–1 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR PETROLEUM PRODUCTS AND NATURAL GAS
LIQUIDS 1 2—Continued
Column A:
density
(metric tons/
bbl)
Products
Column B:
carbon
share
(% of mass)
Column C:
emission
factor
(metric tons
CO2/bbl)
0.1158
0.1390
84.11
87.30
0.3571
0.4450
0.1476
0.1622
85.80
85.70
0.4643
0.5097
0.1120
0.1222
0.1428
0.1285
0.1818
0.1634
0.1405
0.0866
0.0903
0.0784
0.0803
0.0911
0.0935
0.0876
0.0936
0.1055
0.1380
85.00
84.76
85.80
85.30
92.28
83.47
77.70
79.89
85.63
81.71
85.63
82.66
85.63
82.66
85.63
83.63
85.49
0.3490
0.3798
0.4492
0.4019
0.6151
0.5001
0.4003
0.2537
0.2835
0.2349
0.2521
0.2761
0.2936
0.2655
0.2939
0.3235
0.4326
Naphthas (< 401 °F) .........................................................................................................................
Other Oils (> 401 °F) ........................................................................................................................
Unfinished Oils
Heavy Gas Oils ........................................................................................................................................
Residuum .................................................................................................................................................
Other Petroleum Products and Natural Gas Liquids
Aviation Gasoline .....................................................................................................................................
Special Naphthas .....................................................................................................................................
Lubricants ................................................................................................................................................
Waxes ......................................................................................................................................................
Petroleum Coke .......................................................................................................................................
Asphalt and Road Oil ..............................................................................................................................
Still Gas ...................................................................................................................................................
Ethane ......................................................................................................................................................
Ethylene ...................................................................................................................................................
Propane ...................................................................................................................................................
Propylene .................................................................................................................................................
Butane ......................................................................................................................................................
Butylene ...................................................................................................................................................
Isobutane .................................................................................................................................................
Isobutylene ...............................................................................................................................................
Pentanes Plus ..........................................................................................................................................
Miscellaneous Products ...........................................................................................................................
1 In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM–1 of this subpart 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.
TABLE MM–2 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR BIOMASS-BASED FUELS AND BIOMASS
Column A:
Density
(metric tons/
bbl)
Biomass-based fuel and biomass
Column B:
Carbon
share
(% of mass)
Column C:
Emission
factor
(metric tons
CO2/bbl)
0.1267
0.1396
0.1333
0.1460
52.14
77.30
76.19
76.77
0.2422
0.3957
0.3724
0.4110
Ethanol (100%) ........................................................................................................................................
Biodiesel (100%, methyl ester) ................................................................................................................
Rendered Animal Fat ...............................................................................................................................
Vegetable Oil ...........................................................................................................................................
Subpart NN—Suppliers of Natural Gas
and Natural Gas Liquids
sroberts on DSKD5P82C1PROD with RULES
§ 98.400
Definition of the source category.
This supplier category consists of
natural gas liquids fractionators and
local natural gas distribution
companies.
(a) Natural gas liquids fractionators
are installations that fractionate natural
gas liquids (NGLs) into their consitutent
liquid products (ethane, propane,
normal butane, isobutane or pentanes
plus) for supply to downstream
facilities.
(b) Local Distribution Companies
(LDCs) are companies that own or
operate distribution pipelines, not
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interstate pipelines or intrastate
pipelines, that physically deliver
natural gas to end users and that are
regulated as separate operating
companies by State public utility
commissions or that operate as
independent municipally-owned
distribution systems.
(c) This supply category does not
consist of the following facilities:
(1) Field gathering and boosting
stations.
(2) Natural gas processing plants that
separate NGLs from natural gas and
produce bulk or y-grade NGLs but do
not fractionate these NGLs into their
constituent products.
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(3) Facilities that meet the definition
of refineries and report under subpart
MM of this part.
(4) Facilities that meet the definition
of petrochemical plants and report
under subpart X of this part.
§ 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) NGL fractionators must report the
CO2 emissions that would result from
the complete combustion or oxidation of
the annual quantity of ethane, propane,
normal butane, isobutane, and pentanes
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(2) Calculation Methodology 2. NGL
fractionators shall estimate CO2
emissions that would result from the
complete combustion or oxidation of the
product(s) supplied using Equation NN–
2 of this section. LDCs shall estimate
CO2 emissions that would result from
the complete combustion or oxidation of
the product received at the city gate
using Equation NN–2. For each product,
use the default CO2 emission factor
found in Table NN–2 of this subpart.
Alternatively, for each product, a
reporter-specific CO2 emission factor
may be used in place of the default
factor, provided it is developed using
methods outlined in § 98.404. For each
product, you must use the same volume
unit throughout the equation.
CO 2i = ∑ Fuelh ∗ EFh
(Eq. NN- 2)
h
HHVh
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(Eq. NN-1)
Where:
CO2i = Annual CO2 mass emissions that
would result from the combustion or
oxidation of each product ‘‘h’’ (metric
tons)
Fuel = Total annual volume of product ‘‘h’’
supplied (bbl or Mscf per year)
EFh = CO2 emission factor of product ‘‘h’’
(MT CO2/bbl, or MT CO2/Mscf)
(b) Each LDC shall follow the
procedures below.
(1) For natural gas that is received for
redelivery to downstream gas
transmission pipelines and other local
distribution companies, use eEquation
NN–3 of this section and 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.
CO 2 j = Fuel
EF
(Eq. NN-3)
Where:
CO2j = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas for redelivery to
transmission pipelines or other LDCs
(metric tons).
Fuel = Total annual volume of natural gas
supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).
(2)(i) For natural gas delivered to each
meter registering a supply equal to or
CO 2l = [ Fuel1 − Fuel2 ] EF
Where:
CO2l = Annual CO2 mass emissions that
would result from the combustion or
oxidation of the net natural gas that is
liquefied and/or stored and not used for
deliveries by the LDC within the
reported year (metric tons).
Fuel1 = Total annual volume of natural gas
received by the LDC at the city gate and
EFh
Frm 00241
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CO 2 k = Fuel
EF
(Eq. NN- 4)
Where:
CO2k = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas received by endusers that receive a supply equal to or
greater than 460,000 Mscf per year
(metric tons).
Fuel = Total annual volume of natural gas
supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).
(3) For natural gas received by the
LDC at the city gate that is injected into
on-system storage, and/or liquefied and
stored, use Equation NN–5 of this
section and the default value for the CO2
emission factors found in Table NN–2 of
this subpart. Alternatively, a reporterspecific CO2 emission factor may be
used, provided it is developed using
methods outlined in § 98.404.
(Eq. NN-5)
stored on-system or liquefied and stored
in the reportng year (Mscf per year).
Fuel2 = Total annual volume of natural gas
that is used for deliveries in the
reporting year that was not otherwise
accounted for in Equation NN–1 or NN–
2 of this section (Mscf per year). This
primarily includes natural gas previously
stored on-system or liquefied and stored
that is removed from storage and used
PO 00000
greater than 460,000 Mscf per year, use
Equation NN–4 of this section and the
default values for the CO2 emission
factors found in Table NN–2 of this
subpart.
(ii) Alternatively, reporter-specific
CO2 emission factors may be used,
provided they are developed using
methods outlined in § 98.404.
for deliveries to customers or other LDCs
by the LDC within the reporting year.
This also includes natural gas that
bypassed the city gate and was delivered
directly to LDC systems from producers
or natural gas processing plants from
local production.
EF = Fuel-specific CO2 emission factor (MT
CO2/Mscf).
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.167</MATH>
Where:
CO2i = Annual CO2 mass emissions that
would result from the combustion or
oxidation of each product ‘‘h’’ for
redelivery to all recipients (metric tons).
Fuel = Total annual volume of product ‘‘h’’
supplied (volume per year, in Mscf for
natural gas and bbl for NGLs).
HHV = Higher heating value of product ‘‘h’’
supplied (MMBtu/Mscf or MMBtu/bbl).
EFh = CO2 emission factor of product ‘‘h’’ (kg
CO2/MMBtu).
1 x 10¥3 = Conversion factor from kilograms
to metric tons (MT/kg).
∑ Fuelh
ER30OC09.166</MATH>
CO 2i = 1 x 10−3
ER30OC09.165</MATH>
Calculating GHG emissions.
(a) LDCs and fractionators shall, for
each individual product reported under
this part, calculate the estimated CO2
the product received at the city gate
using Equation NN–1. For each product,
use the default value for higher heating
value and CO2 emission factor in Table
NN–1 of this subpart. Alternatively, for
each product, a reporter-specific higher
heating value and CO2 emission factor
may be used, in place of one or both
defaults provided they are developed
using methods outlined in § 98.404. For
each product, you must use the same
volume unit throughout the equation.
ER30OC09.164</MATH>
§ 98.403
emissions that would result from the
complete combustion or oxidation of the
products supplied using either of
Calculation Methodology 1 or 2 of this
subpart:
(1) Calculation Methodology 1. NGL
fractionators shall estimate CO2
emissions that would result from the
complete combustion or oxidation of the
product(s) supplied using Equation NN–
1 of this section. LDCs shall estimate
CO2 emissions that would result from
the complete combustion or oxidation of
ER30OC09.163</GPH>
plus that is produced and sold or
delivered to others.
(b) LDCs 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 on their distribution
systems.
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
supply of natural gas to end-users using
Equation NN–6 of this section.
CO 2 = ∑ CO 2i −∑ CO 2j −∑ CO 2k − ∑ CO 2l
calculated in paragraph (b)(2) of this
section (metric tons).
CO2l = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas received by the
LDC and liquefied and/or stored but not
used for deliveries within the reported
year as calculated in paragraph (b)(3) of
this section (metric tons).
(c) Each NGL fractionator shall follow
the following procedures.
(1)(i) For fractionated NGLs received
by the reporter from other NGL
fractionators, you shall use Equation
NN–7 of this section and the default
values for the CO2 emission factors
found in Table NN–2 of this subpart.
(ii) Alternatively, reporter-specific
CO2 emission factors may be used,
provided they are developed using
methods outlined in § 98.404.
CO 2 = ∑ CO 2i − ∑ CO 2j
Where:
CO2 = Annual CO2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs delivered
to customers or on behalf of customers
(metric tons).
CO2i = Annual CO2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs delivered
to all customers as calculated in
paragraph (a)(1) or (a)(2) of this section
(metric tons).
CO2m = Annual CO2 mass emissions that
would result from the combustion or
oxidation of fractionated NGLs received
from other fractionators and calculated
in paragraph (c)(1) of this section (metric
tons).
sroberts on DSKD5P82C1PROD with RULES
§ 98.404 Monitoring and QA/QC
requirements.
(a) Determination of quantity.
(1) NGL fractionators and LDCs shall
determine the quantity of NGLs and
natural gas using methods in common
use in the industry for billing purposes
as audited under existing Sarbanes
Oxley regulationn.
(i) Where an appropriate standard
method published by a consensus-based
standards organization exists, such a
method shall be used. Consensus-based
standards organizations include, but are
not limited to, the following: ASTM
International, the American National
Standards Institute (ANSI), the
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EFg
(Eq. NN-7)
g
Where:
CO2m = Annual CO2 mass emissions that
would result from the combustion or
oxidation of each fractionated NGL
product ‘‘g’’ received from other
fractionators (metric tons).
Fuelg = Total annual volume of each NGL
product ‘‘g’’ received (bbls).
EF = Fuel-specific CO2 emission factor (MT
CO2/bbl).
(2) Calculate the total CO2 equivalent
emissions that would result from the
combustion or oxidation of fractionated
NGLs supplied less the quantity
received by other fractionators using
Equation NN–8 of this section.
(Eq. NN-8)
American Gas Association (AGA), the
American Society of Mechanical
Engineers (ASME), the American
Petroleum Institute (API), and the North
American Energy Standards Board
(NAESB).
(ii) Where no appropriate standard
method developed by a consensus-based
standards organization exists, industry
standard practices shall be followed.
(2) NGL fractionators and LDCs shall
base the minimum frequency of the
product quantity measurements, to be
summed to the annual quantity
reported, on the reporter’s standard
practices for commercial operations.
(i) For NGL fractionators the
minimum frequency of measurements
shall be the measurements taken at
custody transfers summed to the annual
reportable volume.
(ii) For natural gas the minimum
frequency of measurement shall be
based on the LDC’s standard
measurement schedules used for billing
purposes and summed to the annual
reportable volume.
(3) NGL fractionators shall use
measurement for NGLs at custody
tranfer meters or at such meters that are
used to determine the NGL product slate
delivered from the fractionation facility.
(4) If a NGL fractionator supplies a
product not listed in Table NN–1 of this
subpart that is a mixture or blend of two
PO 00000
CO 2 m = ∑ Fuelg
or more products listed in Tables NN–
1 and NN–2 of this subpart, the NGL
fractionator shall report the quantities of
the constituents of the mixtures or
blends separately.
(5) For an LDC using Equation NN–1
or NN–2 of this subpart, the point(s) of
measurement for the natural gas volume
supplied shall be the LDC city gate
meter(s).
(i) If the LDC makes its own quantity
measurements according to established
business practices, its own
measurements shall be used.
(ii) If the LDC does not make its own
quantity measurements according to
established business practices, it shall
use its delivering pipeline invoiced
measurements for natural gas deliveries
to the LDC city gate, used in
determining daily system sendout.
(6) An LDC using Equation NN–3 of
this subpart shall measure natural gas at
the custody transfer meters.
(7) An LDC using Equation NN–4 of
this subpart shall measure natural gas at
the customer meters. The reporter shall
consider the volume delivered through
a single particluar meter at a single
particular location as the volume
delivered to an individual end-user.
(8) An LDC using Equation NN–5 of
this subpart shall measure natural gas as
follows:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.170</MATH>
Where:
CO2 = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas delivered to LDC
customers not covered in paragraph
(b)(2) of this section (metric tons).
CO2i = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas received at the
city gate as calculated in paragraph (a)(1)
or (a)(2) of this section (metric tons).
CO2j = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas delivered to
transmission pipelines or other LDCs as
calculated in paragraph (b)(1) of this
section (metric tons).
CO2k = Annual CO2 mass emissions that
would result from the combustion or
oxidation of natural gas received by endusers that receive a supply equal to or
greater than 460,000 Mscf per year as
(Eq. NN-6)
ER30OC09.169</MATH>
(4) Calculate the total CO2 emissions
that would result from the complete
combustion or oxidation of the annual
ER30OC09.168</MATH>
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(i) Fuel1 shall be measured at the onsystem storage injection meters and/or
at the meters measuring natural gas to
be liquefied.
(ii) Fuel2 shall be measured at the
meters used for measuring on-system
storage withdrawals and/or LNG
vaporization injection. If Fuel2 is from a
source other than storage, the
appropriate meter shall be used to
measure the quantity.
(9) An LDC shall measure all natural
gas under the following standard
industry temperature and pressure
conditions: Cubic foot of gas at a
temperature of 60 degrees Fahrenheit
and at an absolute pressure of fourteen
and seventy-three hundredths (14.73)
pounds per square inch.
(b) Determination of higher heating
values (HHV).
(1) When a reporter uses the default
HHV provided in this section to
calculate Equation NN–1 of this subpart,
the appropriate value shall be taken
from Table NN–1 of this subpart.
(2) When a reporter uses a reporterspecific HHV to calculate Equation NN–
1 of this subpart, an appropriate
standard test published by a consensusbased standards organization shall be
used. Consensus-based standards
organizations include, but are not
limited to, the following: AGA and GPA.
(i) If an LDC makes its own HHV
measurements according to established
business practices, then its own
measurements shall be used.
(ii) If an LDC does not make its own
measurements according to established
business practices, it shall use its
delivering pipeline measurements.
(c) Determination of emission factor
(EF).
(1) When a reporter used the default
EF provided in this section to calculate
Equation NN–1 of this subpart, the
appropriate value shall be taken from
Table NN–1 of this subpart.
(2) When a reporter used the default
EF provided in this section to calculate
Equation NN–2, NN–3, NN–4, NN–5, or
NN–7 of this subpart, the appropriate
value shall be taken from Table NN–2 of
this subpart.
(3) When a reporter uses a reporterspecific EF, the reporter shall use an
appropriate standard method published
by a consensus-based standards
organization to conduct compositional
analysis necessary to determine
reporter-specific CO2 emission factors.
Consensus-based standards
organizations include, but are not
limited to, the following: AGA and GPA.
(d) Equipment Calibration.
(1) Equipment used to measure
quantities in Equations NN–1, NN–2,
and NN–5 of this subpart shall be
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calibrated prior to its first use for
reporting under this subpart, using a
suitable standard method published by
a consensus based standards
organization or according to the
equipment manufacturer’s directions.
(2) Equipment used to measure
quantities in Equations NN–1, NN–2,
and NN–5 of this subpart shall be
recalibrated at the frequency specified
by the standard method used or by the
manufacturer’s directions.
§ 98.405 Procedures for estimating
missing data.
(a) Whenever a quality-assured value
of the quantity of natural gas liquids or
natural gas supplied 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) Determination of quantity.
(1) NGL fractionators 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 fractionator 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, fractionators
may substitute estimates based on
contract quantities required to be
delivered under purchase or delivery
contracts with other parties.
(2) LDCs shall either substitute their
delivering pipeline metered deliveries at
the city gate or substitute nominations
and scheduled delivery quantities for
the period when metered values of
actual deliveries are not available.
(c) Determination of HHV and EF.
(1) Whenever an LDC that makes its
own HHV measurements according to
established business practices cannot
follow the quality assurance procedures
for developing a reporter-specific HHV,
as specified in § 98.404, during any
period for any reason, the reporter shall
use either its delivering pipeline
measurements or the default HHV
provided in Table NN–1 of this part for
that period.
(2) Whenever an LDC that does not
make its own HHV measurements
according to established business
practices or an NGL fractionator cannot
follow the quality assurance procedures
for developing a reporter-specific HHV,
as specified in § 98.404, during any
period for any reason, the reporter shall
use the default HHV provided in Table
NN–1 of this part for that period.
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56501
(3) Whenever a NGL fractionator
cannot follow the quality assurance
procedures for developing a reporterspecific HHV, as specified in § 98.404,
during any period for any reason, the
NGL fractionator shall use the default
HHV provided in Table NN–1 of this
part for that period.
(4) Whenever a reporter cannot follow
the quality assurance procedures for
developing a reporter-specific EF, as
specified in § 98.404, during any period
for any reason, the reporter shall use the
default EF provided in § 98.408 for that
period.
§ 98.406
Data reporting requirements.
(a) In addition to the information
required by § 98.3(c), the annual report
for each NGL fractionator covered by
this rule shall contain the following
information.
(1) Annual quantity (in barrels) of
each NGL product supplied to
downstream facilities in the following
product categories: ethane, propane,
normal butane, isobutane, and pentanes
plus.
(2) Annual quantity (in barrels) of
each NGL product received from other
NGL fractionators in the following
product categories: ethane, propane,
normal butane, isobutane, and pentanes
plus.
(3) Annual volumes in Mscf of natural
gas received for processing.
(4) Annual quantity (in barrels) of ygrade, bulk NGLs received from others
for fractionation.
(5) Annual quantity (in barrels) of
propane that the NGL fractionator
odorizes at the facility and delivers to
others.
(6) Annual CO2 emissions (metric
tons) that would result from the
complete combustion or oxidation of the
quantities in paragraphs (b)(1) and (b)(2)
of this section, calculated in accordance
with § 98.403(a) and (c)(1).
(7) Annual CO2 mass emissions
(metric tons) that would result from the
combustion or oxidation of fractionated
NGLs supplied less the quantity
received by other fractionators,
calculated in accordance with
§ 98.403(c)(2).
(8) The specific industry standard
used to measure each quantity reported
in paragraph (a)(1) of this section.
(9) If the LNG fractionator developed
reporter-specific EFs or HHVs, report
the following:
(i) The specific industry standard(s)
used to develop reporter-specific higher
heating value(s) and/or emission
factor(s), pursuant to § 98.404(b)(2) and
(c)(3).
(ii) The developed HHV(s).
(iii) The developed EF(s).
E:\FR\FM\30OCR2.SGM
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(b) In addition to the information
required by § 98.3(c), the annual report
for each LDC shall contain the following
information.
(1) Annual volume in Mscf of natural
gas received by the LDC at its city gate
stations for redelivery on the LDC’s
distribution system, including for use by
the LDC.
(2) Annual volume in Mscf of natural
gas placed into storage.
(3) Annual volume in Mscf of
vaporized liquefied natural gas (LNG)
produced at on-system vaporization
facilities for delivery on the distribution
system that is not accounted for in
paragraph (b)(1) of this section.
(4) Annual volume in Mscf of natural
gas withdrawn from on-system storage
(that is not delivered to the city gate) for
delivery on the distribution system.
(5) Annual volume in Mscf of natural
gas delivered directly to LDC systems
from producers or natural gas
processing plants from local production.
(6) Annual volume in Mscf of natural
gas delivered to downstream gas
transmission pipelines and other local
distribution companies.
(7) Annual volume in Mscf of natural
gas delivered by LDC to each meter
registering supply equal to or greater
than 460,000 Mcsf during the calendar
year.
(8) The total annual CO2 mass
emissions (metric tons) associated with
the volumes in paragraphs (b)(1)
through (b)(7) of this section, calculated
in accordance with § 98.403(a) and
(b)(1) through (b)(3).
(9) Annual CO2 emissions (metric
tons) that would result from the
complete combustion or oxidation of the
annual supply of natural gas to endusers registering less than 460,000 Mcsf,
calculated in accordance with
§ 98.403(b)(4).
(10) The specific industry standard
used to develop the volume reported in
paragraph (b)(1) of this section.
(11) If the LDC developed reporterspecific EFs or HHVs, report the
following:
(i) The specific industry standard(s)
used to develop reporter-specific higher
heating value(s) and/or emission
factor(s), pursuant to § 98.404 (b)(2) and
(c)(3).
(ii) The developed HHV(s).
(iii) The developed EF(s).
(12) The customer name, address, and
meter number of each meter reading
used to report in paragraph (b)(7) of this
section.
(i) If known, report the EIA
identification number of each LDC
customer.
(ii) [Reserved]
(13) The annual volume in Mscf 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 (Annual Report of Natural
Gas and Supplemental Gas Supply &
Disposition) and Instructions.
(i) Residential consumers.
(ii) Commercial consumers.
(iii) Industrial consumers.
(iv) Electricity generating facilities.
(c) Each reporter shall report the
number of days in the reporting year for
which substitute data procedures were
used for the following purpose:
(1) To measure quantity.
(2) To develop HHV(s).
(3) To develop EF(s).
§ 98.407
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 and
showing the calculations of the values
used for the missing 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)(6).
(e) Records relating to measured Btu
content or carbon content showing
specific industry standards used to
develop reporter-specific higher heating
values and emission factors.
(f) Records of such audits as required
by Sarbanes Oxley regulations on the
accuracy of measurements of volumes of
natural gas and NGLs delivered to
customers or on behalf of customers.
§ 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 TO SUBPART NN OF PART 98—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART
Fuel
Default high heating value factor
Natural Gas ..................................................................................
Propane ........................................................................................
Normal butane ..............................................................................
Ethane ..........................................................................................
Isobutane ......................................................................................
Pentanes plus ...............................................................................
1.027
3.836
4.326
3.082
3.974
4.620
MMBtu/Mscf ........................................................................
MMBtu/bbl ..........................................................................
MMBtu/bbl ..........................................................................
MMBtu/bbl ..........................................................................
MMBtu/bbl ..........................................................................
MMBtu/bbl ..........................................................................
Default CO2
emission
factor
(kg CO2/
MMBtu)
53.02
63.02
64.93
59.58
65.08
66.90
TABLE NN–2 TO SUBPART NN OF PART 98—LOOKUP DEFAULT VALUES FOR CALCULATION METHODOLOGY 2 OF THIS
SUBPART
Default CO2
emission
value
(MT CO2/
Unit)
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Fuel
Unit
Natural Gas ..................................................................................
Propane ........................................................................................
Normal butane ..............................................................................
Ethane ..........................................................................................
Isobutane ......................................................................................
Mscf ..............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
Barrel ............................................................................................
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TABLE NN–2 TO SUBPART NN OF PART 98—LOOKUP DEFAULT VALUES FOR CALCULATION METHODOLOGY 2 OF THIS
SUBPART—Continued
Default CO2
emission
value
(MT CO2/
Unit)
Fuel
Unit
Pentanes plus ...............................................................................
Barrel ............................................................................................
Reporting threshold.
Any supplier of industrial greenhouse
gases who meets the requirements of
§ 98.2(a)(4) must report GHG emissions.
sroberts on DSKD5P82C1PROD with RULES
§ 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
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(Eq. OO-1)
p =1
P = Mass of fluorinated GHG or nitrous oxide
produced annually.
Pp = Mass of fluorinated GHG or nitrous
oxide produced over the period ‘‘p’’.
(b) Calculate the total mass of each
fluorinated GHG or nitrous oxide
produced over the period ‘‘p’’ 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) Calculate the total mass of each
fluorinated GHG or nitrous oxide
transformed by using Equation OO–3 of
this section:
T = FT ∗ ET
(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).
ET = The fraction of the fluorinated GHG
or nitrous oxide fed into the
transformation process that is
transformed in the process (metric
tons).
(d) Calculate the total mass of each
fluorinated GHG destroyed by using
Equation OO–4 of this section:
Calculating GHG emissions.
(a) Calculate the total mass of each
fluorinated GHG or nitrous oxide
produced annually, except for amounts
that are captured solely to be shipped
n
∑ Pp
D = FD ∗ DE
(Eq. OO- 4)
Where:
D = Mass of fluorinated GHG destroyed
annually (metric tons).
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§ 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
using flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of one 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
using flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of one percent of full scale or
better. If the mass in paragraph (a) of
this section is measured by weighing
containers that include returned heels
as well as newly produced fluorinated
GHGs, the returned heels shall be
considered used fluorinated GHGs for
purposes of this paragraph (b) of this
section and § 98.413(b).
(c) The mass of fluorinated GHGs or
nitrous oxide fed into the
transformation process shall be
measured using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of one percent of
full scale or better.
(d) The fraction of the fluorinated
GHGs or nitrous oxide fed into the
transformation process that is actually
transformed shall be estimated
considering yield calculations or
quantities of unreacted fluorinated
GHGs or nitrous oxide permanently
removed from the process and
recovered, destroyed, or emitted.
(e) The mass of fluorinated GHG or
nitrous oxide sent to another facility for
transformation shall be measured using
flowmeters, weigh scales, or a
combination of volumetric and density
measurements with an accuracy and
precision of one percent of full scale or
better.
E:\FR\FM\30OCR2.SGM
30OCR2
er30oc09.174</MATH>
§ 98.411
P=
er30oc09.173</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 GHG
includes the manufacture of a
fluorinated GHG for use in a process
that will result in its transformation
either at or outside of the production
facility. Producing a fluorinated GHG
also includes the creation of a
fluorinated GHG (with the exception of
HFC–23) that is captured and shipped
off site for any reason, including
destruction. Producing a fluorinated
GHG does not include the reuse or
recycling of a fluorinated GHG, the
creation of HFC–23 during the
production of HCFC–22, or the creation
of by-products that are released or
destroyed at the production facility.
(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.
er30oc09.172</MATH>
§ 98.410
FD = Mass of fluorinated GHG fed into the
destruction device annually (metric
tons).
DE = Destruction efficiency of the destruction
device (fraction).
er30oc09.171</MATH>
off site for destruction, by using
Equation OO–1 of this section:
Subpart OO—Suppliers of Industrial
Greenhouse Gases
0.309078
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(f) The mass of fluorinated GHG sent
to another facility for destruction shall
be measured using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of one 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 estimated
considering current or previous
representative concentration
measurements and other relevant
process information. 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) You must estimate the share of the
mass of fluorinated GHGs in paragraph
(f) of this section that is comprised of
fluorinated GHGs that are not included
in the mass produced in § 98.413(a)
because they are removed from the
production process as by-products or
other wastes.
(h) The mass of fluorinated GHGs fed
into the destruction device shall be
measured using flowmeters, weigh
scales, or a combination of volumetric
and density measurements with an
accuracy and precision of one 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
concentrations of fluorinated GHG being
destroyed shall be estimated
considering current or previous
representative concentration
measurements and other relevant
process information. This concentration
(mass fraction) shall be multiplied by
the mass measurement to obtain the
mass of the fluorinated GHG destroyed.
(i) Very small quantities of fluorinated
GHGs that are difficult to measure
because they are entrained in other
media such as destroyed filters and
destroyed sample containers are exempt
from paragraphs (f) and (h) of this
section.
(j) You must estimate the share of the
mass of fluorinated GHGs in paragraph
(h) of this section that is comprised of
fluorinated GHGs that are not included
in the mass produced in § 98.413(a)
because they are removed from the
production process as by-products or
other wastes.
(k) For purposes of Equation OO–4 of
this subpart, the destruction efficiency
can 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
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17:39 Oct 29, 2009
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provided by the manufacturer of the
destruction device.
(l) 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.
(m) Calibrate all flow meters, weigh
scales, and combinations of volumetric
and density measures that are used to
measure or calculate quantities that are
to be reported under this subpart prior
to the first year for which GHG
emissions are reported under this part.
Calibrations performed prior to the
effective date of this rule satisfy this
requirement. Recalibrate all flow meters,
weigh scales, and combinations of
volumetric and density measures at the
minimum frequency specified by the
manufacturer. Use NIST-traceable
standards and suitable methods
published by a consensus standards
organization (e.g., ASTM, ASME, ISO,
or others).
§ 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 paragraph (b) of this
section.
(b) For each missing value of the mass
produced, fed into the production
process (for used material being
reclaimed), fed into the transformation
process, 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 where
such a measurement is 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. Where a
secondary mass measurement is not
available, the substitute value of the
parameter shall be an estimate based on
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Fmt 4701
Sfmt 4700
a related parameter. For example, if a
flowmeter measuring the mass fed into
a destruction device is rendered
inoperable, then the mass fed into the
destruction device may be estimated
using the production rate and the
previously observed relationship
between the production rate and the
mass flow rate into the destruction
device.
§ 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:
(1) Mass in metric tons of each
fluorinated GHG or nitrous oxide
produced at that facility by process,
except for amounts that are captured
solely to be shipped off site for
destruction.
(2) Mass in metric tons of each
fluorinated GHG or nitrous oxide
transformed at that facility, by process.
(3) Mass in metric tons of each
fluorinated GHG destroyed at that
facility, except fluorinated GHGs not
included in the calculation of mass
produced in § 98.413(a) because they are
removed from the production process as
by-products or other wastes. Quantities
to be reported under this paragraph
(a)(3) of this section could include, for
example, quantities that are returned to
the facility for reclamation but are found
to be irretrievably contaminated and are
therefore destroyed.
(4) Mass in metric tons of each
fluorinated GHG that is destroyed at that
facility except GHGs not included in the
calculation of mass produced in
§ 98.413(a) because they are removed
from the production process as
byproducts or other wastes.
(5) Total mass in metric tons of each
fluorinated GHG or nitrous oxide sent to
another facility for transformation.
(6) Total mass in metric tons of each
fluorinated GHG sent to another facility
for destruction, except fluorinated GHGs
that are not included in the mass
produced in § 98.413(a) because they are
removed from the production process as
by-products or other wastes. Quantities
to be reported under this paragraph
(a)(6) could include, for example,
fluorinated GHGs that are returned to
the facility for reclamation but are found
to be irretrievably contaminated and are
therefore sent to another facility for
destruction.
(7) Total mass in metric tons of each
fluorinated GHG that is sent to another
facility for destruction and that is not
included in the mass produced in
§ 98.413(a) because it is removed from
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the production process as a byproduct
or other waste.
(8) Total mass in metric tons of each
reactant fed into the F–GHG or nitrous
oxide production process, by process.
(9) Total mass in metric tons of the
reactants, by-products, and other wastes
permanently removed from the F–GHG
or nitrous oxide production process, by
process.
(10) For transformation processes that
do not produce an F–GHG or nitrous
oxide, mass in metric tons of any
fluorinated GHG or nitrous oxide fed
into the transformation process, by
process.
(11) Mass in metric tons of each
fluorinated GHG fed into the destruction
device.
(12) Mass in metric tons of each
fluorinated GHG or nitrous oxide that is
measured coming out of the production
process, by process.
(13) Mass in metric tons of each used
fluorinated GHGs or nitrous oxide
added back into the production process
(e.g., for reclamation), including
returned heels in containers that are
weighed to measure the mass in
§ 98.414(a), by process.
(14) Names and addresses of facilities
to which any nitrous oxide or
fluorinated GHGs were sent for
transformation, and the quantities
(metric tons) of nitrous oxide and of
each fluorinated GHG that were sent to
each for transformation.
(15) 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.
(16) 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.
(b) A fluorinated GHG production
facility or importer that destroys
fluorinated GHGs shall submit a onetime report containing the following
information:
(1) Destruction efficiency (DE) of each
destruction unit.
(2) 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
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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.
(c) A bulk importer of fluorinated
GHGs or nitrous oxide shall submit an
annual report that summarizes their
imports at the corporate level, except for
shipments including less than 250
metric tons of CO2e, transshipments,
and heels that meet the conditions set
forth at § 98.417(e). The report shall
contain the following information for
each import:
(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) Total mass in metric tons of each
fluorinated GHG destroyed by the
importer.
(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
transformation, and the quantities
(metric tons) of nitrous oxide and of
each fluorinated GHG that were sold or
transferred to each facility for
transformation.
(10) 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.
(d) A bulk exporter of fluorinated
GHGs or nitrous oxide shall submit an
annual report that summarizes their
exports at the corporate level, except for
shipments including less than 250
metric tons of CO2e, 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.
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56505
(2) Names and addresses of the
exporter and the recipient of the
exports.
(3) Exporter’s Employee Identification
Number.
(4) Commodity code of the fluorinated
GHGs and nitrous oxide shipped.
(5) Date on which, and the port from
which, fluorinated GHGs and nitrous
oxide were exported from the United
States or its territories.
(6) Country to which the fluorinated
GHGs or nitrous oxide were exported.
(e) By April 1, 2011, a fluorinated
GHG production facility shall submit a
one-time report describing the following
information:
(1) The method(s) by which the
producer in practice measures the mass
of fluorinated GHGs produced,
including the instrumentation used
(Coriolis flowmeter, other flowmeter,
weigh scale, etc.) and its accuracy and
precision.
(2) The method(s) by which the
producer in practice estimates the mass
of fluorinated GHGs fed into the
transformation process, including the
instrumentation used (Coriolis
flowmeter, other flowmeter, weigh
scale, etc.) and its accuracy and
precision.
(3) The method(s) by which the
producer in practice estimates the
fraction of fluorinated GHGs fed into the
transformation process that is actually
transformed, and the estimated
precision and accuracy of this estimate.
(4) The method(s) by which the
producer in practice estimates the
masses of fluorinated GHGs fed into the
destruction device, including the
method(s) used to estimate the
concentration of the fluorinated GHGs
in the destroyed material, and the
estimated precision and accuracy of this
estimate.
(5) The estimated percent efficiency of
each production process for the
fluorinated GHG produced.
§ 98.417
Records that must be retained.
(a) In addition to the data required by
§ 98.3(g), the fluorinated GHG
production facility shall retain the
following records:
(1) Dated records of the data used to
estimate the data reported under
§ 98.416.
(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
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Definitions.
All terms used in this subpart have
the same meaning given in the Clean Air
Act and subpart A of this part.
§ 98.420
(a) The carbon dioxide (CO2) supplier
source category consists of the
following:
(1) Facilities with production process
units that capture a CO2 stream for
purposes of supplying CO2 for
commercial applications or that capture
and maintain custody of a CO2 stream
in order to sequester or otherwise inject
it underground. Capture refers to the
initial separation and removal of CO2
from a manufacturing process or any
other process.
(2) Facilities with CO2 production
wells that extract or produce a CO2
stream for purposes of supplying CO2
for commercial applications or that
extract and maintain custody of a CO2
stream in order to sequester or
otherwise inject it underground.
(3) Importers or exporters of bulk CO2.
(b) This source category is focused on
upstream supply. It does not cover:
(1) Storage of CO2 above ground or in
geologic formations.
(2) Use of CO2 in enhanced oil and gas
recovery.
(3) Transportation or distribution of
CO2.
(4) Purification, compression, or
processing of CO2.
(5) On-site use of CO2 captured on
site.
(c) This source category does not
include CO2 imported or exported in
equipment, such as fire extinguishers.
CO 2,u =
Where:
CO2,u = Annual mass of CO2 (metric tons)
through flow meter u.
CCO2,p,u = Quarterly CO2 concentration
measurement in flow for flow meter u in
quarter p (wt. %CO2).
Qp,u = Quarterly mass flow rate measurement
for flow meter u in quarter p (metric
tons).
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Any supplier of CO2 who meets the
requirements of § 98.2(a)(4) of subpart A
of this part must report the mass of CO2
captured, extracted, imported, or
exported.
§ 98.422
GHGs to report.
(a) Mass of CO2 captured from each
production process unit.
(b) Mass of CO2 extracted from each
CO2 production wells.
(c) Mass of CO2 imported.
(d) Mass of CO2 exported.
§ 98.423
Calculating CO2 supply.
(a) Calculate the annual mass of CO2
captured, extracted, imported, or
exported through each flow meter in
accordance with the procedures
specified in either paragraph (a)(1) or
(a)(2) of this section. If multiple flow
meters are used, you shall calculate the
annual mass of CO2 for all flow meters
according to the procedures specified in
paragraph (a)(3) of this section.
(1) For each mass flow meter, you
shall calculate quarterly the mass of CO2
in a CO2 stream in metric tons, prior to
any subsequent purification, processing,
or compressing, by multiplying the mass
flow by the composition data, according
to Equation PP–1 of this section. Mass
flow and composition data
measurements shall be made in
accordance with § 98.424 of this
subpart.
(Eq. PP-1)
p =1
(2) For each volumetric flow meter,
you shall calculate quarterly the mass of
CO2 in a CO2 stream in metric tons,
prior to any subsequent purification,
processing, or compressing, by
multiplying the volumetric flow by the
concentration and density data,
according to Equation PP–2 of this
section. Volumetric flow, concentration
and density data measurements shall be
made in accordance with § 98.424 of
this section.
4
∑ Q p ∗ D p ∗ CCO2, p
(Eq. PP- 2)
p =1
Qp = Quarterly volumetric flow rate
measurement for flow meter u in quarter
p (standard cubic meters).
Dp = Quarterly CO2 stream density
measurement for flow meter u in quarter
p (metric tons per standard cubic meter).
p = Quarter of the year.
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4
∑ Q p,u ∗ CCO2, p,u
p = Quarter of the year.
u = Flow meter.
CO 2,u =
Where:
CO2,u = Annual mass of CO2 (metric tons)
through flow meter u.
CCO2,p = Quarterly CO2 concentration
measurement in flow for flow meter u in
quarter p (wt. % CO2).
Definition of the source category.
§ 98.421
Frm 00248
Fmt 4701
Sfmt 4700
u = Flow meter.
(3) To aggregate data, sum the mass of
CO2 for all flow meters in accordance
with Equation PP–3 of this section.
E:\FR\FM\30OCR2.SGM
30OCR2
er30oc09.176</MATH>
§ 98.418
Subpart PP—Suppliers of Carbon
Dioxide
er30oc09.175</MATH>
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 (e).
(c) In addition to the data required by
§ 98.3(g), the 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 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 that is not
reported under § 98.416(c) 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.
(4) Be recovered and included in a
future shipment.
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
p =1
Where:
CO2 = Annual mass of CO2 (metric tons)
through all flow meters.
CO2,u = Annual mass of CO2 (metric tons)
through flow meter u.
u = Flow meter.
(b) Importers or exporters that import
or export CO2 in containers shall
calculate the total mass of CO2 imported
or exported in metric tons, prior to any
subsequent purification, processing, or
compressing, based on summing the
mass in each CO2 container using weigh
bills, scales, or load cells according to
Equation PP–4 of this section.
CO 2 =
I
∑Q
(Eq. PP- 4)
p =1
Where:
CO2 = Annual mass of CO2 (metric tons).
Q = Annual mass in all CO2 containers
imported or exported during the
reporting year (metric tons).
sroberts on DSKD5P82C1PROD with RULES
§ 98.424 Monitoring and QA/QC
requirements.
(a) Determination of quantity.
(1) Reporters that have a mass flow
meter or volumetric flow meter installed
to measure the flow of a CO2 stream
shall base calculations in § 98.423 of
this subpart on the installed mass flow
or volumetric flow meters.
(2) Reporters that do not have a mass
flow meter or volumetric flow meter
installed to measure the flow of the CO2
stream shall base calculations in
§ 98.423 of this subpart on the flow of
gas transferred off site using a mass flow
meter or a volumetric flow meter
located at the point of off-site transfer.
(3) Importers or exporters that import
or export CO2 in containers shall
measure the mass in each CO2 container
using weigh bills, scales, or load cells
and sum the mass in all containers
imported or exported during the
reporting year.
(4) All flow meters, scales, and load
cells used to measure quantities that are
reported in § 98.423 of this subpart shall
be operated and calibrated according to
the following procedure:
(i) You shall use an appropriate
standard method published by a
consensus-based standards organization
if such a method exists. Consensusbased standards organizations include,
but are not limited to, the following:
ASTM International, the American
National Standards Institute (ANSI), the
American Gas Association (AGA), the
American Society of Mechanical
Engineers (ASME), the American
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
Petroleum Institute (API), and the North
American Energy Standards Board
(NAESB).
(ii) Where no appropriate standard
method developed by a consensus-based
standards organization exists, you shall
follow industry standard practices.
(iii) You must ensure that any flow
meter calibrations performed are NIST
traceable.
(5) Reporters using Equation PP–2 of
this subpart shall measure the density of
the CO2 stream on a quarterly basis in
order to calculate the mass of the CO2
stream according to the following
procedure:
(i) You shall use an appropriate
standard method published by a
consensus-based standards organization
to measure density if such a method
exists. Consensus-based standards
organizations include, but are not
limited to, the following: ASTM
International, the American National
Standards Institute (ANSI), the
American Gas Association (AGA), the
American Society of Mechanical
Engineers (ASME), the American
Petroleum Institute (API), and the North
American Energy Standards Board
(NAESB).
(ii) Where no appropriate standard
method developed by a consensus-based
standards organization exists, you shall
follow industry standard practices.
(b) Determination of concentration.
(1) Reporters using Equation PP–1 or
PP–2 of this subpart shall sample the
CO2 stream on a quarterly basis to
determine the composition of the CO2
stream.
(2) Methods to measure the
composition of the CO2 stream must
conform to applicable chemical
analytical standards. Acceptable
methods include U.S. Food and Drug
Administration food-grade
specifications for CO2 (see 21 CFR
184.1250) and ASTM standard E1747–
95 (Reapproved 2005) Standard Guide
for Purity of Carbon Dioxide Used in
Supercritical Fluid Applications
(incorporated by reference, see § 98.7 of
subpart A of this part).
§ 98.425 Procedures for estimating
missing data.
(a) Whenever the quality assurance
procedures in § 98.424(a) of this subpart
cannot be followed to measure quarterly
mass flow or volumetric flow of CO2,
the most appropriate of the following
missing data procedures shall be
followed:
(1) A quarterly CO2 mass flow or
volumetric flow value that is missing
may be substituted with a quarterly
value measured during another quarter
of the current reporting year.
PO 00000
Frm 00249
Fmt 4701
Sfmt 4700
(2) A quarterly CO2 mass flow or
volumetric flow value that is missing
may be substituted with a quarterly
value measured during the same quarter
from the past reporting year.
(3) If a mass or volumetric flow meter
is installed to measure the CO2 stream,
you may substitute data from a mass or
volumetric flow meter measuring the
CO2 stream transferred for any period
during which the installed meter is
inoperable.
(4) The mass or volumetric flow used
for purposes of product tracking and
billing according to the reporter’s
established procedures may be
substituted for any period during which
measurement equipment is inoperable.
(b) Whenever the quality assurance
procedures in § 98.424(b) of this subpart
cannot be followed to determine
concentration of the CO2 stream, the
most appropriate of the following
missing data procudures shall be
followed:
(1) A quarterly concentration value
that is missing may be substituted with
a quarterly value measured during
another quarter of the current reporting
year.
(2) A quarterly concentration value
that is missing may be substituted with
a quarterly value measured during the
same quarter from the previous
reporting year.
(3) The concentration used for
purposes of product tracking and billing
according to the reporter’s established
procedures may be substituted for any
quarterly value.
(c) Missing data on density of the CO2
stream shall be substituted with
quarterly or annual average values from
the previous calendar year.
§ 98.426
Data reporting requirements.
In addition to the information
required by § 98.3(c) of subpart A of this
part, the annual report shall contain the
following information, as applicable:
(a) If you use Equation PP–1 of this
subpart, report the following
information for each mass flow meter:
(1) Annual mass in metric tons of CO2.
(2) Quarterly mass flow of CO2.
(3) Quarterly concentration of the CO2
stream.
(4) The standard used to measure CO2
concentration.
(b) If you use Equation PP–2 of this
subpart, report the following
information for each volumetric flow
meter:
(1) Annual mass in metric tons of CO2.
(2) Quarterly volumetric flow of CO2.
(3) Quarterly concentration of the CO2
stream.
(4) Quarterly density of the CO2
stream.
E:\FR\FM\30OCR2.SGM
30OCR2
er30oc09.178</MATH>
(Eq. PP-3)
er30oc09.177</MATH>
U
CO 2 = ∑ CO 2,u
56507
56508
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(5) The method used to measure
density.
(6) The standard used to measure CO2
concentration.
(c) If you use Equation PP–3 of this
subpart, report the annual CO2 mass in
metric tons from all flow meters.
(d) If you use Equation PP–4 of this
subpart, report at the corporate level the
annual mass of CO2 in metric tons in all
CO2 containers that are imported or
exported.
(e) Each reporter shall report the
following information:
(1) The type of equipment used to
measure the total flow of the CO2 stream
or the total mass in CO2 containers.
(2) The standard used to operate and
calibrate the equipment reported in
(e)(1) of this section.
(3) The number of days in the
reporting year for which substitute data
procedures were used for the following
purpose:
(i) To measure quantity.
(ii) To measure concentration.
(iii) To measure density.
(f) Report the aggregated annual
quantity of CO2 in metric tons that is
transferred to each of the following end
use applications, if known:
(1) Food and beverage.
(2) Industrial and municipal water/
wastewater treatment.
(3) Metal fabrication, including
welding and cutting.
(4) Greenhouse uses for plant growth.
(5) Fumigants (e.g., grain storage) and
herbicides.
(6) Pulp and paper.
(7) Cleaning and solvent use.
(8) Fire fighting.
(9) Transportation and storage of
explosives.
(10) Enhanced oil and natural gas
recovery.
(11) Long-term storage (sequestration).
(12) Research and development.
(13) Other.
(g) Each production process unit that
captures a CO2 stream for purposes of
supplying CO2 for commercial
applications or in order to sequester or
otherwise inject it underground when
custody of the CO2 is maintained shall
report the percentage of that stream, if
any, that is biomass-based during the
reporting year.
sroberts on DSKD5P82C1PROD with RULES
§ 98.427
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 (c) of this
section, as applicable.
(a) The owner or operator of a facility
containing production process units
must retain quarterly records of
captured or transferred CO2 streams and
composition.
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(b) The owner or operator of a CO2
production well facility must maintain
quarterly records of the mass flow or
volumetric flow of the extracted or
transferred CO2 stream and
concentration and density if volumetric
flow meters are used.
(c) Importers or exporters of CO2 must
retain annual records of the mass flow,
volumetric flow, and mass of CO2
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 1033—[AMENDED]
21. The authority citation for part
1033 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
22. Section 1033.205 is amended by
revising paragraph (d)(8) to read as
follows:
■
§ 1033.205 Applying for a certificate of
conformity.
*
*
*
*
*
(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) Report measured CO2, N2O, and
CH4 as described in § 1033.235. Small
manufacturers/remanufacturers may
omit reporting N2O and CH4.
*
*
*
*
*
■ 23. Section 1033.235 is amended by
adding paragraph (i) to read as follows:
§ 1033.235 Emission testing required for
certification.
*
*
*
*
*
(i) Measure CO2 with each test.
Measure CH4 with each low-hour
certification test using the procedures
specified in 40 CFR part 1065 starting in
the 2012 model year. Also measure N2O
with each low-hour certification test
using the procedures specified in 40
CFR part 1065 for any engine family that
depends on NOx aftertreatment to meet
emission standards. Small
manufacturers/remanufacturers may
omit measurement of N2O and CH4. 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/bhp–
hr.
PO 00000
Frm 00250
Fmt 4701
Sfmt 4700
(2) Round N2O to the nearest 0.001 g/
bhp–hr.
(3) Round CH4 to the nearest 0.001g/
bhp–hr.
Subpart F—[Amended]
24. Section 1033.501 is amended by
revising paragraph (a) introductory text
to read as follows:
■
§ 1033.501
General provisions.
(a) Except as specified in this subpart,
use the equipment and procedures for
compression-ignition engines in 40 CFR
part 1065 to determine whether your
locomotives meet the duty-cycle
emission standards in § 1033.101. Use
the applicable duty cycles specified in
this subpart. Measure emissions of all
the pollutants we regulate in § 1033.101
plus CO2. Measure N2O, and CH4 as
described in § 1033.235. The general test
procedure is the procedure specified in
40 CFR part 1065 for steady-state
discrete-mode cycles. However, if you
use the optional ramped modal cycle in
§ 1033.520, follow the procedures for
ramped modal testing in 40 CFR part
1065. The following exceptions from the
1065 procedures apply:
*
*
*
*
*
Subpart J—[Amended]
25. 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 1039—[AMENDED]
26. The authority citation for part
1039 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
27. Section 1039.205 is amended by
revising paragraph (r) to read as follows:
■
§ 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
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
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) Report measured CO2, N2O, and
CH4 as described in § 1039.235. Smallvolume engine manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 28. 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) Measure CO2 and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065 in the 2011 and 2012 model years,
respectively. Also measure N2O with
each low-hour certification test using
the procedures specified in 40 CFR part
1065 starting in the 2013 model year for
any engine family that depends on NOx
aftertreatment to meet emission
standards. Small-volume engine
manufacturers may omit measurement
of N2O and CH4. 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 F—[Amended]
29. Section 1039.501 is amended by
revising paragraph (a) to read as follows:
■
sroberts on DSKD5P82C1PROD with RULES
§ 1039.501
test?
How do I run a valid emission
(a) Use the equipment and procedures
for compression-ignition engines in 40
CFR part 1065 to determine whether
engines meet the duty-cycle emission
standards in subpart B of this part.
Measure the emissions of all the exhaust
constituents subject to emissions
standards as specified in 40 CFR part
1065. Measure CO2, N2O, and CH4 as
described in § 1039.235. Use the
applicable duty cycles specified in
§§ 1039.505 and 1039.510.
*
*
*
*
*
Subpart I—[Amended]
30. Section 1039.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
■
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17:39 Oct 29, 2009
Jkt 220001
§ 1039.805 What symbols, acronyms, and
abbreviations does this part use?
*
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
(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.
Subpart F—[Amended]
34. Section 1042.501 is amended by
revising paragraph (a) to read as follows:
■
PART 1042—[AMENDED]
31. The authority citation for part
1042 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
32. Section 1042.205 is amended by
revising paragraph (r) to read as follows:
■
§ 1042.205
56509
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) Report measured CO2, N2O, and
CH4 as described in § 1042.235. Smallvolume engine manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 33. Section 1042.235 is amended by
adding paragraph (g) to read as follows:
§ 1042.501
test?
How do I run a valid emission
(a) Use the equipment and procedures
for compression-ignition engines in 40
CFR part 1065 to determine whether
Category 1 and Category 2 engines meet
the duty-cycle emission standards in
§ 1042.101(a). Measure the emissions of
all exhaust constituents subject to
emissions standards as specified in 40
CFR part 1065. Measure CO2, N2O, and
CH4 as described in § 1042.235. Use the
applicable duty cycles specified in
§ 1042.505.
*
*
*
*
*
Subpart J—[Amended]
35. 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.
*
*
*
*
*
*
*
*
*
*
CH4 methane.
*
*
*
*
*
N2O nitrous oxide.
*
*
*
*
*
§ 1042.235 Emission testing required for a
certificate of conformity.
PART 1045—[AMENDED]
*
■
*
*
*
*
(g) Measure CO2 with each low-hour
certification test using the procedures
specified in 40 CFR part 1065 starting in
the 2011 model year. Also measure CH4
from Category 1 and Category 2 engines
with each low-hour certification test
using the procedures specified in 40
CFR part 1065 starting in the 2012
model year. Measure N2O from Category
1 and Category 2 engines with each lowhour certification test using the
procedures specified in 40 CFR part
1065 for any engine family that depends
on NOx aftertreatment to meet emission
standards. Small-volume engine
manufacturers may omit measurement
of N2O and CH4. 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:
PO 00000
Frm 00251
Fmt 4701
Sfmt 4700
36. The authority citation for part
1045 continues to read as follows:
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
37. 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.
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
(2) Report measured CO2, N2O, and
CH4 as described in § 1045.235. Smallvolume engine manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 38. 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 and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065 starting in the 2011 and 2012
model years, respectively. Also measure
N2O with each low-hour certification
test using the procedures specified in 40
CFR part 1065 starting in the 2013
model year for any engine family that
depends on NOX aftertreatment to meet
emission standards. Small-volume
engine manufacturers may omit
measurement of N2O and CH4. 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 0.001 g/
kW-hr.
Subpart F—[Amended]
39. Section 1045.501 is amended by
revising paragraph (b) to read as follows:
■
§ 1045.501
test?
How do I run a valid emission
sroberts on DSKD5P82C1PROD with RULES
*
*
*
*
*
(b) General requirements. Use the
equipment and procedures for sparkignition engines in 40 CFR part 1065 to
determine whether engines meet the
duty-cycle emission standards in
§§ 1045.103 and 1045.105. Measure the
emissions of all exhaust constituents
subject to emissions standards as
specified in 40 CFR part 1065. Measure
CO2, N2O, and CH4 as described in
§ 1045.235. Use the applicable duty
cycles specified in § 1045.505. Section
1045.515 describes the supplemental
procedures for evaluating whether
engines meet the not-to-exceed emission
standards in § 1045.107.
*
*
*
*
*
Subpart C—[Amended]
41. Section 1048.205 is amended by
revising paragraph (s) to read as follows:
■
§ 1048.205 What must I include in my
application?
*
*
*
*
*
(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) Report measured CO2, N2O, and
CH4 as described in § 1048.235. Smallvolume engine manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 42. 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) Measure CO2 and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065 starting in the 2011 and 2012
model years, respectively. Also measure
N2O with each low-hour certification
test using the procedures specified in 40
CFR part 1065 starting in the 2013
model year for any engine family that
depends on NOx aftertreatment to meet
emission standards. Small-volume
engine manufacturers may omit
measurement of N2O and CH4. 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.
Subpart F—[Amended]
43. Section 1048.501 is amended by
revising paragraph (a) to read as follows:
■
§ 1048.501
test?
40. The authority citation for part
1048 continues to read as follows:
(a) Use the equipment and procedures
for spark-ignition engines in 40 CFR
part 1065 to determine whether engines
meet the duty-cycle emission standards
Authority: 42 U.S.C. 7401–7671q.
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Subpart I—[Amended]
44. Section 1048.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
■
§ 1048.805 What symbols, acronyms, and
abbreviations does this part use?
*
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CH4 methane.
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PART 1051—[AMENDED]
45. The authority citation for part
1051 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
46. Section 1051.205 is amended by
revising paragraph (p) to read as
follows:
■
§ 1051.205 What must I include in my
application?
*
*
*
*
*
(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) Report measured CO2, N2O, and
CH4 as described in § 1051.235. Smallvolume manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 47. Section 1051.235 is amended by
adding paragraph (i) to read as follows:
§ 1051.235 What emission testing must I
perform for my application for a certificate
of conformity?
*
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*
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*
PART 1048—[AMENDED]
■
in § 1048.101(a) and (b). Measure the
emissions of all the pollutants we
regulate in § 1048.101 using the
sampling procedures specified in 40
CFR part 1065. Measure CO2, N2O, and
CH4 as described in § 1048.235. Use the
applicable duty cycles specified in
§§ 1048.505 and 1048.510.
*
*
*
*
*
*
*
*
*
(i) Measure CO2 and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065 starting in the 2011 and 2012
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model years, respectively. Also measure
N2O with each low-hour certification
test using the analytical equipment and
procedures specified in 40 CFR part
1065 starting in the 2013 model year for
any engine family that depends on NOx
aftertreatment to meet emission
standards. Small-volume manufacturers
may omit measurement of N2O and CH4;
other manufacturers may provide
appropriate data and/or information and
omit measurement of N2O and CH4 as
described in 40 CFR 1065.5. 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 0.001 g/
kW-hr or 0.001 g/km, as appropriate.
approve in advance testing in a
governed configuration. We will only
approve testing in a governed
configuration if you can show that the
governor is permanently installed on all
production vehicles and is unlikely to
be removed in use. With respect to
engine-speed governors, test
motorcycles and ATVs in their governed
configuration. Run the test engine, with
all emission-control systems operating,
long enough to stabilize emission levels;
you may consider emission levels stable
without measurement if you accumulate
12 hours of operation.
*
*
*
*
*
Subpart I—[Amended]
49. Section 1051.805 is amended by
adding the abbreviations CH4 and N2O
in alphanumeric order to read as
follows:
■
Subpart F—[Amended]
§ 1051.805 What symbols, acronyms, and
abbreviations does this part use?
48. Section 1051.501 is amended by
revising paragraphs (a) and (b) to read
as follows:
*
■
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(a) Snowmobiles. For snowmobiles,
use the equipment and procedures for
spark-ignition engines in 40 CFR part
1065 to determine whether your
snowmobiles meet the duty-cycle
emission standards in § 1051.103.
Measure the emissions of all the
pollutants we regulate in § 1051.103.
Measure CO2, N2O, and CH4 as
described in § 1051.235. Use the duty
cycle specified in § 1051.505.
(b) Motorcycles and ATVs. For
motorcycles and ATVs, use the
equipment, procedures, and duty cycle
in 40 CFR part 86, subpart F, to
determine whether your vehicles meet
the exhaust emission standards in
§ 1051.105 or § 1051.107. Measure the
emissions of all the pollutants we
regulate in § 1051.105 or § 1051.107.
Measure CO2, N2O, and CH4 as
described in § 1051.235. If we allow you
to certify ATVs based on engine testing,
use the equipment, procedures, and
duty cycle described or referenced in
the section that allows engine testing.
For motorcycles with engine
displacement at or below 169 cc and all
ATVs, use the driving schedule in
paragraph (c) of appendix I to 40 CFR
part 86. For all other motorcycles, use
the driving schedule in paragraph (b) of
Appendix I to part 86. With respect to
vehicle-speed governors, test
motorcycles and ATVs in their
ungoverned configuration, unless we
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*
*
*
§ 1054.235 What exhaust emission testing
must I perform for my application for a
certificate of conformity?
*
*
*
*
*
(g) Measure CO2 and CH4 with each
low-hour certification test using the
procedures specified in 40 CFR part
1065 starting in the 2011 and 2012
model years, respectively. Also measure
N2O with each low-hour certification
test using the procedures specified in 40
CFR part 1065 starting in the 2013
model year for any engine family that
depends on NOx aftertreatment to meet
emission standards. Small-volume
engine manufacturers may omit
measurement of N2O and CH4. 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.
Subpart F—[Amended]
*
§ 1051.501 What procedures must I use to
test my vehicles or engines?
*
*
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CH4 methane.
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N2O nitrous oxide.
*
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*
*
53. Section 1054.501 is amended by
revising paragraph (b)(1) to read as
follows:
■
§ 1054.501
test?
PART 1054—[AMENDED]
How do I run a valid emission
§ 1054.205 What must I include in my
application?
*
*
*
*
(b) * * *
(1) Measure the emissions of all
exhaust constituents subject to
emissions standards as specified in
§ 1054.505 and 40 CFR part 1065.
Measure CO2, N2O, and CH4 as
described in § 1054.235. See § 1054.650
for special provisions that apply for
variable-speed engines (including
engines shipped without governors).
*
*
*
*
*
*
PART 1065—[AMENDED]
50. The authority citation for part
1054 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart C—[Amended]
51. Section 1054.205 is amended by
revising paragraph (p) to read as
follows:
■
*
*
*
*
(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) Report measured CO2, N2O, and
CH4 as described in § 1054.235. Smallvolume engine manufacturers may omit
reporting N2O and CH4.
*
*
*
*
*
■ 52. Section 1054.235 is amended by
adding paragraph (g) to read as follows:
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54. The authority citation for part
1065 continues to read as follows:
■
Authority: 42 U.S.C. 7401–7671q.
Subpart A—[Amended]
55. Section 1065.5 is amended by
revising paragraph (a)(3) to read as
follows:
■
§ 1065.5 Overview of this part 1065 and its
relationship to the standard-setting part.
(a) * * *
(3) Which exhaust constituents do I
need to measure? Measure all exhaust
constituents that are subject to emission
standards, any other exhaust
constituents needed for calculating
emission rates, and any additional
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exhaust constituents as specified in the
standard-setting part. Alternatively, you
may omit the measurement of N2O and
CH4 for an engine, provided it is not
subject to an N2O or CH4 emission
standard. If you omit the measurement
of N2O and CH4, you must provide other
information and/or data that will give us
a reasonable basis for estimating the
engine’s emission rates.
*
*
*
*
*
Subpart C—[Amended]
56. The center heading ‘‘NOx
Measurements’’ preceding § 1065.270 is
revised to read as follows:
■
NOX and N2O Measurements
57. A new § 1065.275 is added under
the center heading ‘‘NOx and N2O
Measurements’’ to read as follows:
■
§ 1065.275
N2O measurement devices.
(a) General component requirements.
We recommend that you use an analyzer
that meets the specifications in Table 1
of § 1065.205. Note that your system
must meet the linearity verification in
§ 1065.307.
(b) Instrument types. You may use any
of the following analyzers to measure
N2O:
(1) Nondispersive infra-red (NDIR)
analyzer. 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 0.0% (that is, no bias high
and no bias low), regardless of the
uncompensated signal’s bias.
(2) Fourier transform infra-red (FTIR)
analyzer. You may use an FTIR 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
0.0% (that is, no bias high and no bias
low), regardless of the uncompensated
signal’s bias. Use appropriate analytical
procedures for interpretation of infrared
spectra. For example, EPA Test Method
320 is considered a valid method for
spectral interpretation (see https://www.
epa.gov/ttn/emc/methods/
method320.html).
(3) Photoacoustic analyzer. You may
use a photoacoustic analyzer that has
compensation algorithms that are
functions of other gaseous
measurements. The target value for any
compensation algorithm is 0.0% (that is,
no bias high and no bias low), regardless
of the uncompensated signal’s bias. Use
an optical wheel configuration that
gives analytical priority to measurement
of the least stable components in the
sample. Select a sample integration time
of at least 5 seconds. Take into account
sample chamber and sample line
volumes when determining flush times
for your instrument.
(4) Gas chromatograph analyzer. You
may use a gas chromatograph with an
electron-capture detector (GC–ECD) to
measure N2O concentrations of diluted
exhaust for batch sampling.
(i) You may use a packed or porous
layer open tubular (PLOT) column
phase of suitable polarity and length to
achieve adequate resolution of the N2O
peak for analysis. Examples of
acceptable columns are a PLOT column
consisting of bonded polystyrenedivinylbenzene or a Porapack Q packed
column. Take the column temperature
profile and carrier gas selection into
consideration when setting up your
method to achieve adequate N2O peak
resolution.
(ii) Use good engineering judgment to
zero your instrument and correct for
drift. You do not need to follow the
specific procedures in § 1065.530 and
§ 1065.550(b) that would otherwise
apply. For example, you may perform a
span gas measurement before and after
sample analysis without zeroing. Use
the average area counts of the pre-span
and post-span measurements to generate
a response factor (area counts/span gas
concentration), which you then
multiply by the area counts from your
sample to generate the sample
concentration.
(c) Interference validation. Perform
interference validation for NDIR, FTIR,
and photoacoustic analyzers using the
procedures of § 1065.375. Interference
validation is not required for GC–ECD.
Certain interference gases can positively
interfere with NDIR, FTIR, and
photoacoustic analyzers by causing a
response similar to N2O. When running
the interference verification for these
analyzers, use interference gases as
follows:
(1) The interference gases for NDIR
analyzers are CO, CO2, H2O, CH4 and
SO2. Note that interference species, with
the exception of H2O, are dependent on
the N2O infrared absorption band
chosen by the instrument manufacturer
and should be determined dently for
each analyzer.
(2) Use good engineering judgment to
determine interference gases for FTIR.
Note that interference species, with the
exception of H2O, are dependent on the
N2O infrared absorption band chosen by
the instrument manufacturer and should
be determined independently for each
analyzer.
(3) The interference gases for
photoacoustic analyzers are CO, CO2,
and H2O.
Subpart D—[Amended]
58. Section 1065.303 is revised to read
as follows:
■
§ 1065.303 Summary of required
calibration and verifications
The following table summarizes the
required and recommended calibrations
and verifications described in this
subpart and indicates when these have
to be performed:
TABLE 1 OF § 1065.303–SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS
Type of calibration or verification
Minimum frequency a
§ 1065.305: Accuracy, repeatability and noise .............................
Accuracy: Not required, but recommended for initial installation.
Repeatability: Not required, but recommended for initial installation.
Noise: Not required, but recommended for initial installation.
Speed: Upon initial installation, within 370 days before testing and after major
maintenance.
Torque: Upon initial installation, within 370 days before testing and after major
maintenance.
Electrical power: Upon initial installation, within 370 days before testing and
after major maintenance.
Clean gas and diluted exhaust flows: Upon initial installation, within 370 days
before testing and after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance.
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§ 1065.307: Linearity ....................................................................
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56513
TABLE 1 OF § 1065.303–SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS—Continued
Minimum frequency a
Type of calibration or verification
§ 1065.308: Continuous gas analyzer system response and updating-recording verification—for gas analyzers not continuously compensated for other gas species.
§ 1065.309: Continuous gas analyzer system-response and updating-recording verification—for gas analyzers continuously
compensated for other gas species.
§ 1065.310: Torque .......................................................................
§ 1065.315: Pressure, temperature, dewpoint ..............................
§ 1065.320: Fuel flow ...................................................................
§ 1065.325: Intake flow .................................................................
§ 1065.330: Exhaust flow .............................................................
§ 1065.340: Diluted exhaust flow (CVS) .......................................
§ 1065.341: CVS and batch sampler verification b .......................
§ 1065.345: Vacuum leak .............................................................
§ 1065.350: CO2 NDIR H2O interference .....................................
§ 1065.355: CO NDIR CO2 and H2O interference .......................
§ 1065.360: FID calibration, THC FID optimization, and THC
FID verification..
§ 1065.362: Raw exhaust FID O2 interference .............................
§ 1065.365: Nonmethane cutter penetration ................................
§ 1065.370:
§ 1065.372:
§ 1065.375:
§ 1065.376:
§ 1065.378:
CLD CO2 and H2O quench .......................................
NDUV HC and H2O interference ..............................
N2O analyzer interference ........................................
Chiller NO2 penetration .............................................
NO2-to-NO converter conversion ..............................
§ 1065.390: PM balance and weighing ........................................
§ 1065.395: Inertial PM balance and weighing ............................
Raw exhaust flow: Upon initial installation, within 185 days before testing and
after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance.
Gas analyzers: Upon initial installation, within 35 days before testing and after
major maintenance.
FTIR and photoacoustic analyzers: Upon initial installation, within 370 days
before testing and after major maintenance.
GC–ECD: Upon initial installation and after major maintenance.
PM balance: Upon initial installation, within 370 days before testing and after
major maintenance.
Stand-alone pressure and temperature: Upon initial installation, within 370
days before testing and after major maintenance.
Upon initial installation or after system modification that would effect response.
Upon initial installation or after system modification that would effect response.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation, within 35 days before testing, and after major maintenance.
Before each laboratory test according to subpart F of this part and before
each field test according to subpart J of this part.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Calibrate all FID analyzers: upon initial installation and after major maintenance.
Optimize and determine CH4 response for THC FID analyzers:
upon initial installation and after major maintenance.
Verify CH4 response for THC FID analyzers: upon initial installation, within
185 days before testing, and after major maintenance.
For all FID analyzers: upon initial installation, and after major maintenance.
For THC FID analyzers: upon initial installation, after major maintenance, and
after FID optimization according to § 1065.360.
Upon initial installation, within 185 days before testing, and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation and after major maintenance.
Upon initial installation, within 35 days before testing, and after major maintenance.
Independent verification: upon initial installation, within 370 days before testing, and after major maintenance.
Zero, span, and reference sample verifications: within 12 hours of weighing,
and after major maintenance.
Independent verification: upon initial installation, within 370 days before testing, and after major maintenance.
Other verifications: upon initial installation and after major maintenance.
a Perform calibrations and verifications more frequently, according to measurement system manufacturer instructions and good engineering
judgment.
b The CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or
oxygen of the intake air, fuel, and diluted exhaust.
b The CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or
oxygen of the intake air, fuel, and diluted exhaust.
59. Section 1065.307 is amended by
revising paragraph (c)(6) to read as
follows:
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■
§ 1065.307
Linearity verification.
*
*
*
*
*
(c) * * *
(6) For all measured quantities, use
instrument manufacturer
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recommendations and good engineering
judgment to select reference values, yrefi,
that cover a range of values that you
expect would prevent extrapolation
beyond these values during emission
testing. We recommend selecting a zero
reference signal as one of the reference
values of the linearity verification. For
stand-alone pressure and temperature
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linearity verifications and for GC–ECD
linearity verifications, we recommend at
least three reference values. For all other
linearity verifications select at least ten
reference values.
*
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*
*
*
■ 60. Section 1065.365 is amended by
revising paragraphs (d), (e), and (f) to
read as follows:
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Nonmethane cutter penetration
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(d) Procedure for a FID calibrated
with the NMC. The method described in
this paragraph (d) is recommended over
the procedures specified in paragraphs
(e) and (f) of this section. If your FID
arrangement is such that a FID is always
calibrated to measure CH4 with the
NMC, then span that FID with the NMC
using a CH4 span gas, set the product of
that FID’s CH4 response factor and CH4
penetration fraction, RFPFCH4[NMC–FID],
equal to 1.0 for all emission
calculations, and determine its
combined ethane (C2H6) response factor
and penetration fraction,
RFPFC2H6[NMC–FID] as follows:
(1) Select CH4 and C2H6 analytical gas
mixtures and ensure that both mixtures
meet the specifications of § 1065.750.
Select a CH4 concentration that you
would use for spanning the FID during
emission testing and select a C2H6
concentration that is typical of the peak
NMHC concentration expected at the
hydrocarbon standard or equal to the
THC analyzer’s span value.
(2) Start, operate, and optimize the
nonmethane cutter according to the
manufacturer’s instructions, including
any temperature optimization.
(3) Confirm that the FID analyzer
meets all the specifications of
§ 1065.360.
(4) Start and operate the FID analyzer
according to the manufacturer’s
instructions.
(5) Zero and span the FID with the
nonmethane cutter as you would during
emission testing. Span the FID through
the cutter by using CH4 span gas.
(6) Introduce the C2H6 analytical gas
mixture upstream of the nonmethane
cutter. Use good engineering judgment
to address the effect of hydrocarbon
contamination if your point of
introduction is vastly different from the
point of zero/span gas introduction.
(7) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the
nonmethane cutter and to account for
the analyzer’s response.
(8) While the analyzer measures a
stable concentration, record 30 seconds
of sampled data. Calculate the
arithmetic mean of these data points.
(9) Divide the mean C2H6
concentration by the reference
concentration of C2H6, converted to a C1
basis. The result is the C2H6 combined
response factor and penetration fraction,
RFPFC2H6[NMC–FID]. Use this combined
response factor and penetration fraction
and the product of the CH4 response
factor and CH4 penetration fraction,
RFPFCH4[NMC–FID], set to 1.0 in emission
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calculations according to
§ 1065.660(b)(2)(i), § 1065.660(c)(1)(i), or
§ 1065.665, as applicable.
(e) Procedure for a FID calibrated with
propane, bypassing the NMC. If you use
a single FID for THC and CH4
determination with an NMC that is
calibrated with propane, C3H8, by
bypassing the NMC, determine its
penetration fractions, PFC2H6[NMC–FID]
and PFCH4[NMC–FID], as follows:
(1) Select CH4 and C2H6 analytical gas
mixtures and ensure that both mixtures
meet the specifications of § 1065.750.
Select a CH4 concentration that you
would use for spanning the FID during
emission testing and select a C2H6
concentration that is typical of the peak
NMHC concentration expected at the
hydrocarbon standard or equal to the
THC analyzer’s span value.
(2) Start and operate the nonmethane
cutter according to the manufacturer’s
instructions, including any temperature
optimization.
(3) Confirm that the FID analyzer
meets all the specifications of
§ 1065.360.
(4) Start and operate the FID analyzer
according to the manufacturer’s
instructions.
(5) Zero and span the FID as you
would during emission testing. Span the
FID by bypassing the cutter and by
using C3H8 span gas.
(6) Introduce the C2H6 analytical gas
mixture upstream of the nonmethane
cutter. Use good engineering judgment
to address the effect of hydrocarbon
contamination if your point of
introduction is vastly different from the
point of zero/span gas introduction.
(7) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the
nonmethane cutter and to account for
the analyzer’s response.
(8) While the analyzer measures a
stable concentration, record 30 seconds
of sampled data. Calculate the
arithmetic mean of these data points.
(9) Reroute the flow path to bypass
the nonmethane cutter, introduce the
C2H6 analytical gas mixture, and repeat
the steps in paragraph (e)(7) through
(e)(8) of this section.
(10) Divide the mean C2H6
concentration measured through the
nonmethane cutter by the mean C2H6
concentration measured after bypassing
the nonmethane cutter. The result is the
C2H6 penetration fraction,
PFC2H6[NMC–FID]. Use this penetration
fraction according to
§ 1065.660(b)(2)(ii), § 1065.660(c)(1)(ii),
or § 1065.665, as applicable.
(11) Repeat the steps in paragraphs
(e)(6) through (e)(10) of this section, but
with the CH4 analytical gas mixture
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instead of C2H6. The result will be the
CH4 penetration fraction, PFCH4[NMC–FID].
Use this penetration fraction according
to § 1065.660(b)(2)(ii),
§ 1065.660(c)(1)(ii), or § 1065.665, as
applicable.
(f) Procedure for a FID calibrated with
methane, bypassing the NMC. If you use
a FID with an NMC that is calibrated
with methane, CH4, by bypassing the
NMC, determine its combined ethane
(C2H6) response factor and penetration
fraction, RFPFC2H6[NMC–FID], as well as
its CH4 penetration fraction,
PFCH4[NMC–FID], as follows:
(1) Select CH4 and C2H6 analytical gas
mixtures and ensure that both mixtures
meet the specifications of § 1065.750.
Select a CH4 concentration that you
would use for spanning the FID during
emission testing and select a C2H6
concentration that is typical of the peak
NMHC concentration expected at the
hydrocarbon standard or equal to the
THC analyzer’s span value.
(2) Start and operate the nonmethane
cutter according to the manufacturer’s
instructions, including any temperature
optimization.
(3) Confirm that the FID analyzer
meets all the specifications of
§ 1065.360.
(4) Start and operate the FID analyzer
according to the manufacturer’s
instructions.
(5) Zero and span the FID as you
would during emission testing. Span the
FID by bypassing the cutter and by
using CH4 span gas. Note that you must
span the FID on a C1 basis. For example,
if your span gas has a methane reference
value of 100 μmol/mol, the correct FID
response to that span gas is 100 μmol/
mol because there is one carbon atom
per CH4 molecule.
(6) Introduce the C2H6 analytical gas
mixture upstream of the nonmethane
cutter. Use good engineering judgment
to address the effect of hydrocarbon
contamination if your point of
introduction is vastly different from the
point of zero/span gas introduction.
(7) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the
nonmethane cutter and to account for
the analyzer’s response.
(8) While the analyzer measures a
stable concentration, record 30 seconds
of sampled data. Calculate the
arithmetic mean of these data points.
(9) Divide the mean C2H6
concentration by the reference
concentration of C2H6, converted to a C1
basis. The result is the C2H6 combined
response factor and penetration fraction,
RFPFC2H6[NMC–FID]. Use this combined
response factor and penetration fraction
according to § 1065.660(b)(2)(iii),
E:\FR\FM\30OCR2.SGM
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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
§ 1065.660(c)(1)(iii), or § 1065.665, as
applicable.
(10) Introduce the CH4 analytical gas
mixture upstream of the nonmethane
cutter. Use good engineering judgment
to address the effect of hydrocarbon
contamination if your point of
introduction is vastly different from the
point of zero/span gas introduction.
(11) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the
nonmethane cutter and to account for
the analyzer’s response.
(12) While the analyzer measures a
stable concentration, record 30 seconds
of sampled data. Calculate the
arithmetic mean of these data points.
(13) Reroute the flow path to bypass
the nonmethane cutter, introduce the
CH4 analytical gas mixture, and repeat
the steps in paragraphs (e)(11) and (12)
of this section.
(14) Divide the mean CH4
concentration measured through the
nonmethane cutter by the mean CH4
concentration measured after bypassing
the nonmethane cutter. The result is the
CH4 penetration fraction, PFCH4[NMC–FID].
Use this penetration fraction according
to § 1065.660(b)(2)(iii),
§ 1065.660(c)(1)(iii), or § 1065.665, as
applicable.
■ 61. The center heading ‘‘NOX
MEASUREMENTS’’ preceding
§ 1065.370 is revised to read as follows:
NOX and N2O Measurements
62. A new § 1065.375 is added under
the center header ‘‘NOX and N2O
Measurements’’ to read as follows:
■
sroberts on DSKD5P82C1PROD with RULES
§ 1065.375
analyzers.
Interference verification for N2O
(a) Scope and frequency. See
§ 1065.275 to determine whether you
need to verify the amount of
interference after initial analyzer
installation and after major
maintenance.
(b) Measurement principles.
Interference gasses can positively
interfere with certain analyzers by
causing a response similar to N2O. If the
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. Analyzers
must have combined interference that is
within (0.0 ± 1.0) μmol/mol. We
strongly recommend a lower
interference that is within (0.0 ± 0.5)
μmol/mol.
(d) Procedure. Perform the
interference verification as follows:
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
(1) Start, operate, zero, and span the
N2O analyzer as you would before an
emission test. If the sample is passed
through a dryer during emission testing,
you may run this verification test with
the dryer if it meets the requirements of
§ 1065.342. Operate the dryer at the
same conditions as you will for an
emission test. You may also run this
verification test without the sample
dryer.
(2) Create a humidified test gas by
bubbling a multi component span gas
that incorporates the target interference
species and meets the specifications in
§ 1065.750 through distilled water in a
sealed vessel. If the sample is not passed
through a dryer during emission testing,
control the vessel temperature to
generate an H2O level at least as high as
the maximum expected during emission
testing. If the sample is passed through
a dryer during emission testing, control
the vessel temperature to generate an
H2O level at least as high as the level
determined in § 1065.145(e)(2) for that
dryer. Use interference span gas
concentrations that are at least as high
as the maximum expected during
testing.
(3) Introduce the humidified
interference test gas into the sample
system. You may introduce it
downstream of any sample dryer, if one
is used during testing.
(4) If the sample is not passed through
a dryer during this verification test,
measure the water mole fraction, xH2O,
of the humidified interference test gas as
close as possible to the inlet of the
analyzer. For example, measure
dewpoint, Tdew, and absolute pressure,
ptotal, to calculate xH2O. Verify that the
water content meets the requirement in
paragraph (d)(2) of this section. If the
sample is passed through a dryer during
this verification test, you must verify
that the water content of the humidified
test gas downstream of the vessel meets
the requirement in paragraph (d)(2) of
this section based on either direct
measurement of the water content (e.g.,
dewpoint and pressure) or an estimate
based on the vessel pressure and
temperature. Use good engineering
judgment to estimate the water content.
For example, you may use previous
direct measurements of water content to
verify the vessel’s level of saturation.
(5) If a sample dryer is not used in this
verification test, use good engineering
judgment to prevent condensation in the
transfer lines, fittings, or valves from the
point where xH2O is measured to the
analyzer. We recommend that you
design your system so that the wall
temperatures in the transfer lines,
fittings, and valves from the point where
xH2O is measured to the analyzer are at
PO 00000
Frm 00257
Fmt 4701
Sfmt 4700
56515
least 5 °C above the local sample gas
dewpoint.
(6) Allow time for the analyzer
response to stabilize. Stabilization time
may include time to purge the transfer
line and to account for analyzer
response.
(7) While the analyzer measures the
sample’s concentration, record its
output for 30 seconds. Calculate the
arithmetic mean of this data.
(8) The analyzer meets the
interference verification if the result of
paragraph (d)(7) of this section meets
the tolerance in paragraph (c) of this
section.
(9) You may also run interference
procedures separately for individual
interference gases. If the interference gas
levels used are higher than the
maximum levels expected during
testing, you may scale down each
observed interference value by
multiplying the observed interference
by the ratio of the maximum expected
concentration value to the actual value
used during this procedure. You may
run separate interference concentrations
of H2O (down to 0.025 mol/mol H2O
content) that are lower than the
maximum levels expected during
testing, but you must scale up the
observed H2O interference by
multiplying the observed interference
by the ratio of the maximum expected
H2O concentration value to the actual
value used during this procedure. The
sum of the scaled interference values
must meet the tolerance specified in
paragraph (c) of this section.
Subpart F—[Amended]
63. Section 1065.550 is amended by
revising paragraphs (b) introductory text
and (b)(1), adding and reserving
paragraph (b)(3), and adding paragraph
(b)(4) to read as follows:
■
§ 1065.550 Gas analyzer range validation,
drift validation, and drift correction.
*
*
*
*
*
(b) Drift validation and drift
correction. Calculate two sets of brakespecific emission results for each test
interval. Calculate one set using the data
before drift correction and calculate the
other set after correcting all the data for
drift according to § 1065.672. Use the
two sets of brake-specific emission
results to validate the duty cycle for
drift as follows:
(1) The duty cycle is validated for
drift if you satisfy one of the following
criteria:
(i) For each test interval of the duty
cycle and for each measured exhaust
constituent, the difference between the
uncorrected and the corrected brake-
E:\FR\FM\30OCR2.SGM
30OCR2
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
xTHC[THC-FID]cor = xTHC[THC-FID]uncor − xTHC[THC-FID] init
Example:
xTHCuncor = 150.3 μmol/mol
xTHCinit = 1.1 μmol/mol
xTHCcor = 150.3¥1.1
xTHCcor = 149.2 μmol/mol
(2) For the NMHC determination
described in paragraph (b) of this
section, correct xTHC[THC–FID] for initial
HC contamination using Eq. 1065.660–
1. You may correct xTHC[NMC–FID] for
initial contamination of the CH4 sample
train using Eq. 1065.660–1, substituting
in CH4 concentrations for THC.
sroberts on DSKD5P82C1PROD with RULES
xNMHC =
xTHC[THC-FID]cor − xTHC[NMC-FID]cor ⋅ RFCH4[THC-FID]
1 − RFPFC2H6[NMC-FID] ⋅ RFCH4[THC-FID]
Where:
xNMHC = concentration of NMHC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
as measured by the THC FID during
sampling while bypassing the NMC.
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
corrected, as measured by the NMC FID
during sampling through the NMC.
VerDate Nov<24>2008
17:39 Oct 29, 2009
(3) For the CH4 determination
described in paragraph (c) of this
section, you may correct xTHC[NMC–FID]
for initial contamination of the CH4
sample train using Eq. 1065.660–1,
substituting in CH4 concentrations for
THC.
(b) NMHC determination. Use one of
the following to determine NMHC
concentration, xNMHC:
(1) If you do not measure CH4, you
may determine NMHC concentrations as
described in § 1065.650(c)(1)(vi).
Jkt 220001
RFCH4[THC–FID] = response factor of THC FID
to CH4, according to § 1065.360(d).
RFPFC2H6[NMC–FID] = nonmethane cutter
combined ethane response factor and
penetration fraction, according to
§ 1065.365(d).
Example:
xTHC[THC–FID]cor = 150.3 μmol/mol
xTHC[NMC–FID]cor = 20.5 μmol/mol
RFPFC2H6[NMC–FID] = 0.019
RFCH4[THC–FID] = 1.05
PO 00000
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Fmt 4701
Sfmt 4700
Subpart G—[Amended]
64. Section 1065.601 is amended by
revising paragraph (a)(1) to read as
follows:
■
§ 1065.601
Overview.
(a) * * *
(1) Use the signals recorded before,
during, and after an emission test to
calculate brake-specific emissions of
each measured exhaust constituent.
*
*
*
*
*
65. Section 1065.660 is amended by
revising paragraphs (a), (b) introductory
text, (b)(1), (b)(2), and (b)(3)
introductory text, and adding paragraph
(c) to read as follows:
■
§ 1065.660 THC, NMHC, and CH4
determination.
(a) THC determination and THC/CH4
initial contamination corrections. (1) If
we require you to determine THC
emissions, calculate xTHC[THC–FID]cor
using the initial THC contamination
concentration xTHC[THC¥FID]init from
§ 1065.520 as follows:
Eq. 1065.660-1
(2) For nonmethane cutters, calculate
xNMHC using the nonmethane cutter’s
penetration fractions (PF) of CH4 and
C2H6 from § 1065.365, and using the HC
contamination and dry-to-wet corrected
THC concentration xTHC[THC–FID]cor as
determined in paragraph (a) of this
section.
(i) Use the following equation for
penetration fractions determined using
an NMC configuration as outlined in
§ 1065.365(d):
Eq. 1065.660-2
xNMHC =
150.3 − 20.5 ⋅1.05
1 − 0.019 ⋅1.05
xNMHC = 131.4 μmol/mol
(ii) For penetration fractions
determined using an NMC configuration
as outlined in section § 1065.365(e), use
the following equation:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.181</MATH>
This calculation uses drift-corrected
mass (or mass rate) values from each test
interval and sets any negative mass (or
mass rate) values to zero before
calculating the composite brake-specific
emission values over the entire duty
cycle. This requirement also applies for
CO2, whether or not an emission
standard applies for CO2. Where no
emission standard applies for CO2, the
difference must be within ±4% of the
uncorrected value. See paragraph (b)(3)
of this section for exhaust constituents
other than CO2 for which no emission
standard applies.
*
*
*
*
*
(3) [Reserved]
(4) The provisions of paragraph (b)(3)
of this section apply for measurement of
pollutants other than CO2 for which no
emission standard applies. You may use
measurements that do not meet the drift
validation criteria specified in
paragraph (b)(1) of this section. For
example, this allowance may be
appropriate for measuring and reporting
very low concentrations of CH4 and N2O
as long as no emission standard applies
for these compounds.
ER30OC09.180</MATH>
specific emission values over the test
interval is within ±4% of the
uncorrected value or applicable
emission standard, whichever is greater.
This requirement also applies for CO2,
whether or not an emission standard
applies for CO2. Where no emission
standard applies for CO2, the difference
must be within ±4% of the uncorrected
value. See paragraph (b)(4) of this
section for exhaust constituents other
than CO2 for which no emission
standard applies.
(ii) For the entire duty cycle and for
each regulated pollutant, the difference
between the uncorrected and corrected
composite brake-specific emission
values over the entire duty cycle is
within ±4% of the uncorrected value or
the applicable emission standard,
whichever is greater. Note that for
purposes of drift validation using
composite brake-specific emission
values over the entire duty cycle, leave
unaltered any negative emission results
over a given test interval (i.e., do not set
them to zero). A third calculation of
composite brake-specific emission
values is required for final reporting.
ER30OC09.179</MATH>
56516
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
xTHC[THC-FID]cor ⋅ PFCH4[NMC-FID]cor − xTHC[NMC-FID]
(iii) For penetration fractions
determined using an NMC configuration
as outlined in § 1065.365(f), use the
following equation:
Eq. 1065.660-4
xCH4 =
RFPFC2H6[NMC–FID] = the combined ethane
response factor and penetration fraction
of the nonmethane cutter, according to
§ 1065.365(d).
RFCH4[THC–FID] = response factor of THC FID
to CH4, according to § 1065.360(d).
Example:
xTHC[NMC–FID]cor = 10.4 μmol/mol
xTHC[THC–FID]cor = 150.3 μmol/mol
RFPFC2H6[NMC–FID] = 0.019
xTHC[NMC-FID]cor − xTHC[THC-FID]cor ⋅ PFC2H6[NMC-FID]
(
RFCH4[THC-FID] ⋅ PFCH4[NMC-FID] − PFC2H6[NMC-FID]
Where:
xCH4 = concentration of CH4.
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
corrected, as measured by the NMC FID
during sampling through the NMC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
Jkt 220001
)
as measured by the THC FID during
sampling while bypassing the NMC.
PFC2H6[NMC–FID] = nonmethane cutter ethane
penetration fraction, according to
§ 1065.365(e).
RFCH4[THC–FID] = response factor of THC FID
to CH4, according to § 1065.360(d).
PO 00000
Frm 00259
Fmt 4701
Sfmt 4700
*
*
Eq. 1065.660-6
RFCH4[THC–FID] = 1.05
xCH4 =
10.4 − 150.3 ⋅ 0.019
1 − 0.019 ⋅1.05
xCH4 = 7.69 μmol/mol
(ii) For penetration fractions determined
using an NMC configuration as outlined in
§ 1065.365(e), use the following equation:
Eq. 1065.660-7
PFCH4[NMC–FID] = nonmethane cutter CH4
penetration fraction, according to
§ 1065.365(e).
Example:
xTHC[NMC–FID]cor = 10.4 μmol/mol
xTHC[THC–FID]cor = 150.3 μmol/mol
PFC2H6[NMC–FID] = 0.020
RFCH4[THC–FID] = 1.05
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.188</MATH>
1 − RFPFC2H6[NMC-FID] ⋅ RFCH4[THC-FID]
*
ER30OC09.187</MATH>
(3) For a gas chromatograph, calculate
xNMHC using the THC analyzer’s response
factor (RF) for CH4, from § 1065.360, and the
HC contamination and dry-to-wet corrected
initial THC concentration xTHC[THC–FID]cor as
*
(c) CH4 determination. Use one of the
following methods to determine CH4
concentration, xCH4:
(1) For nonmethane cutters, calculate xCH4
using the nonmethane cutter’s penetration
fractions (PF) of CH4 and C2H6 from
§ 1065.365, using the dry-to-wet corrected
CH4 concentration xTHC[NMC–FID]cor as
determined in paragraph (a) of this section
and optionally using the CH4 contamination
correction under paragraph (a) of this section.
(i) Use the following equation for
penetration fractions determined using an
NMC configuration as outlined in
§ 1065.365(d):
ER30OC09.186</MATH>
xNMHC = 132.5 μmol/mol
*
ER30OC09.185</MATH>
150.3 ⋅ 0.990 − 20.5 ⋅ 0.980
0.990 − 0.019 ⋅ 0.980
determined in paragraph (a) of this section as
follows:
ER30OC09.184</MATH>
xNMHC =
xTHC[NMC-FID]cor − xTHC[THC-FID]cor ⋅ RFPFC2H6[NMC-FID]
Where:
xCH4 = concentration of CH4.
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
corrected, as measured by the NMC FID
during sampling through the NMC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
as measured by the THC FID during
sampling while bypassing the NMC.
17:39 Oct 29, 2009
RFCH4[THC–FID] = response factor of THC FID
to CH4, according to § 1065.360(d).
Example:
xTHC[THC–FID]cor = 150.3 μmol/mol
PFCH4[NMC–FID] = 0.990
xTHC[NMC–FID]cor = 20.5 μmol/mol
RFPFC2H6[NMC–FID] = 0.019
RFCH4[THC–FID] = 0.980
150.3 ⋅ 0.990 − 20.5
0.990 − 0.020
xNMHC = 132.3 μmol/mol
PFCH4[NMC-FID] − RFPFC2H6[NMC-FID] ⋅ RFCH4[THC-FID]
xCH4 =
sroberts on DSKD5P82C1PROD with RULES
xNMHC =
xTHC[THC-FID]cor ⋅ PFCH4[NMC-FID] − xTHC[NMC-FID]cor ⋅ RFCH4[THC-FID]
Where:
xNMHC = concentration of NMHC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
as measured by the THC FID during
sampling while bypassing the NMC.
PFCH4[NMC–FID] = nonmethane cutter CH4
penetration fraction, according to
§ 1065.365(f).
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
corrected, as measured by the THC FID
during sampling through the NMC.
RFPFC2H6[NMC–FID] = nonmethane cutter CH4
combined ethane response factor and
penetration fraction, according to
§ 1065.365(f).
VerDate Nov<24>2008
corrected, as measured by the THC FID
during sampling through the NMC.
PFC2H6[NMC–FID] = nonmethane cutter ethane
penetration fraction, according to
§ 1065.365(e).
Example:
xTHC[THC–FID]cor = 150.3 μmol/mol
PFCH4[NMC–FID] = 0.990
xTHC[NMC–FID]cor = 20.5 μmol/mol
PFC2H6[NMC–FID] = 0.020
ER30OC09.183</MATH>
Where:
xNMHC = concentration of NMHC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
as measured by the THC FID during
sampling while bypassing the NMC.
PFCH4[NMC–FID] = nonmethane cutter CH4
penetration fraction, according to
§ 1065.365(e).
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
xNMHC =
Eq. 1065.660-3
PFCH4[NMC-FID] − PFC2H6[NMC-FID]
ER30OC09.182</MATH>
xNMHC =
56517
56518
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
xCH4 = 7.25 μmol/mol
PFCH4[NMC–FID] = 0.990
xCH4
(iii) For penetration fractions determined
using an NMC configuration as outlined in
§ 1065.365(f), use the following equation:
10.4 − 150.3 ⋅ 0.020
=
1.05 ⋅ (0.990 − 0.020)
xCH4 =
xTHC[NMC-FID]cor − xTHC[THC-FID]cor ⋅ RFPFC2H6[NMC-FID]
Eq. 1065.660-8
PFCH4[NMC-FID] − RFPFC2H6[NMC-FID] ⋅ RFCH4[THC-FID]
Where:
xCH4 = concentration of CH4.
xTHC[NMC–FID]cor = concentration of THC, HC
contamination (optional) and dry-to-wet
corrected, as measured by the NMC FID
during sampling through the NMC.
xTHC[THC–FID]cor = concentration of THC, HC
contamination and dry-to-wet corrected,
as measured by the THC FID during
sampling while bypassing the NMC.
RFPFC2H6[NMC–FID] = the combined ethane
response factor and penetration fraction
of the nonmethane cutter, according to
§ 1065.365(f).
PFCH4[NMC–FID] = nonmethane cutter CH4
penetration fraction, according to
§ 1065.365(f).
RFCH4[THC–FID] = response factor of THC FID
to CH4, according to § 1065.360(d).
Example:
xTHC[NMC–FID]cor = 10.4 μmol/mol
xTHC[THC–FID]cor = 150.3 μmol/mol
RFPFC2H6[NMC–FID] = 0.019
PFCH4[NMC–FID] = 0.990
RFCH4[THC–FID] = 1.05
xCH4 =
10.4 − 150.3 ⋅ 0.019
0.990 − 0.019 ⋅1.05
xCH4 = 7.78 μmol/mol
(2) For a gas chromatograph, xCH4 is the
actual dry-to-wet corrected CH4
concentration as measured by the analyzer.
Subpart H—[Amended]
66. 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 ....................................................................
N2O2 ...................................................................
≤ 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 ...............................................
do not require these levels of purity to be NIST-traceable.
N2O limit applies only if the standard-setting part requires you to report N2O.
*
*
*
*
(3) * * *
(xi) N2O, balance purified synthetic
air.
*
*
*
*
*
■ 67. Section 1065.1001 is amended by
revising the definition for ‘‘Oxides of
nitrogen’’ to read as follows:
§ 1065.1001
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.
*
*
*
*
*
■ 68. Section 1065.1005 is amended by
revising paragraphs (b), (f)(2), and (g) to
read as follows:
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
§ 1065.1005 Symbols, abbreviations,
acronyms, and units of measure.
*
*
*
*
*
(b) Symbols for chemical species. This
part uses the following symbols for
chemical species and exhaust
constituents:
Symbol
Species
Ar ...................
C ....................
CH4 ................
C2H6 ...............
C3H8 ...............
C4H10 ..............
C5H12 ..............
CO ..................
CO2 ................
H ....................
H2 ...................
H2O ................
He ..................
85Kr ................
N2 ...................
PO 00000
Frm 00260
argon.
carbon.
methane.
ethane.
propane.
butane.
pentane.
carbon monoxide.
carbon dioxide.
atomic hydrogen.
molecular hydrogen.
water.
helium.
krypton 85.
molecular nitrogen.
Fmt 4701
Sfmt 4700
Symbol
Species
NMHC ............
NMHCE ..........
nonmethane hydrocarbon.
nonmethane hydrocarbon
equivalent.
nitric oxide.
nitrogen dioxide.
oxides of nitrogen.
nitrous oxide.
nonoxygenated hydrocarbon.
molecular oxygen.
oxygenated hydrocarbon.
polonium 210.
particulate mass.
sulfur.
sulfur dioxide.
total hydrocarbon.
zirconium dioxide.
NO ..................
NO2 ................
NOX ................
N2O ................
NOTHC ..........
O2 ...................
OHC ...............
210Po ..............
PM ..................
S .....................
SO2 ................
THC ................
ZrO2 ...............
*
*
*
*
*
(f) * * *
(2) This part uses the following molar
masses or effective molar masses of
chemical species:
E:\FR\FM\30OCR2.SGM
30OCR2
ER30OC09.191</MATH>
*
sroberts on DSKD5P82C1PROD with RULES
0.05 μmol/mol.
1 μmol/mol.
10 μmol/mol.
2 μmol/mol.
0.02 μmol/mol.
0.05 μmol/mol.
ER30OC09.190</MATH>
2 The
≤
≤
≤
≤
≤
≤
ER30OC09.189</MATH>
1 We
Purified N21
56519
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations
g/mol
(10¥3.kg.mol¥ 1)
Symbol
Quantity
Mair ...........................................................
MAr ...........................................................
MC .............................................................
MCO ...........................................................
MCO2 .........................................................
MH ............................................................
MH2 ...........................................................
MH2O .........................................................
MHe ...........................................................
MN ............................................................
MN2 ...........................................................
MNMHC ......................................................
MNMHCE ....................................................
MNOx .........................................................
MN2O .........................................................
MO ............................................................
MO2 ...........................................................
MC3H8 ........................................................
MS .............................................................
MTHC .........................................................
MTHCE .......................................................
molar mass of dry air .................................................................................................
molar mass of argon ..................................................................................................
molar mass of carbon ................................................................................................
molar mass of carbon monoxide ................................................................................
molar mass of carbon dioxide ....................................................................................
molar mass of atomic hydrogen .................................................................................
molar mass of molecular hydrogen ............................................................................
molar mass of water ...................................................................................................
molar mass of helium .................................................................................................
molar mass of atomic nitrogen ...................................................................................
molar mass of molecular nitrogen ..............................................................................
effective molar mass of nonmethane hydrocarbon 2 .................................................
effective molar mass of nonmethane equivalent hydrocarbon 2 ................................
effective molar mass of oxides of nitrogen 3 ..............................................................
effective molar mass of nitrous oxide ........................................................................
molar mass of atomic oxygen ....................................................................................
molar mass of molecular oxygen ...............................................................................
molar mass of propane ..............................................................................................
molar mass of sulfur ...................................................................................................
effective molar mass of total hydrocarbon 2 ...............................................................
effective molar mass of total hydrocarbon equivalent 2 .............................................
1 See
2 The
3 The
paragraph (f)(1) of this section for the composition of dry air
effective molar masses of THC, THCE, NMHC, and NMHCE are defined by an atomic hydrogen-to-carbon ratio, a, of 1.85
effective molar mass of NOx is defined by the molar mass of nitrogen dioxide, NO2
*
*
*
*
*
(g) Other acronyms and abbreviations.
This part uses the following additional
abbreviations and acronyms:
ASTM American Society for Testing
and Materials.
BMD bag mini-diluter.
BSFC brake-specific fuel consumption.
CARB California Air Resources Board.
CFR Code of Federal Regulations.
CFV critical-flow venturi.
CI compression-ignition.
CITT Curb Idle Transmission Torque.
CLD chemiluminescent detector.
CVS constant-volume sampler.
DF deterioration factor.
ECM electronic control module.
EFC electronic flow control.
sroberts on DSKD5P82C1PROD with RULES
28.96559
39.948
12.0107
28.0101
44.0095
1.00794
2.01588
18.01528
4.002602
14.0067
28.0134
13.875389
13.875389
46.0055
44.0128
15.9994
31.9988
44.09562
32.065
13.875389
13.875389
VerDate Nov<24>2008
17:39 Oct 29, 2009
Jkt 220001
EGR exhaust gas recirculation.
EPA Environmental Protection
Agency.
FEL Family Emission Limit
FID flame-ionization detector.
GC gas chromatograph.
GC–ECD gas chromatograph with an
electron-capture detector.
IBP initial boiling point.
ISO International Organization for
Standardization.
LPG liquefied petroleum gas.
NDIR nondispersive infrared.
NDUV nondispersive ultraviolet.
NIST National Institute for Standards
and Technology.
PDP positive-displacement pump.
PEMS portable emission measurement
system.
PO 00000
Frm 00261
Fmt 4701
Sfmt 4700
PFD partial-flow dilution.
PMP Polymethylpentene.
pt. a single point at the mean value
expected at the standard.
PTFE polytetrafluoroethylene
(commonly known as TeflonTM).
RE rounding error.
RMC ramped-modal cycle.
RMS root-mean square.
RTD resistive temperature detector.
SSV subsonic venturi.
SI spark-ignition.
UCL upper confidence limit.
UFM ultrasonic flow meter.
U.S.C. United States Code.
[FR Doc. E9–23315 Filed 10–29–09; 8:45 am]
BILLING CODE 6560–50–P
E:\FR\FM\30OCR2.SGM
30OCR2
]]>Agencies
[Federal Register Volume 74, Number 209 (Friday, October 30, 2009)]
[Rules and Regulations]
[Pages 56260-56519]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E9-23315]
[[Page 56259]]
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Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 86, 87, 89 et al.
Mandatory Reporting of Greenhouse Gases; Final Rule
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 /
Rules and Regulations
[[Page 56260]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 86, 87, 89, 90, 94, 98, 1033, 1039, 1042, 1045, 1048,
1051, 1054, 1065
[EPA-HQ-OAR-2008-0508; FRL-8963-5]
RIN 2060-A079
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: EPA is promulgating a regulation to require reporting of
greenhouse gas emissions from all sectors of the economy. The final
rule applies to fossil fuel suppliers and industrial gas suppliers,
direct greenhouse gas emitters and manufacturers of heavy-duty and off-
road vehicles and engines. The rule does not require control of
greenhouse gases, rather it requires only that sources above certain
threshold levels monitor and report emissions.
DATES: The final rule is effective on December 29, 2009. The
incorporation by reference of certain publications listed in the rule
is approved by the Director of the Federal Register as of December 29,
2009.
ADDRESSES: EPA has established a docket for this action under Docket ID
No. EPA-HQ-OAR-2008-0508. All documents in the docket are listed on the
www.regulations.gov Web site. Although listed in the index, some
information is not publicly available, e.g., confidential business
information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the Internet and will be publicly available only in hard
copy form. Publicly available docket materials are available either
electronically through www.regulations.gov or in hard copy at EPA's
Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301
Constitution Avenue, NW., Washington, DC 20004. 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 and implementation
materials, please go to the Web site www.epa.gov/climatechange/emissions/ghgrulemaking.html. You may also contact the Greenhouse Gas
Reporting Rule Hotline at telephone number: (877) 444-1188; or e-mail:
ghgmrr@epa.gov.
SUPPLEMENTARY INFORMATION:
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (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.''). The final
rule affects fuel and chemicals suppliers, direct emitters of
greenhouse gases (GHGs) and manufacturers of mobile sources and
engines. Regulated categories and entities 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.
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 Portland Cement
manufacturing plants.
Ferroalloy Production.......... 331112 Ferroalloys
manufacturing
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.
Nitric Acid Production......... 325311 Nitric acid
manufacturing
facilities.
Petrochemical Production....... 32511 Ethylene dichloride
manufacturing
facilities.
325199 Acrylonitrile, ethylene
oxide, methanol
manufacturing
facilities.
325110 Ethylene manufacturing
facilities.
[[Page 56261]]
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.
212391 Soda ash, natural,
mining and/or
beneficiation.
Titanium Dioxide Production.... 325188 Titanium dioxide
manufacturing
facilities.
Zinc Production................ 331419 Primary zinc refining
facilities.
331492 Zinc dust reclaiming
facilities, recovering
from scrap and/or
alloying purchased
metals.
Municipal Solid Waste Landfills 562212 Solid waste landfills.
221320 Sewage treatment
facilities.
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 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................. 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
affected by this action. Table 1 of this preamble lists the types of
facilities that EPA is now aware could be potentially affected by the
reporting requirements. Other types of facilities and suppliers not
listed in the table could also be subject to reporting requirements. To
determine whether you are affected by this action, you should carefully
examine the applicability criteria found in 40 CFR part 98, subpart A
or the relevant criteria in the sections related to manufacturers of
heavy-duty and off-road vehicles and engines. 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 are affected by the final 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 are
relevant for all reporters.
Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
Other subparts recommended for
Source category (and main applicable review to determine
subpart) applicability
------------------------------------------------------------------------
General Stationary Fuel Combustion
Sources.
Electricity Generation................. General Stationary Fuel
Combustion, Suppliers of CO2.
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.
Ferroalloy Production.................. General Stationary Fuel
Combustion.
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.
[[Page 56262]]
Lead Production........................ General Stationary Fuel
Combustion.
Lime Manufacturing..................... General Stationary Fuel
Combustion.
Nitric Acid Production................. General Stationary Fuel
Combustion, Adipic Acid.
Petrochemical Production............... General Stationary Fuel
Combustion, Ammonia, Petroleum
Refineries.
Petroleum Refineries................... General Stationary Fuel
Combustion, Hydrogen,
Suppliers of Petroleum
Products.
Phosphoric Acid Production............. General Stationary Fuel
Combustion.
Pulp and Paper Manufacturing........... General Stationary Fuel
Combustion.
Silicon Carbide Production............. General Stationary Fuel
Combustion.
Soda Ash Manufacturing................. General Stationary Fuel
Combustion.
Titanium Dioxide Production............ General Stationary Fuel
Combustion.
Zinc Production........................ General Stationary Fuel
Combustion.
Municipal Solid Waste Landfills........ General Stationary Fuel
Combustion.
Manure Management...................... General Stationary Fuel
Combustion.
Suppliers of Coal-based Liquid Fuels... Suppliers of Petroleum
Products.
Suppliers of Petroleum Products........ General Stationary Fuel
Combustion.
Suppliers of Natural Gas and NGLs...... General Stationary Fuel
Combustion, 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.
------------------------------------------------------------------------
Judicial Review. Under section 307(b)(1) of the CAA, judicial
review of this final rule is available only by filing a petition for
review in the U.S. Court of Appeals for the District of Columbia
Circuit by December 29, 2009. Under CAA section 307(d)(7)(B), only an
objection to this final rule that was raised with reasonable
specificity during the period for public comment can be raised during
judicial review. This section also provides a mechanism for us to
convene a proceeding for reconsideration, ``[i]f the person raising an
objection can demonstrate to EPA that it was impracticable to raise
such objection within [the period for public comment] or if the grounds
for such objection arose after the period for public comment (but
within the time specified for judicial review) and if such objection is
of central relevance to the outcome of this rule.'' Any person seeking
to make such a demonstration to us should submit a Petition for
Reconsideration to the Office of the Administrator, Environmental
Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania
Ave., NW., Washington, DC 20004, with a copy to the person listed in
the preceding FOR FURTHER INFORMATION CONTACT section, and the
Associate General Counsel for the Air and Radiation Law Office, Office
of General Counsel (Mail Code 2344A), Environmental Protection Agency,
1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, under CAA
section 307(b)(2), the requirements established by this final rule may
not be challenged separately in any civil or criminal proceedings
brought by EPA to enforce these requirements.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
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
CAIR Clean Air Interstate Rule
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CCS carbon capture and sequestration
CEMS continuous emission monitoring system(s)
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
EAF electric arc furnace
ECOS Environmental Council of the States
EGUs electric generating units
EIA Energy Information Administration
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC-22 chlorodifluoromethane (or CHClF2)
HCFCs hydrochlorofluorocarbons
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
kg kilograms
LDCs local natural gas distribution companies
LMP lime manufacturing plants
mmBtu/hr millions British thermal units per hour
MSW municipal solid waste
MW megawatts
MY mileage year
N2O nitrous oxide
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
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
PSD Prevention of Significant Deterioration
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
R&D research and development
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RICE reciprocating internal combustion engine
RIA regulatory impact analysis
SBREFA Small Business Regulatory Enforcement Fairness Act
[[Page 56263]]
scf standard cubic feet
SF6 sulfur hexafluoride
SIP State Implementation Plan
SOP standard operating procedure
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TRI Toxic Release Inventory
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
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. Organization of This Preamble
B. Background on the Final Rule
C. Legal Authority
D. How does this rule relate to EPA and U.S. government climate
change efforts?
E. How does this rule relate to State and regional programs?
II. General Requirements of the Rule
A. Summary of the General Requirements of the Final Rule
B. Summary of the Major Changes Since Proposal
C. Summary of Comments and Responses on GHGs To Report
D. Summary of Comments and Responses on Source Categories To
Report
E. Summary of Comments and Responses on Thresholds
F. Summary of Comments and Responses on Level of Reporting
G. Summary of Comments and Responses on Initial Reporting Year
and Best Available Monitoring Methods
H. Summary of Comments and Responses on Frequency of Reporting
and Provisions To Cease Reporting
I. Summary of Comments and Responses on General Content of the
Annual GHG Report
J. Summary of Comments and Responses on Submittal Date and
Making Corrections to Annual Reports
K. Summary of Comments and Responses on De Minimis Reporting
L. Summary of Comments and Responses on General Monitoring
Requirements
M. Summary of Comments and Responses on General Recordkeeping
Requirements
N. Summary of Comments and Responses on Emissions Verification
Approach
O. Summary of Comments and Responses on the Role of States and
Relationship of This Rule to Other Programs
P. Summary of Comments and Responses on Other General Rule
Requirements
Q. Summary of Comments and Responses on Statutory Authority
R. Summary of Comments and Responses on CBI
S. Summary of Comments and Responses on Other Legal Issues
III. Reporting and Recordkeeping Requirements for Specific Source
Categories
A. Overview
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. Municipal Solid Waste 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)
IV. Mobile Sources
A. Summary of Requirements of the Final Rule
B. Summary of Changes Since Proposal
C. Summary of Comments and Responses
V. Collection, Management, and Dissemination of GHG Emissions Data
A. Summary of Data Collection, Management and Dissemination for
the Final Rule
B. Summary of Comments and Responses on Collection, Management,
and Dissemination of GHG Emissions Data
VI. Compliance and Enforcement
A. Compliance and Enforcement Summary
B. Summary of Public Comments and Responses on Compliance and
Enforcement
VII. Economic Impacts of the Rule
A. How were compliance costs estimated?
B. What are the costs of the rule?
C. What are the economic impacts of the rule?
D. What are the impacts of the rule on small businesses?
E. What are the benefits of the rule for society?
VIII. 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
K. Congressional Review Act
I. Background
A. Organization of This Preamble
This preamble is broken into several large sections, as detailed
above in the Table of Contents. The paragraphs below describe the
layout of the preamble and provide a brief summary of each section.
The first section of this preamble contains the basic background
information about the origin of this rule, our legal authority, and how
this proposal relates to other Federal, State, and regional efforts to
address emissions of GHGs.
The second section of this preamble summarizes the general
provisions of the final GHG reporting rule and identifies the major
changes since proposal. It also provides a brief summary of public
comments and responses on key design elements such as: (i) Source
categories included, (ii) the level of reporting, (iii) applicability
thresholds, (iv) selection of reporting and monitoring methods, (v)
emissions verification, (vi) frequency of reporting and (vii) duration
of reporting. It also addresses some of the legal comments on the
statutory authority for the rule and the relationship of this rule to
other CAA programs.
The third section of this preamble contains separate subsections
addressing each individual source category of the proposed rule. Each
source category section contains a summary of specific requirements of
the rule for that source category, identifies major changes since
proposal, and briefly discusses public comments and EPA responses
specific to the source category. For example, comments on EPA's general
approach for selecting monitoring methods are discussed in Section II
of this preamble, whereas,
[[Page 56264]]
comments on specific monitoring methods for individual source
categories are discussed in Section III of this preamble.
The fourth section of this preamble summarizes rule requirements
and addresses public comments pertaining to mobile sources.
The fifth section of this preamble explains how EPA plans to
collect, manage and disseminate the data, while the sixth section
describes the approach to compliance and enforcement. In both sections
key public comments are summarized and responses are presented.
The seventh section provides the summary of the cost impacts,
economic impacts, and benefits of the final rule and discusses comments
on the regulatory impacts analyses. Finally, the last section discusses
the various statutory and executive order requirements applicable to
this rulemaking.
B. Background on the Final Rule
The fiscal year 2008 (FY2008) Consolidated Appropriations Act,
signed on December 26, 2007, authorized funding for EPA to ``develop
and publish a draft rule not later than nine months after the date of
enactment of [the] Act, and a final rule not later than 18 months after
the date of enactment of [the] Act, to require mandatory reporting of
greenhouse gas 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 interpreted that language to confirm that it was
appropriate for the Agency to exercise its CAA authority to develop
this rulemaking. 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
(EGUs)'' under section 821 of the 1990 CAA Amendments.
On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting
rule. EPA held two public hearings, and received approximately 16,800
written public comments. The public comment period ended on June 9,
2009.
In addition to the public hearings, EPA had an open door policy,
similar to the outreach conducted during the development of the
proposal. As a result, EPA has met with over 4,000 people and 135
groups since proposal signature (March 10, 2009). Details of these
meetings are available in the docket (EPA-HQ-OAR-2008-0508).
EPA developed this final rule and included reporting of GHGs from
the facilities that we determined appropriately responded to the
direction in the FY2008 Consolidated Appropriations Act \1\ (e.g.,
capturing approximately 85 percent of U.S. GHG emissions through
reporting by direct emitters as well as suppliers of fossil fuels and
industrial gases and manufacturers of heavy-duty and off-road vehicles
and engines). There are, however, many additional types of data and
reporting that the Agency deems important and necessary to address an
issue as large and complex as climate change (e.g., indirect emissions,
electricity use). In that sense, one could view this final rule as
narrowly focused on certain sources of emissions and upstream
suppliers. As described in Sections I.C and D of this preamble as well
as in the comment response sections, there are several existing
programs at the Federal, regional and State levels that also collect
valuable information to inform and implement policies necessary to
address climate change. Many of these programs are focused on cost-
effectively reducing GHG emissions through improvements in energy
efficiency and by other means. These programs are an essential
component of the Nation's climate policy, and the targeted nature of
this rule should not be interpreted to mean that the data EPA collects
through this program are the only data necessary to support the full
range of climate policies and programs.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG
reporting rule, and provided additional funding, in the 2009
Appropriations Act (Consolidated Appropriations Act, 2009, Public
Law 110-329, 122 Stat. 3574-3716).
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Today's rule requires the reporting of the GHG emissions that could
result from the combustion or use 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 directly emitted from facilities
(downstream sources) through their processes and/or from fuel
combustion, as appropriate. Vehicle and engine manufacturers are also
required to report emissions rate data on the heavy-duty and off-road
engines they produce. The rule also establishes appropriate thresholds
and frequency for reporting.
The rule requires reporting of annual emissions of carbon dioxide
(CO2), methane (CH4), nitrous oxide
(N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other
fluorinated gases (e.g., nitrogen trifluoride (NF3) and
hydrofluorinated ethers (HFEs)). It also includes provisions to ensure
the accuracy of emissions data through monitoring, recordkeeping and
verification requirements. The rule applies to certain downstream
facilities that emit GHGs (primarily large facilities emitting 25,000
metric tons or more of CO2 equivalent (CO2e) GHG
emissions per year) and to most upstream suppliers of fossil fuels and
industrial GHGs, as well as to manufacturers of vehicles and engines.
Reporting is at the facility level, except certain suppliers and
vehicle and engine manufacturers report at the corporate level.
C. Legal Authority
As proposed, EPA is promulgating this rule under its existing CAA
authority, specifically authorities provided in CAA sections 114 and
208. As discussed further below and in ``Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Legal Issues'', we
are not citing the FY 2008 Consolidated Appropriations Act as the
statutory basis for this action. While that law required that EPA spend
no less than $3.5 million on a rule requiring the mandatory reporting
of GHG emissions, it is the CAA, not the Appropriations Act, that EPA
is citing as the authority to gather the information required by this
rule.
Sections 114 and 208 of the CAA provide EPA broad authority to
require the information mandated by this rule because such data will
inform and are relevant to EPA's carrying out a wide variety of CAA
provisions. As discussed in the proposed rule, CAA section 114(a)(1)
authorizes the Administrator to require emissions sources, persons
subject to the CAA, or persons whom the Administrator believes may have
necessary information to monitor and report emissions and provide such
other information the Administrator requests for the purposes of
carrying out any provision of the CAA (except for a provision of title
II with respect to manufacturers of new motor vehicles or
[[Page 56265]]
new motor vehicle engines).\2\ 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. We note that while climate
change legislation approved by the U.S. House of Representatives would
provide EPA additional authority for a GHG registry similar to today's
rule, and would do so for purposes of that pending legislation, this
final rule is authorized by, and the information being gathered by the
rule is relevant to implementing, the existing CAA. We expect, however,
that the information collected by this final rule will also prove
useful to legislative efforts to address GHG emissions.
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\2\ Although there are exclusions in CAA section 114(a)(1)
regarding certain title II requirements applicable to manufacturers
of new motor vehicle and motor vehicle engines, CAA section 208
authorizes the gathering of information related to those areas.
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As discussed in the proposal, emissions from direct emitters should
inform decisions about whether and how to use CAA section 111 to
establish new source performance standards (NSPS) for various source
categories emitting GHGs, including whether there are any additional
categories of sources that should be listed under CAA section 111(b).
Similarly, the information required of manufacturers of mobile sources
should support decisions regarding treatment of those sources under CAA
sections 202, 213 or 231. In addition, the information from fuel
suppliers would be relevant in analyzing whether to proceed, and
particular options for how to proceed, under CAA section 211(c)
regarding fuels, or to inform action concerning downstream sources
under a variety of Title I or Title II provisions. The data overall
also would inform EPA's implementation of CAA section 103(g) regarding
improvements in non-regulatory strategies and technologies for
preventing or reducing air pollutants (e.g., EPA's voluntary GHG
reduction programs such as the non-CO2 partnership programs
and ENERGY STAR, described below in Section I.D of this preamble and
Section II of the proposal preamble (74 FR 16448, April 10, 2009)).
D. How does this rule relate to EPA and U.S. government climate change
efforts?
This reporting rule is one specific action EPA has taken,
consistent with the Congressional request contained in the FY2008
Consolidated Appropriations Act, to collect GHG emissions data. EPA has
recently announced a number of climate change related actions,
including proposed findings that GHG emissions from new motor vehicles
and engines contribute to air pollution which may reasonably be
anticipated to endanger public health and welfare (74 FR 18886, April
24, 2009, ``Proposed Endangerment and Cause or Contribute Findings for
Greenhouse Gases Under Section 202(a) of the Clean Air Act''), and an
intent to regulate light duty vehicles, jointly published with U.S.
Department of Transportation (DOT) (74 FR 24007, May 22, 2009, ``Notice
of Upcoming Joint Rulemaking To Establish Vehicle GHG Emissions and
CAFE Standards''). The Administrator has also announced her
reconsideration of the memo entitled ``EPA's Interpretation of
Regulations that Determine Pollutants Covered By Federal Prevention of
Significant Deterioration (PSD) Permit Program'' (73 FR 80300, December
31, 2008), and granted California's request for a waiver for its GHG
vehicle standard (74 FR 32744, July 8, 2009). These are all separate
actions, some of which are related to EPA's response to the U.S.
Supreme Court's decision in Massachusetts v. EPA. 127 S. Ct. 1438
(2007). This rulemaking does not indicate EPA has made any final
decisions on pending actions. In fact the mandatory GHG reporting
program will provide EPA, other government agencies, and outside
stakeholders with economy-wide data on facility-level (and in some
cases corporate-level) GHG emissions, which should assist in future
policy development.
Accurate and timely information on GHG emissions is essential for
informing many future climate change policy decisions. Although
additional data collection (e.g., for other source categories or to
support additional policy or program needs) will no doubt be required
as the development of climate policies evolves, the data collected in
this rule will provide useful information for a variety of polices.
Through data collected under this rule, EPA, States and the public will
gain a better understanding of the relative emissions of specific
industries across the nation 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
GHG emission rates and actions that facilities could in the future or
already take to reduce emissions, including under traditional and more
flexible programs.
As discussed in more detail in ``Mandatory Greenhouse Gas Reporting
Rule: EPA's Response to Public Comments, Legal Issues'' and elsewhere,
EPA is promulgating this rule to gather GHG information to assist EPA
in assessing how to address GHG emissions and climate change under the
Clean Air Act. However, we expect that the information will prove
useful for other purposes as well. For example, using the rich data set
provided by this rulemaking, EPA, States and the public will be able to
track emission trends from industries and facilities within industries
over time, particularly in response to policies and potential
regulations. The data collected by this rule will also improve the U.S.
government's ability to formulate climate policies, and to assess which
industries might be affected, and how these industries might be
affected by potential policies. 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 and implement emission reduction opportunities. These data
can also be coupled with efforts at the local, State and Federal levels
to assist corporations and facilities in determining their GHG
footprints and identifying opportunities to reduce emissions (e.g.,
through energy audits or other forms of assistance).
This GHG reporting program supplements and complements, rather than
duplicates, existing U.S. government programs (e.g., climate policy and
research programs). For example, EPA anticipates that facility-level
GHG emissions data will lead to improvements in the quality of the
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory), which
EPA prepares annually, with input from several other agencies, and
submits to the Secretariat of the United Nations Framework Convention
on Climate Change (UNFCCC).
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, Energy Star). This mandatory reporting
program has broader coverage of U.S. GHG emissions than most voluntary
programs, which typically focus on a specific industry and/or goal
(e.g., reduction of CH4 emissions or development of
corporate inventories). It will improve EPA's understanding of
emissions from facilities not currently included in these programs and
increase the coverage of these industries. That said, we expect ongoing
and potential new voluntary programs to continue to
[[Page 56266]]
play an important role in achieving low-cost reductions in GHG
emissions.
In addition to EPA's programs mentioned above, U.S. Department of
Energy (DOE) EIA implements a voluntary GHG registry under section
1605(b) of the Energy Policy Act, which is further discussed in Section
II of the proposal preamble (74 FR 16458, April 10, 2009). 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.\3\
EPA's mandatory GHG reporting rule covers a much broader set of
reporters, primarily at the facility rather than entity-level, but this
reporting rule is not designed with the specific intent of reporting of
emission reductions, as is the 1605(b) program.
For additional information about these programs, please see
Sections I and II of the preamble to the proposed GHG reporting rule
(74 FR 16454, April 10, 2009).
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\3\ 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/)
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E. How does this rule relate to other State and Regional Programs?
There are several existing State and regional GHG reporting and/or
reduction programs summarized in Section II of the proposal preamble
(74 FR 16457, April 10, 2009). These are important programs that not
only led the way in reporting of GHG emissions before the Federal
government acted but also assist in quantifying the GHG reductions
achieved by various policies. Many of these programs collect different
or additional data as compared to this rule. For example, State
programs may establish lower thresholds for reporting or request
information on areas not addressed in EPA's reporting rule (e.g.,
electricity use or emission related to other indirect sources). States
collecting additional information have determined that these data are
necessary to implement their specific climate policies and programs.
EPA agrees that State and regional programs are crucial to achieving
emissions reductions, and this rule does not preempt any other
programs.
EPA's GHG reporting rule is a specific single action that was
developed in response to the Appropriations Act, and therefore is
targeted to accomplish the purpose of the language of the
Appropriations Act and serve EPA's purposes under the CAA. As State
experience has demonstrated, we recognize that in order to address the
breadth of climate change issues there will likely be a need to collect
additional data from sources subject to this rule as well as other
sources. The timing and nature of these additional needs will be
dependent on the types of programs and actions the Agency has underway
or may develop and implement in response to future policy developments
and/or new requests from Congress. Addressing climate change will
require a suite of policies and programs and this reporting rule is
just one effort to collect information to inform those policies.
EPA is committed to working with State and regional programs to
coordinate implementation of reporting programs, reduce burden on
reporters, provide timely access to verified emissions data, establish
mechanisms to efficiently share data, and harmonize data systems to the
extent possible. See Section II.O of this preamble for a summary of
public comments and responses on the role of States and the
relationship of this GHG reporting rule to other programs. See Section
VI.B of this preamble for a summary of comments and responses on State
delegation of rule implementation and enforcement. As mentioned above,
for additional information about existing State and regional programs
please see Section II of the proposal preamble (74 FR 16457, April 10,
2009) and the docket EPA-HQ-OAR-2008-0508.
II. General Requirements of the Rule
The rule requires reporting of annual emissions of CO2,
CH4, N2O, SF6, HFCs, PFCs, and other
fluorinated gases (as defined in 40 CFR part 98, subpart A) in metric
tons. The final 40 CFR part 98 applies to certain downstream facilities
that emit GHGs, and to certain upstream suppliers of fossil fuels and
industrial GHGs. For suppliers, the GHG emissions reported are the
emissions that would result from combustion or use of the products
supplied. The rule also includes provisions to ensure the accuracy of
emissions data through monitoring, recordkeeping and verification
requirements. Reporting is at the facility \4\ level, except that
certain suppliers of fossil fuels and industrial gases would report at
the corporate level.
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\4\ 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 than
a single facility based on distinct and independent functional
groupings within contiguous military properties.
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In addition, GHG reporting by manufacturers of heavy-duty and off-
road vehicles and engines is required, by incorporating new
requirements into the existing reporting requirements for motor
vehicles and engine manufacturers in 40 CFR parts 86, 87, 89, 90, 94,
1033, 1039, 1042, 1045, 1048, 1051, 1054, and 1065. A summary of the
reporting requirements for manufacturers of motor vehicles and engines
is contained in Section IV of this preamble. A discussion of public
comments and responses that pertain to motor vehicles is also contained
in Section IV of this preamble and in the ``Mandatory Greenhouse Gas
Reporting Rule: EPA's Response to Public Comments, Motor Vehicle and
Engine Manufacturers.''
The remainder of this section summarizes the general provisions of
40 CFR part 98, identifies changes since the proposed rule, and
summarizes key public comments and responses on the general
requirements of the rule.
A. Summary of the General Requirements of the Final Rule
1. Applicability
Reporters must submit annual GHG reports for the following
facilities and supply operations.
Any facility that contains any source category (as defined
in 40 CFR part 98, subparts C through JJ) that is listed below in any
calendar year starting in 2010.\5\ For these facilities, the annual GHG
report covers all source categories and GHGs for which calculation
methodologies are provided in 40 CFR part 98, subparts C through JJ.
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\5\ Unless otherwise noted, years and dates in this notice refer
to calendar years and dates.
--Electricity generating facilities that are subject to the Acid Rain
Program (ARP) or otherwise report CO2 mass emissions year-
round through 40 CFR part 75.
--Adipic acid production.
--Aluminum production.
--Ammonia manufacturing.
--Cement production.
--HCFC-22 production.
--HFC-23 destruction processes that are not co-located 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.
[[Page 56267]]
--Phosphoric acid production.
--Silicon carbide production.
--Soda ash production.
--Titanium dioxide production.
--Municipal solid waste (MSW) landfills that generate CH4 in
amounts equivalent to 25,000 metric tons CO2e or more per
year, as determined according to 40 CFR part 98, subpart HH.
--Manure management systems that emit CH4 and N20
(combined) in amounts equivalent to 25,000 metric tons CO2e
or more per year, as determined according to 40 CFR part 98, subpart
JJ.
Any facility that contains any source category (as defined
in 40 CFR part 98, subparts C through JJ) that is listed below and 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 in this paragraph in
any calendar year starting in 2010. For these facilities, the annual
GHG report must cover all source categories and GHGs for which
calculation methodologies are provided in 40 CFR part 98, subparts C
through JJ.
--Ferroalloy Production.
--Glass Production.
--Hydrogen Production.
--Iron and Steel Production.
--Lead Production.
--Pulp and Paper Manufacturing.
--Zinc Production.
Any facility that in any calendar year starting in 2010
meets all three of the conditions listed in this paragraph. For these
facilities, the annual GHG report covers emissions from stationary fuel
combustion sources only. For 2010 only, the facilities can submit an
abbreviated GHG report according to 40 CFR 98.3(d).
--The facility does not meet the requirements described in the above
two paragraphs;
--The aggregate maximum rated heat input capacity of the stationary
fuel combustion units at the facility is 30 million British thermal
units per hour (mmBtu/hr) or greater; and
--The facility emits 25,000 metric tons CO2e or more per
year from all stationary fuel combustion sources.\6\
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\6\ This does not include portable equipment, emergency
generators, or emergency equipment as defined in the rule.
Any supplier (as defined in 40 CFR part 98, subparts LL
through PP) of any of the products as listed below in any calendar year
starting in 2010. For these suppliers, the annual GHG report covers all
applicable products for which calculation methodologies are provided in
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40 CFR part 98, subparts KK through PP.
--Coal-based liquid fuels: All producers of coal-to-liquid fuels;
importers and exporters of coal-to-liquid fuels with annual imports or
annual exports that are equivalent to 25,000 metric tons
CO2e or more per year.
--Petroleum products: All petroleum refiners that distill crude oil;
importers and exporters of petroleum products with annual imports or
annual exports that are equivalent to 25,000 metric tons
CO2e or more per year.
--Natural gas and natural gas liquids (NGLs): All natural gas
fractionators and all local natural gas distribution companies (LDCs).
--Industrial GHGs: All producers of industrial GHGs; importers and
exporters of industrial GHGs with annual bulk imports or exports of
N2O, fluorinated GHGs, and CO2 that in
combination are equivalent to 25,000 metric tons CO2e or
more per year.
--CO2: All producers of CO2; importers and exporters of
CO2 with annual bulk imports or exports of N2O,
fluorinated GHGs, and CO2 that in combination are equivalent
to 25,000 metric tons CO2e or more per year.
Research and development activities (as defined in 40 CFR
98.6) are not considered to be part of any source category subject to
the rule.
It is important to note that the applicability criteria apply to a
facility's annual emissions or a supplier's annual quantity of product
supplied.\7\ For example, while a facility's emissions may be below
25,000 metric tons CO2e in January, if the cumulative
emissions for the calendar year are 25,000 metric tons CO2e
or more at the end of December, the rule applies and the reporter must
submit an annual GHG report for that facility. Therefore, it is in a
facility's or supplier's interest to collect the GHG data required by
the rule if they think they will meet or exceed the applicability
criteria in 40 CFR 98.2 by the end of the year. EPA plans to have tools
and guidance available to assist potential reporters in assessing
whether the rule applies to their facilities or supply operations.
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\7\ Supplied means produced, imported, or exported.
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2. Schedule for Reporting
Reporters must begin collecting data on January 1, 2010. The first
annual GHG report is due on March 31, 2011, for GHGs emitted or
products supplied during 2010. For a portion of 2010, the rule allows
reporters to use best available monitoring methods for parameters that
cannot reasonably be measured according to the monitoring and quality
assurance/quality control (QA/QC) requirements of the relevant subpart
as described in Sections II.A.3 and II.G of this preamble.
Reports are submitted annually. For EGUs that are subject to the
ARP, reporters must continue to report CO2 mass emissions
quarterly, as required by the ARP, in addition to providing annual GHG
reports under this rule. Reporters must submit GHG data on an ongoing,
annual basis. The snapshot of information provided by a one-time
information collection request (ICR) would not provide the type of
ongoing information which could inform the variety of potential CAA
policy options being evaluated for addressing climate change.
Once subject to this reporting rule, reporters must continue to
submit GHG reports annually. A reporter can cease reporting if the
required annual GHG reports demonstrate that reported GHG emissions are
either (1) less than 25,000 metric tons of CO2e per year for
five consecutive years or (2) less than 15,000 metric tons of
CO2e per year for three consecutive years. The reporter must
notify EPA that they intend to cease reporting and explain the reasons
for the reduction in emissions. This provision applies to all
facilities and suppliers subject to the rule, regardless of their
applicability category (i.e., whether rule applicability was initially
triggered by an ``all-in'' source category or a source category with a
25,000 metric tons CO2e threshold). The reporter must keep
records for all five consecutive years in which emissions were less
than 25,000 metric tons per year, or all three consecutive years in
which emissions were less than 15,000 metric tons per year, as
appropriate. If GHG emissions (or quantities in products supplied)
subsequently increase to 25,000 metric tons CO2e in any
calendar year, the reporter must again begin annual reporting. The rule
also contains a provision to allow facilities and suppliers to notify
EPA and stop reporting if they close all GHG-emitting processes and
operations covered by the rule.
If reporters discover or are notified by EPA of errors in an annual
GHG report, they must submit a revised GHG report within 45 days.
3. What has to be included in the annual GHG report?
Reporters must include the following information in each annual GHG
report:
[[Page 56268]]
Facility name or supplier name (as appropriate) and
physical street address including the city, State, and zip code.
Year and months covered by the report, and date of report
submittal.
For facilities that directly emit GHG:
--Annual facility emissions (excluding biogenic CO2),
expressed in metric tons of CO2e per year, aggregated for
all GHG from all source categories in 40 CFR part 98, subparts C
through JJ that are located at the facility.
--Annual emissions of biogenic CO2
