[Federal Register Volume 74, Number 209 (Friday, October 30, 2009)]
[Rules and Regulations]
[Pages 56260-56519]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-23315]
[[Page 56259]]
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Part II
Environmental Protection Agency
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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]]
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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.
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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:
[email protected]. 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:
[email protected].
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.
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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.
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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
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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
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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
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.'' (http://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 (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\
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\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.
--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.
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\9\ ``Use'' for purposes of industrial GHGs presumes that there
will be 100 percent release of the GHG.
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--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.
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\
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\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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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, 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.
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\11\ For more information about the reporting format please see
Section V of this preamble.
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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
[[Page 56269]]
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.
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.''
Reduced the number of source categories included in the
final rule as we further consider comments and options on several
categories.\12\
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\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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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 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
[[Page 56270]]
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.
---------------------------------------------------------------------------
\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:
http://www.ipcc.ch/ipccreports/methodology-reports.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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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.
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.
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 56271]]
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 facility-level 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.
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 the development of climate change policy and programs.
Potential 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 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
[[Page 56272]]
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 coal-fired units larger
than 30 mmBtu per 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
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
[[Page 56273]]
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:
Facility-level 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 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 facility-level 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 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,
[[Page 56274]]
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 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 facility-specific 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 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
[[Page 56275]]
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 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.
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
[[Page 56276]]
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.
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 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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 56277]]
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 GHG-emitting 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 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 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
[[Page 56278]]
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''.
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 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.
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 self-certification 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 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.
K. Summary of Comments and Responses on De Minimis Reporting
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.
[[Page 56279]]
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 facility-
level emissions to be excluded) or allow simplified calculation methods
for small sources.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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 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 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
[[Page 56280]]
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 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 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.
[[Page 56281]]
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 direct-fired 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 category-
specific 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 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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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 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
[[Page 56282]]
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 self-certification 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
self-certification seriously and ensure the emissions they report are
correct. Some also stated that independent verification is not needed
for a reporting program 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) Self-
certification without independent verification, (2) self-certification
with third party verification, and (3) self-certification with EPA
verification. For this particular program, EPA is not changing the
verification approach from the proposal and is requiring self-
certification 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 high-quality
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 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
[[Page 56283]]
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 self-
certification 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 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 self-
certification 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 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.
[[Page 56284]]
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 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 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
[[Page 56285]]
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 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 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--
[[Page 56286]]
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 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
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
[[Page 56287]]
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.
---------------------------------------------------------------------------
\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).
---------------------------------------------------------------------------
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.
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.''
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 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
[[Page 56288]]
``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.
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 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.
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,
[[Page 56289]]
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 corporate-wide 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 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 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
[[Page 56290]]
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 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 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.
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 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 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
[[Page 56292]]
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 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 fuel-specific 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 (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
[[Page 56293]]
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
unit-level 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 unit-level 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 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
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 year-round
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
[[Page 56294]]
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 unit-level 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
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
year-round 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 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 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
[[Page 56295]]
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 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.
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
[[Page 56296]]
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.
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-H[eacute]roult manufacturing process. The primary aluminum
manufacturing process consists of the following operations:
Electrolysis in prebake and S[oslash]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[oslash]derberg electrolysis cells
combined.
CO2 emissions from anode consumption during
electrolysis in all prebake and S[oslash]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[oslash]derberg electrolysis cell using the following parameters:
--Anode effect minutes (AEM) per cell-day calculated monthly.
--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 smelter-specific 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[oslash]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 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[oslash]derberg cells: Calculate
CO2 emissions from paste consumption in S[oslash]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[oslash]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
[[Page 56297]]
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[oslash]derberg cells (paste consumption) was corrected.
Language was updated to request reporting of all
CO2 emissions from on-site 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.
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 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
smelter-specific 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 rates). The Protocol
currently recommends that smelter operators re-measure 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) Thirty-six 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 smelter-specific
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,
[[Page 56298]]
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
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 fossil-based 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 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
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
[[Page 56299]]
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.
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 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.
[[Page 56300]]
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
kiln-specific 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 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 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
[[Page 56301]]
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 non-carbonated 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 plant-specific 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 facility-specific estimates,
where data are readily available to develop site-specific emission
factors. Default approaches would not provide site-specific calculation
of emissions that reflect 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 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.
[[Page 56302]]
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.
I. Electronics Manufacturing
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.
J. Ethanol Production
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.
K. Ferroalloy Production
1. Summary of the Final Rule
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 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
[[Page 56303]]
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
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 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.
[[Page 56304]]
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 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, 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
[[Page 56305]]
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.
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 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) 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
[[Page 56306]]
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.
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 initial performance test that established the destruction
efficiency.
A term has been added to 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. 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 under-estimate 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 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
[[Page 56307]]
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
CO2-equivalent. 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 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 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
[[Page 56308]]
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.''
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, 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 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.''
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 co-products 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
[[Page 56309]]
and solid hydrocarbon fuels of commerce to be characterized upon
delivery if delivered by bulk transport (e.g., by truck or rail). Other
non-standard 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 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 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
[[Page 56310]]
battery combustion stack, coke pushing process, sinter process, EAF,
argon-oxygen 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, argon-
oxygen 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, argon-oxygen 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 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 argon-oxygen 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.
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 carbon-containing inputs entering the
plant and in the most significant carbon-containing 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
[[Page 56311]]
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
process-specific 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) site-
specific 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 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.
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 in-
house 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
[[Page 56312]]
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 re-testing 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 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).
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):
[[Page 56313]]
--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 R.
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.
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 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
[[Page 56314]]
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 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:
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.
[[Page 56315]]
--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 Sec. 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.
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 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
[[Page 56316]]
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.
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 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 in-house 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 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-of-magnitude 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
[[Page 56317]]
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 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 non-emissive 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.
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
[[Page 56318]]
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.
V. Nitric Acid Production
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.
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.
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 N