[Federal Register Volume 75, Number 208 (Thursday, October 28, 2010)]
[Rules and Regulations]
[Pages 66434-66479]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-26506]
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Part II
Environmental Protection Agency
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40 CFR Parts 86 and 98
Mandatory Reporting of Greenhouse Gases; Final Rule
Federal Register / Vol. 75 , No. 208 / Thursday, October 28, 2010 /
Rules and Regulations
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 86 and 98
[EPA-HQ-OAR-2010-0109; FRL-9213-5]
RIN 2060-A079
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: EPA is amending specific provisions in the 2009 Final
Mandatory Greenhouse Gas Reporting rule to correct certain technical
and editorial errors that have been identified since promulgation and
to clarify and update certain provisions that have been the subject of
questions from reporting entities. These final changes include
additional information to better or more fully understand compliance
obligations, corrections to data reporting elements so they more
closely conform to the information used to perform emission
calculations, and other corrections and amendments.
DATES: The final rule amendments are effective on November 29, 2010.
The incorporation by reference of certain publications listed in the
final rule amendments are approved by the director of the Federal
Register as of November 29, 2010.
ADDRESSES: EPA has established a docket under Docket ID No. EPA-HQ-OAR-
2010-0109 for this action. All documents in the docket are listed on
the http://www.regulations.gov index. Although listed in the index,
some information is not publicly available, e.g., CBI or other
information whose disclosure is restricted by statute. Certain other
material, such as copyrighted material, 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
http://www.regulations.gov or in hard copy at EPA's Docket Center,
Public Reading Room, EPA West Building, Room 3334, 1301 Constitution
Ave., NW., Washington, DC. This Docket Facility is open from 8:30 a.m.
to 4:30 p.m., Monday through Friday, excluding legal holidays. The
telephone number for the Public Reading Room is (202) 566-1744, and the
telephone number for the Air Docket is (202) 566-1742.
FOR FURTHER GENERAL 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 Greenhouse Gas Reporting
Program Web site http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To submit a question, select Rule Help Center,
followed by Contact Us.
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''). These are
final amendments to existing regulations. These amended regulations
affect owners or operators of certain fossil fuel suppliers, direct
emitters of greenhouse gases, and manufacturers of highway heavy-duty
vehicles. Regulated categories and entities include those listed in
Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
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Category NAICS Examples of affected facilities
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Adipic Acid Production.......................... 325199 Adipic acid 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 Destruction....... 325120 Chlorodifluoromethane 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.
Lime Production................................. 327410 Calcium oxide, calcium hydroxide, dolomitic
hydrates manufacturing facilities.
Nitric Acid Production.......................... 325311 Nitric acid manufacturing facilities.
Phosphoric Acid Production...................... 325312 Phosphoric acid manufacturing facilities.
Soda Ash Manufacturing.......................... 325181 Alkali 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.
Suppliers of Coal Based Liquids Fuels........... 211111 Coal liquefaction at mine sites.
Suppliers of Natural Gas and NGLs............... 221210 Natural gas distribution facilities.
211112 Natural gas liquid extraction 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 than those 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 fossil fuel suppliers,
direct emitters of GHGs, and manufacturers of highway heavy-
[[Page 66435]]
duty vehicles. If you have questions regarding the applicability of
this action to a particular facility, consult the person listed in the
preceding FOR FURTHER GENERAL INFORMATION CONTACT section.
Judicial Review. Under section 307(b)(1) of the Clean Air Act
(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 (the Court) by December 27, 2010. 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. Section 307(d)(7)(B) of the CAA also
provides a mechanism for EPA 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 the 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 20460, with a
copy to the person listed in the preceding FOR FURTHER GENERAL
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.
AFPC Association of Fertilizer and Phosphate Chemists
AOD argon-oxygen decarburization
API American Petroleum Institute
ASTM American Society for Testing and Materials
C&D construction and demolition
CAA Clean Air Act
CaO calcium oxide
CBI confidential business information
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CH4 methane
CKD cement kiln dust
CO2 carbon dioxide
DE destruction efficiency
DOC degradable organic carbon
EAF electric arc furnace
EF emission factor
EIA Energy Information Administration
EPA U.S. Environmental Protection Agency
FR Federal Register
GHG greenhouse gas
HHV higher heating value
ID identification
kg kilograms
lb pound
LNG liquefied natural gas
LMPs lime manufacturing plants
MCF Methane Correction Factor
MgO magnesium oxide
Mscf thousand standard cubic feet
MSW municipal solid waste
MSWLF municipal solid waste landfill
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NOX nitrogen oxides
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
QA/QC quality assurance/quality control
RCRA Resource Conservation and Recovery Act
RFA Regulatory Flexibility Act
SBREFA Small Business Regulatory Enforcement Fairness Act
SWDS solid waste disposal site
TSCA Toxic Substances Control Act (TSCA)
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VOD vacuum oxygen decarburization
Table of Contents
I. Background
A. How is this preamble organized?
B. Background on This Action
C. Legal Authority
D. How will these amendments apply to 2011 reports?
II. Final Amendments and Responses to Public Comments
A. Mobile Sources
B. Subpart A--General Provisions
C. Subpart E--Adipic Acid Production
D. Subpart H--Cement Production
E. Subpart K--Ferroalloy Production
F. Subpart N--Glass Production
G. Subpart O--HCFC-22 Production and HFC-23 Destruction
H. Subpart P--Hydrogen Production
I. Subpart Q--Iron and Steel Production
J. Subpart S--Lime Manufacturing
K. Subpart V--Nitric Acid Production
L. Subpart Z--Phosphoric Acid Production
M. Subpart CC--Soda Ash Manufacturing
N. Subpart EE--Titanium Dioxide Production
O. Subpart GG--Zinc Production
P. Subpart HH--Municipal Solid Waste Landfills
R. Subpart MM--Suppliers of Petroleum Products
S. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
III. 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. How is this preamble organized?
The first section of this preamble contains the basic background
information about the origin of these rule amendments. This section
also discusses EPA's use of our legal authority under the CAA to
collect data under the mandatory GHG reporting rule.
The second section of this preamble describes in detail the rule
changes that are being promulgated to correct technical errors, to
provide clarification, and to address implementation issues identified
by EPA and others. This section also presents a summary and EPA's
response to the major public comments submitted on the proposed rule
amendments, and significant changes, if any, made since proposal in
response to those comments.
Finally, the last (third) section of the preamble discusses the
various statutory and executive order requirements applicable to this
final rulemaking.
B. Background on This Action
The final Mandatory Reporting of Greenhouse Gases Rule (40 CFR part
98 or Part 98) was signed by EPA Administrator Lisa Jackson on
September 22, 2009 and published in the Federal Register on October 30,
2009 (74 FR 56260, October 30, 2009). Part 98, which became effective
on December 29, 2009, included reporting of greenhouse gas (GHG)
information from facilities and suppliers, consistent with the 2008
Consolidated Appropriations Act.\1\ These source categories capture
approximately 85 percent of U.S. GHG emissions through reporting by
direct emitters as well as suppliers of fossil fuels and industrial
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gases and manufacturers of mobile sources.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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EPA published a notice proposing amendments to Part 98 to, among
other things, correct certain technical and editorial errors that have
been identified since promulgation and clarify or propose amendments to
certain provisions that have been the subject of questions from
reporting entities. The proposal was published on June 15, 2010 (75 FR
33950). The public comment period for the proposed rule amendments
ended on July 30, 2010. EPA did not receive any requests to hold a
public hearing.
In addition to the notice published on June 15, 2010 (75 FR 33950),
EPA published a second proposal on August 11, 2010 (75 FR 48744). The
second notice proposed to correct certain technical and editorial
errors in Part 98 that were identified since promulgation and clarify
or propose amendments to certain provisions that were the subject of
questions from reporting entities, primarily to subparts not addressed
in the June 15, 2010 proposal. The August 11, 2010 proposal complements
the proposal published on June 15, 2010.
C. Legal Authority
EPA is promulgating these rule amendments under its existing CAA
authority, specifically authorities provided in CAA sections 114 and
208.
As stated in the preamble to the final Part 98 (74 FR 56260), CAA
sections 114 and 208 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 preamble to the initial proposed Part 98 (74 FR 16448,
April 10, 2009) CAA section 114(a)(1) authorizes the Administrator to
require emissions sources, persons subject to the CAA, manufacturers of
process or control equipment, and 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 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. For further
information about EPA's legal authority, see the preambles to the
proposed and final Part 98.\3\
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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 vehicles and motor vehicle engines, CAA section 208
authorizes the gathering of information related to those areas.
\3\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30,
2009).
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D. How will these amendments apply to 2011 reports?
With two exceptions, we have determined that it is feasible for
reporters to implement these changes for the 2010 reporting year
because the revisions primarily provide additional clarifications
regarding the existing regulatory requirements, generally do not affect
the type of information that must be collected and do not substantially
affect how emissions are calculated. Our rationale for this
determination is explained in the preamble to the proposed rule
amendments.\4\
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\4\ 75 FR 33952-33953 (June 15, 2010).
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In summary, these amendments, with the two exceptions described
below, do not require any additional monitoring or information
collection above what was already included in Part 98. Therefore, we
have determined that reporters can use the same information that they
have been collecting for each subpart to calculate and report GHG
emissions for 2010 and submit reports in 2011 under the amended
subparts.
The first exception is for reporting CO2 emissions from
certain types of decarburization vessels at iron and steel sources
under subpart Q. EPA has determined, based on public comments, that it
is necessary to allow a delay in reporting from certain decarburization
vessels until the 2011 data collection year (and the subsequent annual
GHG emissions reports submitted to EPA by March 31, 2012). The delay in
implementation was determined to be necessary because although the 2009
final rule was clear that emissions from argon oxygen-decarburization
vessels were required to be reported, the inclusion of other types of
decarburization vessels was not clear. A more detailed description of
the affected decarburization vessels and our rationale is available in
Section II.I of this preamble.
The second exception is related to crude oil reporting requirements
in subpart MM. We are providing reporters some flexibility in defining
a batch of crude oil for purposes of reporting crude oil data for
reporting year 2010. A more detailed description of the type of
flexibility we are providing and our rationale is available in Section
II.R of this preamble. EPA notes that crude oil data does not impact
the CO2 calculations for 2010 or for any other reporting
year.
II. Final Amendments and Responses to Public Comments
We are amending 40 CFR part 86 to appropriately incorporate the
regulatory text into the regulations at 40 CFR 86.1844-01.
In 40 CFR Part 98, we are amending various subparts to correct
errors in the regulatory language that were identified as a result of
working with affected industries to implement the various subparts of
Part 98. We are also amending certain rule provisions to provide
greater clarity. The amendments to 40 CFR Part 98 include the following
types of changes:
Changes to correct cross references within and between
subparts.
Additional information to better or more fully
understand compliance obligations in a specific provision, such as
the reference to a standardized method that must be followed.
Amendments to certain equations to better reflect
actual operating conditions.
Corrections to terms and definitions in certain
equations.
Corrections to data reporting requirements so that they
more closely conform to the information used to perform emission
calculations.
Other amendments related to certain issues identified
as a result of working with the reporters during rule implementation
and outreach.
The final amendments promulgated by this action reflect EPA's
consideration of the comments received on the proposal. The major
public comments and EPA's responses for each subpart are provided in
this preamble. Our responses to additional significant public comments
on the proposal are presented in a comment summary and response
document available in Docket ID No. EPA-HQ-OAR-2010-0109.
A. Mobile Sources
1. Summary of Final Amendments and Major Changes Since Proposal
Manufacturers of highway heavy-duty vehicles, as well as
manufacturers of highway heavy-duty engines, are subject to GHG
reporting requirements. EPA inadvertently omitted the regulatory text
covering manufacturers of highway heavy-duty vehicles. We are amending
40 CFR part 86 to correct that error by incorporating the appropriate
language into the regulations at 40 CFR 86.1844-01.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to 40
CFR
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part 86 and is finalizing the amendments as proposed.
B. Subpart A--General Provisions
1. Summary of Final Amendments and Major Changes Since Proposal
We are adding and changing several definitions to subpart A to
clarify terms used in other subparts of Part 98. Similarly, we are
amending 40 CFR 98.7 (incorporation by reference) to accommodate
changes in the standard methods that are allowed by other subparts of
Part 98.
We are amending the following definitions in 40 CFR 98.6:
Carbonate-based mineral.
Carbonate-based mineral mass fraction.
Carbonate-based raw material.
Crude oil.
Decarburization vessel.
Gas collection system or landfill gas collection system.
Mscf.
Non-crude feedstocks.
We are amending the definitions of ``carbonate-based mineral,''
``carbonate-based mineral mass fraction,'' and ``carbonate-based raw
material'' in order to include barium carbonate, potassium carbonate,
lithium carbonate, and strontium carbonate, because these carbonates
are consumed in the glass industry subject to subpart N.
We are amending the definition of ``crude oil'' in 40 CFR 98.6 so
that it is consistent with the definition in the Energy Information
Administration's (EIA) Definitions of Petroleum Products and Other
Terms (Revised January 2010) \5\, with one additional provision to
accommodate the needs of this program to ensure complete reporting of
petroleum products, including the unique circumstances that have been
raised in comments. We are adding a crude oil reporting requirement in
subpart MM (40 CFR 98.396 (a)(22)) to accommodate this provision.
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\5\ http://www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/psmdefs_2010.pdf.
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We are amending the definition of ``decarburization vessel'' in 40
CFR 98.6 to include vessels that are used to further refine molten
steel with the primary intent of reducing the carbon content of the
steel.
We are amending the definition of ``gas collection system or
landfill gas collection system,'' in 40 CFR 98.6 to clarify that the
passive vents/flares are not considered part of a landfill gas
collection system for purposes of subpart HH, to state that such a
system collects gas actively by means of a fan or similar mechanical
draft equipment, versus collecting gas passively. Based on a comment
received, we are also clarifying that a single landfill may have more
than one gas collection system.
We are also amending the definition of ``Mscf'' in 40 CFR 98.6 to
indicate that ``Mscf'' means thousand standard cubic feet.
We are also amending the definition of ``non-crude feedstocks'' in
40 CFR 98.6 to remove the phrase ``as a feedstock'' in order to avoid
confusion with the definition of ``feedstock.'' Under subpart MM,
refiners must calculate annual CO2 emissions that would
result from the complete combustion or oxidation of each non-crude
feedstock. Our intention in subpart MM is to capture all petroleum
products and natural gas liquids that enter a refinery to be further
refined or otherwise used on site. By removing the term ``as a
feedstock'' from the definition of ``non-crude feedstocks'' we are
aligning the definition to the original intent of subpart MM.
We are also incorporating by reference ASTM D6349-09, ``Standard
Test Method for Determination of Major and Minor Elements in Coal,
Coke, and Solid Residues from Combustion of Coal and Coke by
Inductively Coupled Plasma--Atomic Emission Spectrometry'' for subpart
N.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments (see EPA-HQ-OAR-2010-0109).
In the definitions of ``carbonate-based mineral,''
``carbonate-based mineral mass fraction,'' and ``carbonate-based raw
material,'' adding lithium carbonate and strontium carbonate, as
well as the proposed additions of barium carbonate and potassium
carbonate.
Expanding the proposed definition of crude oil to
include petroleum products injected into a crude supply or
reservoir.
Narrowing the definition of decarburization vessel to
include only vessels for which the primary intent is reducing the
carbon content of the steel.
Incorporating by reference ASTM D6349-09, ``Standard
Test Method for Determination of Major and Minor Elements in Coal,
Coke, and Solid Residues from Combustion of Coal and Coke by
Inductively Coupled Plasma--Atomic Emission Spectrometry'' for
subpart N.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments (see
EPA-HQ-OAR-2010-0109).
Comment: One commenter responded to EPA's question regarding
whether other carbonates not listed in the proposed definitions are
consumed in glass production, and the commenter noted that they consume
lithium carbonate and strontium carbonate.
Response: EPA appreciates the clarification and has added these
carbonates to the definitions of carbonate-based materials in 40 CFR
98.6 and to Table N-1 to subpart N.
Comment: EPA received several comments on our proposal to amend the
definition of crude oil. Two commenters supported the proposed
definition of crude oil because it is identical to the definition used
for reporting to the Energy Information Administration (EIA) and it
will be easier for reporters to calculate and report the same data for
both agencies' crude oil reporting requirements. One commenter
suggested that EPA expand it even further by adding the word
``nitrogen'' to describe non-hydrocarbons, referencing atmospheric
conditions rather than just atmospheric pressure, removing the
requirement that hydrocarbon liquids must be comingled with a crude
stream, and including natural gas processing plant liquids captured by
gravity separation. Therefore, the commenter did not support using a
definition of crude oil that is identical to the definition used by
EIA. Two commenters submitted information about situations where a
petroleum product is re-injected into a crude supply line or back into
a reservoir. One of these two commenters reported that they inject a
mixture of products, some of which meet the proposed definition of
crude and some of which do not, and specifically requested
clarification on how to treat such a mixture with respect to crude oil
and petroleum product reporting.
Response: In today's final rule, EPA is retaining the amendatory
text proposed for the definition of crude oil and making amendments
beyond what was proposed to address the comments received and improve
technical accuracy.
EPA agrees with commenters that a definition of crude oil for Part
98 that is identical to the EIA definition makes it easier for
refineries to comply with both agencies' reporting requirements.
However, EPA considered comments requesting amendments to the crude oil
definition in an effort to ensure the definition is technically
accurate and to allow for complete reporting.
[[Page 66438]]
EPA considered including natural gas processing plant liquids
captured by gravity separation in the crude oil definition, but
concluded that doing so would create ambiguity in the regulatory text.
EPA has always required natural gas liquids (NGLs) received by the
refinery to be reported as non-crude feedstock because the vast
majority is being reported by fractionators as product supplied under
subpart NN, and EPA does not want these volumes to be double counted
across the industry. Because refiners would be unable to physically
distinguish NGLs from gravity separation from NGLs reported as product
by fractionators under subpart NN, EPA does not concur that such an
edit is an improvement to the proposed definition and has not made the
suggested change in the definition.
EPA agrees with the comment that specifying atmospheric conditions
(temperature and pressure), rather than just atmospheric pressure, is
technically more accurate and has made this change in the final
definition. This change allows for conditions under which liquids may
drop out because of lower temperatures that may not have dropped out in
warmer temperatures and atmospheric pressure. EPA has concluded that
adding ``nitrogen'' as an example of non-hydrocarbons does not improve
technical accuracy and is not necessary since it is clear that nitrogen
is a non-hydrocarbon. Therefore, EPA has not made this change to the
final definition.
EPA considered removing the qualification that hydrocarbon liquids
must be comingled with a crude stream to meet the crude oil definition
and concluded that removing that qualification would create ambiguity.
EPA determined that it may be difficult for refineries to distinguish
between such hydrocarbon liquids (which commenters suggested should be
treated as crude oil) and natural gas liquids or petroleum products
(which EPA required be treated as non-crude feedstock) when received
and to, therefore, determine how to comply with the rule. EPA has
concluded that we cannot delete such text from the crude oil definition
unless we specifically seek comment on the impact of such a revision to
reporters. Therefore, such an amendment is outside of the scope of this
rulemaking.
Finally, EPA is expanding the proposed definition of crude oil to
include petroleum products that are received or produced at a refinery
and subsequently injected into a crude supply or reservoir by the same
refinery owner or operator. EPA is making this addition because, in
these situations, petroleum products will be comingled with crude oil
to the point of being indistinguishable from crude oil. Whenever a
refinery receives the comingled crude oil downstream they will report
it as crude oil to EPA. Therefore, this addition is needed to prevent
double-counting among reporters under subpart MM. EPA has concluded
that the additions to the definition beyond what is used by EIA will
only apply to a small minority of refineries that face the unique
circumstances presented by commenters and that all other refineries
will be able to report to EPA according to the same definition that
they use to report to EIA.
With this amendment in place, EPA will need data on the volume
injected into a crude supply or reservoir from this small minority of
refineries in order to conduct effective verification on the full set
of data submitted under subpart MM. Therefore, we are making a
harmonizing amendment to subpart MM to require reporting on the volume
of any crude oil injected into a crude supply or reservoir under a new
paragraph 40 CFR 98.396(a)(22).
Comment: One commenter noted that the Phosphate Mining States
Methods Used and Adopted by the Association of Fertilizer and Phosphate
Chemists (AFPC) Manual 10th Edition--Version 1.9 had been updated to
the version 1.92, which includes a protocol for collecting grab samples
of phosphate rock to be tested for chemical composition.
Response: EPA agrees that it is important to allow phosphoric acid
facilities to follow the latest standard protocol for grab samples of
phosphate rock. In light of this, EPA has finalized requirements to use
an industry consensus standard or industry standard practice for
collecting grab samples. As an example, the Association of Fertilizer
and Phosphate Chemists (AFPC) Manual 10th Edition--Version 1.92 and
future versions of that manual would be an acceptable standard.
C. Subpart E--Adipic Acid Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending Equation E-1, Equation E-2 and Equation E-3 in 40
CFR 98.53. First, we are amending these equations so that the
calculation equations are internally consistent. Currently, the
equations do not correctly address situations in which a facility has
more than one production unit or process line with separate
N2O control or abatement technology on the separate
production units or process lines, and the technologies are not
operated 100 percent of the time. In these circumstances, the current
equations will not provide an accurate calculation of N2O
emissions. We are amending the equations so that emissions are
calculated separately for each production unit or process line (or
groups of units or lines) that has a separate control or abatement
technology, and then the emissions for all such units or lines are
summed to determine the overall N2O emissions for the
facility. For consistency with these amendments, we are also amending
40 CFR 98.54(a), 98.56(j), and 98.57(c) for monitoring and QA/QC,
reporting, and recordkeeping, respectively.
We are amending 40 CFR 98.53(b)(1) to address performance testing
when a group of adipic acid production units share a common abatement
technology or emission point.
We are amending Equation E-3 of subpart E to accommodate
N2O abatement technology located after the emission test
(sampling) point and re-designating it as Equation E-3a of subpart E.
There are three ways in which abatement technology can be employed.
Equation E-3a of subpart E is for one N2O abatement
technology. We are amending Equation E-3a of subpart E further so that
the annual adipic acid produced by adipic acid unit ``z''
(Pz) is used rather than annual adipic acid produced by
unit(s) for which N2O abatement technology ``N'' is
operating (Pa,N). Also, the summation was removed.
We are adding Equation E-3b of subpart E to accommodate multiple
N2O abatement technologies in series and we are adding
Equation E-3c of subpart E to accommodate multiple N2O
abatement technologies in parallel. We are also adding a new Equation
E-3d of subpart E for facilities that do not have any N2O
abatement technology located after the test (sampling) point.
We are adding Equation E-4 of subpart E to sum the emissions from
Equations E-3a through E-3d of subpart E for each adipic acid
production unit ``z''.
We are amending the language in 40 CFR 98.54(a)(3) and 98.56(k)
regarding the Administrator approved alternative method to clarify that
this alternative method is for determining N2O emissions
rather than N2O concentration. Also, we are amending the
language in 40 CFR 98.54(a)(1), (e) and (f) to clarify the location of
the test (sampling) point used for the performance test and to clarify
that the performance test should be conducted when the process is
operating normally. As promulgated, the language can be
[[Page 66439]]
misconstrued that EPA is requiring the facility to shut down any
N2O abatement technology during the performance testing.
This was not intended because many, if not all, of the N2O
abatement technologies in use must be operated at all times that the
adipic acid facility is operated to control emissions of NOX
in order to comply with state and federal regulations limiting
NOX emissions. The amendments clarify that testing can occur
before or after N2O abatement technology as long as the
destruction efficiency of the N2O abatement technology is
properly accounted for and adipic acid production is quantified while
abatement equipment is operating. Finally, we are clarifying under 40
CFR 98.57(f) that facilities should retain records of all data
collected during performance tests, not just the calculated emission
factor. This clarification is consistent with the general recordkeeping
requirements in 40 CFR 98.3(g)(2)(ii).
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments (see EPA-HQ-OAR-2010-0109).
Language was added to 40 CFR 98.53(b)(1) to address
performance testing when multiple adipic acid production units
exhaust to a common emission point.
Changed the emission factor in Equation E-1 of subpart
E from EFN2O,N to
EFN2O,z to eliminate confusion.
Changed the description of the emission factor,
EFN2O,z from ``Average facility-specific
N2O emission factor for each adipic acid production unit
(lb N2O generated/ton adipic acid produced)'' to
``Average facility-specific N2O emission factor for each
adipic acid production unit ``z'' (lb N2O/ton adipic acid
produced).''
Changed the terms ``waste gas stream'' and ``air
stream'' to ``vent stream'' at 40 CFR 98.53(b)(1) and 98.53(g)(1).
Edited Equation E-1 and Equation E-3a of subpart E to
include changes above.
Added Equation E-3b, Equation E-3c, Equation E-3d and
Equation E-4 of subpart E.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments (see
EPA-HQ-OAR-2010-0109).
Comment: One commenter raised the issue that there are situations
where multiple adipic acid production units exhaust to a common
abatement technology or emission point and should be addressed during
the performance test.
Response: EPA has added language at 40 CFR 98.53(b)(1) to address
performance testing for a group of adipic acid production units
exhausting to a common abatement technology or emission point and for
other possible situations that were not accurately addressed by the
proposed Equation V-3a of subpart V (abatement technologies used in
series and backup abatement technologies operated periodically. We are
aware of at least one facility where multiple units exhaust through a
common abatement technology.
Comment: One commenter suggested that the subscript letter ``N'' in
the term EFN2O,N used in Equation E-1 of subpart
E be explained and changed to avoid confusion with the term ``N'' in
Equations E-2 and E-3a. The commenter also suggested that the word
``generated'' be struck from the definition of EF
N2O,N in Equation E-1 of subpart E to reflect
that the emission factor may now be determined either before or after
abatement. If measured after abatement, EFN2O,N
represents the controlled emission rate instead of the amount of
N2O generated. The commenter suggested a similar
change to Equations E-3a and E-3b of subpart E where the terms
EFN2O,N and EFN2O
respectively, are used.
Response: EPA agrees that the subscript letter ``N'' in the term
EFN2O,N used in Equation E-1 of subpart E could
be confused with the term ``N'' used in Equations E-2 and E-3a of
subpart E. Therefore, the subscript ``N'' has been changed to subscript
``z'' in Equation E-1 of subpart E. EPA also agrees that
EFN2O,N represents the controlled emission rate
instead of the amount of N2O generated, if the
test point is located after the abatement technology. Therefore, the
definition of EFN2O,z has been revised to be the
average facility-specific N2O emission factor for
each adipic acid production unit ``z'', in units of lb
NN2O/ton adipic acid produced.
EPA also removed the word ``generated'' in Equations E-3a and E-3b
of subpart E for the definitions of the terms
EFN2O,N and EFN2O,
respectively.
Comment: One commenter agreed with the proposed amendments to
correctly calculate emissions in which an abatement technology is not
operated 100 percent of the time. The commenter requested that
additional changes be made to Equation E-3a in 40 CFR 98.53(g)(1). The
commenter suggested the use of Pa (annual adipic acid
produced for unit a) instead of PaN (annual adipic acid
produced by unit(s) for which N2O abatement
technology ``N'' is operating), and noted that the summation over the
range of 1 to N should include only the term (1-
(DFN*AFN)), to accurately represent the effect of
multiple abatement devices on each unit.
Response: EPA agrees that annual adipic acid produced from unit
``z'' (Pz) should be used rather than annual adipic acid
produced by unit(s) for which N2O abatement
technology ``N'' is operating (Pa,N). These changes have
been made in the final rule.
D. Subpart H--Cement Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.84(b) to correct the most recent ASTM
standard, to ASTM C114-09 rather than C114-07, for determining the
weight fraction of magnesium oxide (MgO) and calcium oxide (CaO) in
clinker. In addition we have learned through questions from reporters,
that for some facilities it is more efficient to sample clinker for the
weight fraction of total MgO and CaO as it exits the kiln rather than
from bulk storage. Some facilities do perform this analysis on clinker
on a daily basis. We are amending the rule to allow facilities the
option to determine a monthly value based on the arithmetic average of
the daily samples.
Through reporters we have also learned that facilities use direct
measurement in conjunction with other factors (e.g., kiln feed) to
determine clinker production. These procedures are verified
periodically for accuracy. We are amending 40 CFR 98.84(d) to allow
facilities to use these existing procedures for measuring clinker
produced and verify those on a monthly basis. Facilities are already
required to measure clinker on a monthly basis. Concurrent with this
change, we are amending 40 CFR 98.86(b) so that facilities that do not
estimate combined process and combustion emissions using continuous
emission monitoring systems (CEMS) will be required to report the kiln
specific feed-to-kiln ratios used to calculate clinker produced for EPA
verification of emissions associated with clinker production. For
consistency, we are clarifying 40 CFR 98.84(e) to allow similar
flexibility in determination of cement kiln dust produced.
Further, we understand from facilities' questions that an analysis
of the organic carbon contents of raw materials could be determined
from a composite sample of the kiln feed or from sampling each raw
material in the
[[Page 66440]]
kiln feed depending on the existing sampling methods and raw material
storage procedures at the facility. We are amending the calculation and
monitoring procedures in 40 CFR 98.83(d)(3) and 98.84(c) to allow
facilities the option to use either sampling procedure for estimating
carbon dioxide (CO2) emissions from raw materials.
We are also correcting and clarifying the recordkeeping
requirements under 40 CFR 98.87(a) and (b) for facilities with CEMS and
for facilities without CEMS. In Part 98, the recordkeeping requirements
listed under 40 CFR 98.87(a)(1) and (a)(2) should have been listed
under 40 CFR 98.87(b). Facilities using CEMS to estimate combined
process and combustion CO2 emissions from kilns do not need
to calculate process emissions using the clinker based emissions
methodology provided in Subpart H and, therefore, would not have the
relevant records requested in 40 CFR 98.87(a)(1) and (a)(2).
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments document (see EPA-HQ-OAR-2010-0109).
Clarifying the cement kiln dust (CKD) monitoring
requirements in 40 CFR 98.84(e);
Changing cement production reporting requirements under
40 CFR 98.86 to require annual, facility-wide cement production
instead of monthly, kiln-specific cement production; and
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments
document (see EPA-HQ-OAR-2010-0109).
Comment: One commenter expressed concern that the monthly
verification of the feed-to-clinker ratio, required under 40 CFR
98.94(d), is unduly burdensome. The commenter suggested that EPA change
subpart H to require quarterly verification instead of monthly.
Response: Because subpart H requires cement manufacturers to report
clinker production on a monthly basis, we are requiring facilities that
estimate clinker production using a feed-to-clinker ratio to verify the
accuracy of that ratio also on a monthly basis. We provided cement
manufacturers the option to use a feed-to-clinker ratio instead of
direct clinker measurement to provide flexibility and consistency with
current industry practices. We note the commenter's concern regarding
the burden of monthly verification. However, other industry comments
generally support this requirement.
Comment: One commenter stated that the CKD measurement requirements
under 40 CFR 98.84(e) should be revised to be consistent with the
clinker measurement requirements under 40 CFR 98.84(d). Specifically,
40 CFR 98.84(d) allows facilities to determine monthly clinker
quantities by either reconciling weigh hopper or belt weigh feeder
measurements against inventory measurements, or by direct weight
measurement of raw feed and applying a feed-to-clinker ratio.
Meanwhile, 40 CFR 98.84(e) requires facilities to determine quarterly
CKD quantities by direct weight measurement. The commenter points out
that the CKD quantity has a lesser impact on CO2 emission
calculations than the clinker quantity. Therefore, the rule should not
have more stringent measurement requirements for CKD than for clinker.
The commenter also states that direct weight measurement devices should
not be required to be installed if they are currently not being
utilized at the facility, and requests that facilities be permitted to
use the same methods currently in place for accounting purposes to
determine the quantity of CKD not recycled to the kiln.
Response: The rule currently allows for the type of flexibility
that the commenter is requesting. The rule lists direct weight
measurement as an example technique that may be used; however, the
examples provided in the rule are not an exhaustive list. Facilities
should determine the quantity of CKD not recycled to the kiln for each
kiln using the same plant techniques used for accounting purposes. We
have revised the language in 40 CFR 98.84(e) to clarify this
flexibility.
Comment: Two commenters noted that reporting requirements in 40 CFR
98.86(a)(2) and 98.86(b)(3) require cement manufacturers to report
monthly cement production from each kiln at the facility. The
commenters pointed out that cement kilns produce clinker--not cement.
The clinker from each cement kiln is subsequently sent to a mill and
pulverized into a fine powder, and mixed with other ingredients to
produce cement. Plants that operate multiple kilns may combine the
clinker from all kilns and store the combined clinker before feeding it
to the cement mill. Because of the variability of the amount of clinker
produced by different kilns, and the varying methods of storage, the
commenters proposed that EPA require cement manufacturers to report the
total quantity of cement produced by the facility on an annual rather
than monthly, kiln-specific basis.
Response: EPA agrees with the commenter that the requirements in 40
CFR 98.86(a)(2) and 98.86(b)(3) are inconsistent with cement plant
manufacturing practices, and should not be required on a kiln-specific
basis. In addition, we agree that due to the variations in storage time
between clinker production and cement production, cement production
data are not needed on a monthly basis. This reporting requirement was
added for verification of reported emissions, not calculating
emissions. Therefore, we have revised the rule to require facilities to
report cement production on an annual, facility-wide basis.
E. Subpart K--Ferroalloy Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.112(a) to be consistent with the
requirement described in 40 CFR 98.113(d) to calculate methane
(CH4) emissions from an electric arc furnace (EAF) used for
the production of all ferroalloys for which an applicable
CH4 emission factor is provided in the rule. These alloys
and the associated CH4 emission factors are listed in Table
K-1 to subpart K. Subpart K in Part 98 contained calculation and
reporting procedures for quantifying process CH4 emissions
from all ferroalloys listed in Table K-1 to subpart K, but
CH4 was inadvertently not included in the GHGs to Report
section.
We are also amending the introductory language for 40 CFR 98.113 to
clarify the applicability of the procedures for calculating
CO2 and CH4 emissions in that section. Finally,
we are amending the language in 40 CFR 98.116 to clarify that the data
reporting requirements in 40 CFR 98.116(b) are for each EAF and those
in 40 CFR 98.116(d)(1) and (e)(1) are for any ferroalloy product
identified in 40 CFR 98.110. We are also amending 40 CFR 98.116(d) to
correct an incorrect cross-reference to 40 CFR 98.36.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart K and is finalizing the amendments to this subpart as proposed.
[[Page 66441]]
F. Subpart N--Glass Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending subpart N to add CO2 emission factors to
Table N-1 to subpart N for barium carbonate, potassium carbonate,
lithium carbonate, and strontium carbonate. These raw materials were
not included in Part 98, but EPA has since learned that they are also
used by the glass industry. EPA is also amending 40 CFR 98.144(b) to
allow for an additional method for determining the carbonate mineral
mass fraction of raw materials used in glass production. Specifically,
in addition to ASTM D3682-01, reporters can also use ASTM D6349-09,
``Standard Test Method for Determination of Major and Minor Elements in
Coal, Coke, and Solid Residues from Combustion of Coal and Coke by
Inductively Coupled Plasma--Atomic Emission Spectrometry.'' We are also
amending the introductory language to 40 CFR 98.146(a) to correct an
incorrect cross-reference to 40 CFR 98.36 and to clarify in 40 CFR
98.146(a)(2) that reporting of glass production is by furnace and from
all furnaces combined, consistent with the calculation methods. We are
amending 40 CFR 98.146(b)(7) and (9) to correct typographical errors.
Major changes since proposal are identified in the following list.
The rationale for these changes can be found in this preamble.
Added an emission factor for lithium carbonate.
Added an emission factor for strontium carbonate.
Removed the requirement for analysis by an
``independent certified laboratory.'' When the final subpart N was
published on October 30, 2009, EPA agreed with commenters that
analyses do not have to be performed by an independent certified
laboratory, but this language inadvertently remained in subpart N.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. One comment letter was received on this subpart.
Comment: One commenter asked that emission factors for lithium
carbonate and strontium carbonate be added to subpart N, in addition to
those being added for barium carbonate and potassium carbonate.
Response: EPA has added these two compounds to the final subpart N.
EPA was not previously aware of use of these carbonates in glass
production in the United States during the initial proposal of the
rule. While less common, these carbonates are used in glass production
to add different properties to glass products and EPA therefore agrees
that these emission factors should be included in the final rule.
G. Subpart O--HCFC-22 Production and HFC-23 Destruction
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.154(k), the requirement to monitor HFC-23
emitted from process vents, to refer to Equation O-7 of subpart O
rather than Equation O-6 of subpart O. In 40 CFR 98.154(k), (l), and
(o) and in 40 CFR 98.156(b), we are amending the language so that the
term ``destruction device'' is used rather than the narrower term
``thermal oxidizer.''
We are amending the reporting requirements in 40 CFR 98.156(c) and
(d) to clarify that only facilities that are required to recalculate
the destruction efficiency of their destruction device under 40 CFR
98.154(l) must report the flow rate of HFC-23 being fed into the
destruction device, the flow rate at the outlet of the destruction
device, and the emission rate of the device. In addition, such
facilities will be required to report the newly calculated DE of the
device, the HFC-23 concentration measurement used in the DE
calculation, and whether 40 CFR 98.154(l)(1) or (l)(2) was used for the
calculation. Under these two paragraphs, other HFC-23 destruction
facilities will be required to report only the results of their annual
measurement of the HFC-23 concentration at the outlet of the
destruction device.
We are amending the reporting requirements in 40 CFR 98.156(e) to
clarify that the one-time report for HFC-23 destruction facilities is
due by March 31, 2011 or within 60 days of commencing HFC-23
destruction. The amendment was necessary because it was not clear when
the one-time report must be submitted. The amendment will make the due
date in 40 CFR 98.156(e) consistent with the due date for a similar
report required in Subpart OO.
In general, these amendments to the reporting requirements for HFC-
23 destruction facilities make them consistent with the monitoring
requirements for these facilities. The due dates for the one-time
report are consistent with those elsewhere in Part 98 for the source
categories that are required to begin monitoring in 2010.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart O and is finalizing the amendments to this subpart as proposed.
H. Subpart P--Hydrogen Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the definition of the source category in 40 CFR
98.160(c) to clarify that hydrogen production facilities located within
other facilities are also included in the source category if they are
not owned by, or under the direct control of, the other facility's
owner and operator. This clarification was necessary to correct a
misunderstanding that the original rule text limited the source
universe to hydrogen production facilities located within petroleum
refineries.
Broadly, we are amending subpart P to remove several references to
``process'' CO2 emissions. EPA received information from
industry indicating that the use of the term ``process'' in the context
of calculating and reporting CO2 emissions resulted in
confusion in differentiating between process and combustion emissions.
We are clarifying the text in the rule by removing references to the
term ``process'' from the rule language.
We are removing the requirements in 40 CFR 98.162(b) for owners or
operators to report CO2, CH4 and N2O
combustion emissions from each hydrogen production process unit using
the emissions calculation methods in subpart C. This provision results
in double counting of combustion-related emissions from hydrogen
production process units, as these combustion emissions are already
accounted for when following the calculation methods in 40 CFR
98.163(a) or (b). CO2 emissions will still be reported under
40 CFR 98.162(a) using the procedures in 40 CFR 98.163(a) or 98.163(b).
We are also amending language describing the calculation of GHG
emissions from gaseous, liquid and solid fuels and feedstocks in 40 CFR
98.163. The clarified language specifies that each gaseous, liquid or
solid fuel and feedstock will need to be calculated based on its
respective equations detailed in the rule language. This removes the
concern that the language was unclear as to which fuel and feedstock
stream should be used to calculate CO2 emissions.
Lastly, we are amending 40 CFR 98.166(c) to strike ``quarterly''
and ``kg'' (kilogram). Some facilities subject to subpart P may also be
subject to subpart PP--Suppliers of Carbon Dioxide. Quarterly reporting
of CO2 quantities (in kilograms) was not consistent with
subpart PP.
[[Page 66442]]
2. Summary of Comments and Responses
All comments received on the proposed amendments to subpart P were
supportive and EPA is finalizing the amendments to this subpart as
proposed.
I. Subpart Q--Iron and Steel Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the subpart Q requirements regarding emissions from
flares to clarify the requirements and correct certain deficiencies in
the rule pertaining to flares burning off-gases from argon-oxygen
decarburization (AOD) and other decarburization processes. Section
98.172(b) of Part 98 required reporting of CO2 emissions
from flares using procedures from subpart Y (Petroleum Refineries),
without distinguishing flares burning off-gases from AOD or other
decarburization processes from other types of flares.
The referenced equations in subpart Y and the further instructions
in 40 CFR 98.172(b) are applicable to estimating emissions from burning
coke oven gas or blast furnace gas, but are not applicable for
estimating emissions from flares burning the off-gases from AOD or
other decarburization processes. We are, therefore, amending the
language in 40 CFR 98.172(b) to clarify that for subpart Q facilities,
flare emissions must be estimated for flares burning blast furnace gas
or coke oven gas. Similarly, we are amending the introductory text in
40 CFR 98.175 to specify that the missing data procedures in subpart Y
(Petroleum Refineries) at 40 CFR 98.255(b) must be followed for flares
burning coke oven gas or blast furnace gas. We are also amending the
introductory text for the data reporting requirements in 40 CFR 98.176
to include flares burning coke oven gas or blast furnace gas.
Subpart Q in Part 98 also referenced incorrect equations from
subpart Y. We are amending and correcting the references in 40 CFR
98.172(b) to the subpart Y flare equations. Equations Y-2 and Y-3 of
subpart Y are the correct equations; the promulgated subpart Q of
subpart Q incorrectly referenced Equation Y-1 of subpart Y.
We are amending the reporting requirements in 40 CFR 98.176(e)(3)
to clarify that fuel consumption needs to be reported separately for
each type of fuel and other process input and output material. We are
also adding paragraphs (g) and (h) to 40 CFR 98.176. Paragraph (g)
requires facilities to report the annual amount of coal charged to coke
ovens because it is used to estimate CO2 emissions from coke
pushing. Paragraph (h) incorporates the same reporting requirements
specified in 40 CFR 98.256(e) of subpart Y (Petroleum Refineries) for
flares burning coke oven gas or blast furnace gas.
We are amending the recordkeeping requirements in 40 CFR 98.177(d)
to clarify the units and processes for which annual operating hours
need to be recorded.
We are also amending the requirements in the promulgated rule to
estimate GHG emissions from AOD vessels to clarify that they also apply
to any other type of vessel used with the primary intent of removing
carbon from molten steel (decarburization), such as vacuum oxygen
decarburization. Because of the clarification noted above to include
all types of decarburization vessels used primarily to remove carbon,
we are replacing the term ``argon-oxygen decarburization vessels'' with
the term ``decarburization vessels'' throughout subpart Q and replacing
the definition of ``argon-oxygen decarburization vessels'' with a
definition for ``decarburization vessels'' in order to maintain
reporting of the CO2 emissions from these vessels.
In response to comments, we are clarifying the definition of
``decarburization vessels'' to include only those decarburization
vessels, such as AOD and vacuum oxygen decarburization vessels, used
with the primary intent of removing carbon from the steel. We are also
delaying the reporting of GHG emissions from decarburization vessels
that are not AOD vessels until reports submitted in 2012, instead of
requiring reporting with the first reports submitted to EPA in March
2011.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments document (see EPA-HQ-OAR-2010-0109).
Clarifying the definition of ``decarburization
vessels'' to include only those decarburization vessels used with
the primary intent of removing carbon from the steel.
Delaying the reporting of GHG emissions from
decarburization vessels that are not AOD vessels until reports
submitted in 2012.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments
document (see EPA-HQ-OAR-2010-0109).
Comment: We received three comments on our proposal to clarify the
definition of decarburization vessels to include all decarburization
vessels rather than just argon-oxygen decarburization (AOD). Two
commenters noted that the proposal was not merely a technical
correction or clarification, but was instead a substantive change to
subpart Q as promulgated. According to the commenters, the new
definition of decarburization vessel, which includes a list of the
covered processes and the phrase ``or other decarburization vessels,''
was too broad and inclusive. The commenters noted that most steel
plants, whether integrated or electric arc furnace producers, employ
several different kinds of refining processes to improve the quality of
the steel produced, and some of these refining processes, such as AODs,
are primarily intended to reduce carbon. However, the commenters stated
that other processes, such as vacuum degassing, electro-slag remelting,
and vacuum-arc remelting, are primarily intended to reduce dissolved
gases such as hydrogen, nitrogen, and oxygen in the molten steel, and
carbon reduction is only incidental. According to the commenters,
making these processes subject to subpart Q would require facilities to
make numerous adjustments to their monitoring plans and conduct
additional sampling. For these reasons, the commenters believe that the
proposed amendment would add significant new requirements and represent
a substantive change rather than being merely a clarification. One
commenter argued that the time and effort to verify GHG emissions from
vacuum degassing would be burdensome, estimating that it would increase
the resources needed to comply with subpart Q by 50 percent. The
commenter stated that the added burden of data collection,
measurements, recordkeeping, and reporting of these emissions is not
justified by the addition of vacuum degassing and other refining
operations to the reporting requirements.
Two of the commenters estimated that the additional processes
included in the proposed amendment contribute ``substantially less than
1 percent'' of the emissions from the sector. Another commenter
estimated they contributed only 0.02 percent of the emissions. The same
commenter argued that because these emissions are relatively
[[Page 66443]]
insignificant and would be extremely difficult to quantify for
reporting purposes, they should continue to be excluded from reporting
obligations. The commenter also rejected the rationale that emissions
from all decarburization vessels should be reported because EPA is also
proposing to limit reporting of emissions from flares to those burning
coke oven gas or blast furnace gas only (an amendment that the
commenter supports), which would obviate reporting of vacuum degasser
flare emissions. The commenter estimated that the emissions are so low
they would be difficult to detect, and measuring such emissions through
either the carbon-mass balance approach or a site-specific emission
factor would be burdensome and potentially infeasible. The commenter
concluded that EPA has not provided a rational basis for inclusion of
decarburization vessels within the GHG Reporting Program.
Two commenters recommended that if EPA proceeds by adding a
definition for ``decarburization vessel,'' the definition should be
revised. One commenter suggested that the definition be clarified such
that it includes only vessels for which the primary purpose is
decarburization. The other commenter asked that it be revised to read
``any vessel used to further refine molten steel with the primary
intent of reducing carbon content of the steel that also requires
flaring the off-gas to oxidize CO to CO2.''
All three commenters stated that if EPA chooses to include all
decarburization vessels as proposed, they should not be included in the
reports submitted to EPA in 2011. Two commenters explained that making
this change retroactive to data collection in 2010 is untenable because
companies were obligated to develop comprehensive GHG Monitoring Plans
in early 2010 and to begin recordkeeping in January 2010 in order to be
able to report for the entire 2010 reporting year by March 2011.
One commenter stated that by expanding the decarburization vessel
definition in Subpart Q to include vacuum degassing and other refining
operations beyond AODs, facilities with these operations will need to
make adjustments to their monitoring plans, conduct additional sampling
of inputs and outputs for these operations, make programmatic
modifications to tracking software, and re-train employees. The
commenter claimed that it will be impossible to collect the necessary
samples of steel and dust or sludge and perform analyses representative
of the months that have elapsed since the beginning of 2010 in order to
perform a mass balance, and it is also unrealistic to expect companies
to consider the option of establishing a site-specific emission factor
for these units because of all of activities that would be required to
perform testing. The commenter recommended that EPA follow the course
set in its July 12, 2010 final rule notice adding four new source
categories to Part 98 (75 FR 39735). The commenter said that EPA
recognized in that notice that it would be unrealistic to require those
operations to report emissions for 2010 and made these new rules
effective with the data collection in 2011.
Two commenters recommended that if EPA proceeds with the proposed
changes, those requirements should be effective no sooner than 2011 and
should be reportable in March 2012. One commenter argued that by
amending a rule to include data acquisition and management after a
reporting period has already begun is arbitrary and capricious and will
significantly add to the burden the regulated community faces when
attempting to collect meaningful data. The commenter stated that any
such amendment should be prospective in nature and not impact
calculations and sampling already underway.
Response: After consideration of these comments, we agree that the
proposed new definition of ``decarburization vessels'' was too broad
and would include certain steel refining processes that were not
intended (i.e., those whose primary purpose is not removal of carbon).
Some of the additional processes cited by the commenters have a primary
purpose to remove dissolved gases, and although some carbon may be
incidentally removed, the CO2 emissions from these processes
are a small percent of total GHG emissions from iron and steel making.
Because the change in carbon content of the steel is so small, it is
difficult to accurately quantify the emissions by a carbon balance, and
it is problematic to measure them because of the sampling and other
difficulties mentioned by the commenters. Consequently, we are revising
the definition of ``decarburization vessels'' to include those for
which the primary purpose is removal of carbon, including but not
limited to AOD and vacuum oxygen decarburization (VOD). We are not
adding the suggested revision that the definition should include only
those decarburization vessels equipped with flares because not all AOD
and VOD vessels are equipped with flares. The revised definition makes
the amendment a technical clarification that is more consistent with
the final rule as originally promulgated.
We also agree that additional time would be required to gather the
data to report emissions from decarburization vessels other than AOD
vessels, and we are amending the reporting requirements so that these
emissions are reported beginning in March 2012 for the year 2011.
However, the final amendments will not require a delay in the reporting
period for AOD vessels because facilities with AOD vessels have known
since the original promulgation of subpart Q that these decarburization
vessels would be included in the reporting for 2010.
J. Subpart S--Lime Manufacturing
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the cross reference to 40 CFR 98.193(b)(1) in the
introductory language to 40 CFR 98.195; it incorrectly referenced 40
CFR 98.193(b)(2).
We are also amending the terminology used throughout subpart S to
clarify whether the calculation and reporting requirements are
referring to calcined byproducts and waste materials by adding the word
``calcined'' to the lime byproduct and waste terminology, as needed. We
are also amending the terminology in the subpart to clarify when the
calculation and reporting requirements apply to lime products that are
produced at the facility.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart S and is finalizing the amendments to this subpart as proposed.
K. Subpart V--Nitric Acid Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.223 and 98.224 to clarify how
N2O emissions are to be measured if a facility has an
N2O abatement device. The first amendment clarifies the
location of the test (sampling) point used for the performance test in
several paragraphs in 40 CFR 98.223. As promulgated, the language could
be misconstrued to require the nitric acid facility to shut down any
N2O abatement technology during the performance testing.
This was not the intention as many, if not all, of the N2O
abatement technologies in use must be operated at all times that the
nitric acid facility is operated to control emissions of NOX
in order to comply with state and federal regulations limiting
NOX emissions. The
[[Page 66444]]
amendments will clarify that testing can occur before or after
N2O abatement technology as long as the testing properly
accounts for destruction efficiency.
We are amending Equation V-3 of subpart V to accommodate
N2O abatement technology located after the emission test
(sampling) point, and re-designating it as Equation V-3a of subpart V.
Equation V-3a is also corrected so that the term on the left-hand side
of the equation is changed from EFN2Ot to
EN2Ot.
There are three ways in which abatement technology can be employed.
Equation V-3a of subpart V is for one N2O abatement
technology. We are adding Equation V-3b of subpart V to accommodate
multiple N2O abatement technologies in series and we are
adding Equation V-3c of subpart V to accommodate multiple
N2O abatement technologies in parallel.
We are also including a new Equation V-3d of subpart V for
facilities that do not have N2O abatement technology located
after the test (sampling) point.
In addition, we are clarifying in 40 CFR 98.223 that the annual
performance test must be conducted for each nitric acid train,
consistent with the equations in 40 CFR 98.223. Additional changes were
made to the monitoring requirements in 40 CFR 98.224 to conform to the
changes in the calculation methods in 40 CFR 98.223. We are amending 40
CFR 98.224(a)(1) to clarify when during a nitric acid production
campaign facilities must conduct the performance test.
We are also amending the language concerning the Administrator-
approved alternative method for determining N2O emissions in
40 CFR 98.223(a)(2)(ii), 98.224(a)(3), and 98.226(n). The alternative
method is for determining N2O emissions rather than
N2O concentration or an N2O emission factor. The
language has been changed to correct this point.
We are amending the data reporting requirements in 40 CFR 98.226(g)
and (m) to be consistent with the calculation methods which are for
each nitric acid train, not the facility.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments document (see EPA-HQ-OAR-2010-0109).
Changed the description of the emission factor,
EFN2Ot from ``lb N2O generated/ton
nitric acid produced, 100 percent acid basis'' to ``lb
N2O/ton nitric acid produced, 100 percent acid basis.''
Changed the term ``air stream'' to ``vent stream'' at
40 CFR 98.223(g)(1).
Added Equations E-3b and E-3c of subpart E.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Two sets of comments were received on this subpart.
Responses to additional significant comments received can be found in
Response to Comments: Technical Corrections, Clarifying and Other
Amendments document (see EPA-HQ-OAR-2010-0109).
Comment: One commenter noted that the regulation for Adipic Acid is
similar to the regulation for Nitric Acid and asked that EPA compare
the clarifications made to each of these subparts for consistency.
Response: EPA agrees that there are similarities between the two
subparts. Although the commenter did not provide specific examples for
subpart V, EPA reviewed the commenter's suggested clarifications for
subpart E and made the following comparable changes to subpart V:
EPA agrees with the change to the term ``air stream.'' The term has
been changed to ``vent stream'' in 40 CFR 98.223(g)(1) as this is more
consistent with terminology used to identify testing locations at
current facilities.
EPA agrees that there could be situations at nitric acid facilities
where multiple trains exhaust to a common abatement technology.
Language has been added to 98.223(b)(1) to add flexibility for
facilities that have a group of trains that exhaust to the same
abatement equipment. Further, the equations do not correctly address
situations in which a facility has separate N2O control or
abatement technology on the separate train or process lines, back-up
controls in parallel on a single train, and these technologies are not
operated 100 percent of the time (i.e., operated during maintenance
operations on primary controls). We have learned that some facilities
could have existing controls (e.g., NSCR) and may apply additional
controls during the production process (e.g secondary catalysts in
oxidation reactor) in the future.
In these circumstances, the current equations will not provide an
accurate calculation of N2O emissions. To address the three
ways in which abatement technology can be employed EPA has revised 40
CRR 98.223 to include calculation methods to accurately account for
these possible abatement applications. The current Equation V-3a of
subpart V is for one N2O abatement technology. EPA has added
Equation V-3b and V-3c to accommodate situations where multiple
N2O abatement technologies operate in series and or multiple
abatement technologies in parallel, respectively. Equation V-3d of
subpart V addresses the situation when facilities that do not have
N2O abatement technology.
Comment: According to one commenter, facilities do not have
information to determine a point during the campaign which is
representative of the average emissions over the entire campaign. The
commenter requested that 40 CFR 98.224(a)(1) be modified to ensure that
performance tests are conducted during representative operations while
enabling operating facilities to document and demonstrate compliance
with this objective.
Response: The purpose of this language was to capture emissions
data when the process was operating normally. This requirement is to
ensure that the emission factor developed through this performance test
is an accurate depiction of the quantity of N2O emitted per
quantity of nitric acid produced over the course of an entire year. A
campaign was used as a reference due to concerns that N2O
rates from nitric acid plants are somewhat below average at the
beginning of a campaign and above average at the end of a campaign.
Testing during either of those times could result in an emission factor
developed during non-representative conditions. For example, at the end
of a campaign, the age of the catalyst may influence emissions. As long
as the choice of the timing of the testing is documented and the
methods used to determine the timing are documented, this requirement
is met. EPA has clarified ``average emissions over the entire
campaign'' to ``average emissions rate from nitric acid campaigns'' as
it is the emissions rate that is obtained during the performance test
and a facility may run more than one production campaign over a
reporting year. EPA does not agree that the additional changes
recommended are needed.
The rule offers flexibility in determining the timing of the
performance testing. Facilities may refer to literature and continuous
monitoring data from similar facilities in other countries. This
literature and data could be used to determine an appropriate test
point from a representative or typical nitric acid campaign. The rule
provides facilities flexibility on methods to determine this testing
point. Further, facilities can also apply to EPA to use alternative
methods for determining N2O emissions.
[[Page 66445]]
L. Subpart Z--Phosphoric Acid Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are renumbering Equation Z-1 as Z-1a of subpart Z and adding a
new Equation Z-1b of subpart Z. Equation Z-1b will be used to calculate
CO2 emissions when the method used to analyze phosphate rock
provides a direct estimate of CO2 emissions instead of just
inorganic carbon content.
We have learned from facilities that the ``Phosphate Mining States
Methods Used and Adopted by the Association of Fertilizer and Phosphate
Chemists AFPC Manual 10th Edition--Version 1.9'' (AFPC manual) does not
currently contain a procedure for obtaining a representative grab
sample of rock for testing. A recently updated version of the AFPC
manual, Version 1.92, does contain the appropriate sampling procedures.
To add flexibility to the rule, we are amending 40 CFR 98.264(a) to
allow facilities to use the appropriate industry consensus standards or
industry standard practices currently available. We are also amending
40 CFR 98.264(a) to clarify that the grab sample must be collected
prior to entering the mill for accurate analysis of inorganic carbon
contents.
We are amending 40 CFR 98.266 to correct a cross reference in the
introductory text of that section, and to revise paragraph (c) to
clarify that the annual arithmetic average percent inorganic carbon in
phosphate rock is to be reported as the percent by weight, expressed as
a decimal fraction. We are also adding a new paragraph (f)(9) to 40 CFR
98.266 to specify that facilities need to report the total annual
process CO2 emissions from the phosphoric acid production
facility, in metric tons. Facilities must calculate these emissions
already in 40 CFR 98.263(b)(2) using Equation Z-2 of subpart Z.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments document (see EPA-HQ-OAR-2010-0109).
Renumbered Equation Z-1 as Equation Z-1a of subpart Z.
Added a new Equation Z-1b of subpart Z.
Revised 98.364(a) and (b) to allow facilities to use
the appropriate industry consensus standard or industry standard
practice.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments
document (see EPA-HQ-OAR-2010-0109).
Comment: One commenter requested that Equation Z-1 be revised to
accurately reflect the output of the AFPC Manual's method for the
analysis of phosphate rock. Regarding the inorganic carbon
determinations, the equation assumes that the AFPC Manual's test is for
inorganic carbon and the equation provides for calculation of
CO2 emissions using inorganic carbon content as an input.
However, the AFPC Manual's test is for CO2 directly, making
Equation Z-1 of subpart Z inapplicable as written to the AFPC Manual's
test output. The commenter suggested a technical amendment to correct
this minor misalignment by removing the factor to convert inorganic
carbon to CO2 from Equation Z-1.
Response: EPA agrees that this change is warranted. However, EPA
has decided not to replace Equation Z-1 but to renumber Equation Z-1 as
Equation Z-1a and to add the revised equation as Equation Z-1b. This
subpart would still allow facilities to use other methods (e.g.,
sampling inorganic carbon content) to determine carbon content in
addition to using analytic methods to directly measure CO2
emissions. Therefore, EPA is maintaining this flexibility by retaining
the previous equation and adding a new one that can be used with the
AFPC Manual.
M. Subpart CC--Soda Ash Manufacturing
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the data reporting requirements in 40 CFR
98.296(b)(3) to clarify that the annual soda ash production is reported
for each line, and to make the reporting requirements consistent with
the calculation requirements in 40 CFR 98.293(b)(1) through (b)(3). The
units in 40 CFR 98.296(a)(1) and 40 CFR 98.296(b)(6) are corrected from
metric tons to short tons for consistency with other similar data
reporting requirements. This change is also consistent with how
facilities collect these data.
We are also amending 40 CFR 98.296(b)(10) to clarify that the
information in that paragraph is reported for each manufacturing line
or stack, when using a site specific emission factor, and to clarify
that the elements required by 40 CFR 98.296(b)(10)(i), (ii), and (iv)
are for the periods during the performance test. We are also deleting
40 CFR 98.296(b)(11)(iv), (v), and (vi) because those paragraphs
describe missing data procedures for elements during the site-specific
emission factor performance test which are not allowed to be missing
per 40 CFR 98.296(c).
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart CC and is finalizing the amendments to this subpart as
proposed.
N. Subpart EE--Titanium Dioxide Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the monitoring and QA/QC reporting requirements in
40 CFR 98.314(e) to clarify that the quantity of carbon-containing
waste generated from each titanium dioxide production line is
determined on a monthly basis, consistent with the calculation
procedures in 40 CFR 98.313(b)(3). In addition, we are amending the
data reporting requirements under 40 CFR 98.316(b)(9) to be consistent
with the calculation and monitoring alternative requirements of 40 CFR
98.313(b)(2) and 40 CFR 98.314(c) by removing the restriction that the
carbon content factor for petroleum coke can only be from the supplier.
We are also amending the data reporting requirements under 40 CFR
98.316(b)(11) to clarify that they apply to each process line,
consistent with the calculation and monitoring alternative requirements
of 40 CFR 98.313(b)(3) and 40 CFR 98.314(f).
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart EE and is finalizing the amendments to this subpart as
proposed.
O. Subpart GG--Zinc Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the definitions of the terms for
(Electrode)k and (CElectrode)k in
Equation GG-1 of subpart GG to remove the references to kilns because
electrodes are only used in electrothermic furnaces and are not used in
Waelz kilns. We are also amending 40 CFR 98.336(a) to correct a
[[Page 66446]]
cross reference to subpart C, and to amend 40 CFR 98.336(b)(1) to
clarify that identification numbers need to be reported for both Waelz
kilns and electrothermic furnaces.
We are amending the data reporting requirements in 40 CFR
98.336(b)(7) and (10) to clarify that the carbon content of each input
to a kiln or furnace should be reported as a calculation parameter
regardless of whether the data are collected from the supplier or by
self measurement. In 40 CFR 98.336, paragraphs (b)(8) and (11) already
require facilities to report whether carbon contents were determined
through self measurement or based on reports from the supplier.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart GG and is finalizing the amendments to this subpart as
proposed.
P. Subpart HH--Municipal Solid Waste Landfills
1. Summary of Final Amendments and Major Changes Since Proposal
We are making numerous clarifying amendments and technical
corrections to subpart HH to address questions EPA has received about
the rule's requirements and to correct known errors. Amendments to the
rule are also being made to address some of the more significant
questions that were the result of the level of detail provided in the
2009 final rule.
Source Category Definition. We are amending 40 CFR 98.340(b) to
read, ``This source category does not include Resource Conservation and
Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA)
hazardous waste landfills, construction and demolition waste landfills,
or industrial waste landfills.'' We are adding definitions within 40
CFR 98.348 for the terms ``construction and demolition waste
landfills'' and ``industrial waste landfills.''
Equation HH-1. We are making the following technical amendments to
Equation HH-1 in 40 CFR 98.343:
Replace the term L0 (CH4
generating potential) with the terms,
``MCFxDOCxDOCFxFx16/12,'' (where MCF is the
CH4 correction factor; DOC is the degradable organic
content; DOCF is the fraction of DOC dissimilated; and F
is the fraction by volume of CH4 in landfill gas) and
remove the definition of the term L0 from the definitions
for Equation HH-1 of subpart HH.
Revise the definition of ``S'' to read, ``Start year of
calculation. Use the year 1960 or the opening year of the landfill,
whichever is more recent.''
Revise the definition of Wx to include ``measurement
data'' as follows: ``Quantity of waste disposed of in the landfill
in year x from measurement data, tipping fee receipts, or other
company records (metric tons, as received (wet weight).''
Revise the definition of ``MCF'' to read ``Methane
correction factor (fraction). Use the default value of 1 unless
there is active aeration of waste within the landfill during the
reporting year. If there is active aeration of waste within the
landfill during the reporting year, either use the default value of
1 or select an alternative value no less than 0.5 based on site-
specific aeration parameters.''
Revise the definition of ``DOCf'' to read,
``Fraction of DOC dissimilated (fraction). Use the default value of
0.5.''
Revise the definition of ``F'' as follows: ``Fraction
by volume of CH4 in landfill gas from measurement data on
a dry basis, if available (fraction); default is 0.5.''
Revise the definition of ``k'' to read, ``Rate constant
from Table HH-1 to subpart HH (yr-1). Select the most applicable k
value for the majority of the past 10 years (or operating life,
whichever is shorter).''
We are also amending 40 CFR 98.343(a)(2) to replace ``use the bulk
waste parameter values for k and L0 in Table HH-1 to subpart
HH'' with ``use the bulk waste parameter values for k and DOC in Table
HH-1 to subpart HH.''.
Measuring Waste Quantity. We are amending 40 CFR 98.343(a) by
adding a new paragraph (a)(3) to provide the necessary detail and
clarification on the requirements for measuring the quantity of waste
disposed in the landfill beginning with the first reporting year, and
re-designating the existing 40 CFR 98.343(a)(3) as (a)(4). The amended
waste measurement requirements for the reporting years require the use
of scales when scales are in-place for all vehicles or containers
delivering waste, except passenger vehicles and light duty pick-up
trucks or waste loads that cannot be measured using the scales due to
physical limitations (load cannot physically access or fit on the
scale) and/or operational limitations of the scale (load exceeds the
limits or sensitivity range of the scale).
When scales are present at the MSW landfill, they must be used,
(except for passenger vehicles and light duty pick-up trucks or waste
loads that cannot be measured using scales due to physical and/or
operational limitations). Two options for the use of scales are
included in the amendments. One option is to directly weigh each
vehicle/container load as it enters the landfill and weigh each
vehicle/container after the waste has been off-loaded, and calculate
the mass of waste disposed as the difference in the two measurements.
The second option requires the landfill owner or operator to determine
tare weights (empty vehicle weights) for representative vehicle types.
In this option, the landfill owner or operator must weigh the incoming
vehicles and containers and calculate the mass of waste disposed based
on the difference of the incoming vehicle weight and the tare weight of
that vehicle type.
When scales are not in place, the working capacity or the mass of
waste per type of vehicle or container must be determined. These
measurements may include determining the volumetric capacity of
representative containers and the average density of the waste as
received. Wheel-load scales or portable axle-load scales may be used
for these density determinations or measures of the mass of waste
received by type of load. The landfill owner or operator must record
the number and type of vehicles that haul waste to the landfill and use
the working capacity of the containers to calculate the quantity of
waste landfilled.
In addition to redesignating paragraph (a)(3) of 40 CFR 98.343 to
(a)(4), we are amending that paragraph and the sub-paragraphs to
clarify that measurement data can be used for historical years when the
data are available. We are clarifying that the ``Historical waste
disposal quantities should only be determined once, as part of the
first annual report, and the same values should be used for all
subsequent annual reports, supplemented by the next year's data on new
waste disposal.'' We are also amending 40 CFR 98.343(a)(4)(i) to read,
``Assume all prior year's waste disposal quantities are the same as the
waste quantity in the first year for which waste quantities are
available.'' We are amending 40 CFR 98.343(a)(4)(iii) by revising the
phrase, ``i.e., from first accepting waste * * *'' with ``i.e., from
the first year accepting waste * * *''
In related amendments, we are also amending 40 CFR 98.344(a) to
state that ``Mass measurement equipment used to determine the quantity
of waste landfilled on or after January 1, 2010 must meet the
requirements for weighing equipment as described in ``Specifications,
Tolerances, and Other Technical Requirements For Weighing and Measuring
Devices,'' NIST Handbook 44 (2009) (incorporated by reference, see 40
CFR 98.7).'' We are also amending 40 CFR 98.346(a) to require reporting
of `` * * an indication of whether scales are present at the
landfill,'' and to amend 40 CFR 98.346(b) to require reporting of the
waste quantities that were determined using scales according to the
requirements in 40 CFR 98.343(a)(3)(i)
[[Page 66447]]
and the waste quantities determined using vehicle counts and load
capacities. We are also amending 40 CFR 98.347 to specifically require
that records be maintained of all measurements used to determine
vehicle tare weights or working capacities.
Equations HH-2, HH-3, and HH-4. We are making the following
technical amendments to Equation HH-2 in 40 CFR 98.343:
Replace the term ``WGRX'' with
``WDRX'' and remove the term ``%SWDS.''
Replace the definition of the term ``WGRX''
with ``WDRX = Average per capita waste disposal rate for
year x from Table HH-2 to this subpart (metric tons per capita per
year, wet basis; tons/cap/yr).''
Delete the definition of the term ``%SWDS.''
Delete the word ``of'' from the definition of
``POPX.''
We are making the following technical amendments to Equation HH-3
in 40 CFR 98.343:
Replace the term ``WDRX'' with
``WX.''
Replace the definition of the term ``WDRX''
with ``WX'' = quantity of waste place in the landfill in
year x (metric tons/wet basis).''
Replace the definition of LFC with ``Landfill capacity
or, for operating landfills, capacity of the landfill used (or the
total quantity of waste-in-place) at the end of the year prior to
the year when waste disposal data are available from design drawings
or engineering estimates (metric tons).''
We are making the following technical amendments to Equation HH-4
and the related 40 CFR 98.343(b):
Amend Equation HH-4 of subpart HH and the terms in that
equation to allow for daily averages (365 or 366 per year) from a
continuous CH4 monitoring system, or from weekly sampling
(with 52 measurement periods).
Amend the definitions of the terms (T)n and
(P)n in Equation HH-4 to allow for averaging of
measurements.
In 40 CFR 98.343(b)(2), delete ``* * * at least weekly
* * *''
In 40 CFR 98.343(b)(2)(ii), (iii)(A), and (iii)(B),
replace ``no less than weekly'' with ``at least once each calendar
week; if only one measurement is made each calendar week, there must
be at least three days between measurements.''
In 40 CFR 98.343(c), replace ``Calculate * * *'' with
``For all landfills, calculate * * *''
Moisture Content Measurement. In addition to the other amendments
to Equation HH-4 of subpart HH discussed above, we revised the
definition of (V)n to be the cumulative volume for the
measurement period (rather than the volumetric flow rate), eliminated
the 1,440 conversion factor for minutes per day, and revised the
reference to ``day'' in the definition of equation terms with
``measurement period.'' We are also amending Equation HH-4 to replace
the moisture correction term, [1-
(fH2O)n], with a moisture correction
factor, KMC. KMC is defined as ``Moisture
correction term for the measurement period, volumetric basis,'' for
three different measurement scenarios:
KMC = 1 if (V)n and (C)n are
both measured on a dry basis or if both are measured on a wet basis.
KMC = 1-(fH2O)n if
(V)n is measured on a wet basis and (C)n is
measured on a dry basis.
KMC = 1/[1-(fH2On] if (V)n is
measured on a dry basis and (C)n is measured on a wet
basis.
We are similarly amending 40 CFR 98.343(b)(2)(iii)(B) to indicate
that moisture content is needed ``[i]f the CH4 concentration
is determined on a dry basis and flow is determined on a wet basis or
CH4 concentration is determined on a wet basis and flow is
determined on a dry basis, * * *''.
We are amending 40 CFR 98.344(d) and (e) to include reference to
moisture content monitors. Specifically, we are amending 40 CFR
98.344(d) to read: ``All temperature, pressure, and if necessary,
moisture content monitors must be calibrated using the procedures and
frequencies specified by the manufacturer.'' We are also amending the
first sentence in 40 CFR 98.343(d) to read, ``The owner or operator
shall document the procedures used to ensure the accuracy of the
estimates of disposal quantities and, if applicable, gas flow rate, gas
composition, temperature, pressure, and moisture content
measurements.'' We are amending 40 CFR 98.346(i)(3) to require
reporting of both temperature and pressure (not just temperature) and
to amend 40 CFR 98.346(i)(4) to require reporting of the moisture
content measurements.
``Active'' and ``Passive'' Gas Collection Systems. We are amending
the definition of ``gas collection system'' in 40 CFR 98.6 as described
in Section II.B of this preamble and we are adding a reporting
requirement in 40 CFR 98.346(h) and (i)(7) for reporters to provide
``an indication of whether passive vents and/or passive flares (vents
or flares that are not considered part of the gas collection system as
defined in 40 CFR 98.6) are present at this landfill.''
Other Technical Corrections. We are making other technical
corrections for subpart HH to correct typographical errors, to correct
equations, and to provide minor clarifications.
We are making the following technical corrections to 40 CFR
98.344(b):
Delete the word ``install.''
In 40 CFR 98.344(b)(6)(ii), add ``at the routine
sampling location.''
Revise 40 CFR 98.344(b)(6)(ii)(A) to read ``Take a
minimum of three grab samples of the landfill gas with a minimum of
20 minutes between samples and determine the methane composition of
the landfill gas using one of the methods specified in paragraphs
(b)(1) through (b)(5) of this section.''
In 40 CFR 98.344(b)(6)(iii), delete ``that is collected
and routed to a destruction device (before and treatment
equipment).''
In 40 CFR 98.344(b)(6)(ii)(B), add ``for use in
Equation HH-4 of this subpart'' to the definition of the term
CH4 as follows ``Methane concentration in the landfill
gas (volume %) for use in Equation HH-4 of this subpart.''
In 40 CFR 98.344(c), we are revising the language to read, ``Each
gas flow meter shall be recalibrated either biennially (every 2 years)
or at the minimum frequency specified by the manufacturer. Except as
provided in 40 CFR 98.343(b)(2)(i), each gas flow meter must be capable
of correcting for the temperature and pressure and, if necessary,
moisture content.'' We are making the following technical corrections
to 40 CFR 98.346:
Revise the language in 40 CFR 98.346(a) regarding
leachate recirculation to read ``an indication of whether leachate
recirculation is used during the reporting year and its typical
frequency of use over the past 10 years (e.g., used several times a
year for the past 10 years, used at least once a year for the past
10 years, used occasionally but not every year over the past 10
years, not used).''
Revise 40 CFR 98.346(c) to read ``Waste composition for
each year required for Equation HH-1 of this subpart, in percentage
by weight, for each waste category listed in Table HH-1 to this
subpart that is used in Equation HH-1 of this subpart to calculate
the annual modeled CH4 generation.''
In 40 CFR 98.346(d)(1), replace the term, ``Degradable
organic carbon (DOC) value used in the calculations,'' with
``Degradable organic carbon (DOC), methane correction factor (MCF),
and fraction of DOC dissimilated (DOCF) values used in
the calculations.''
In 40 CFR 98.346(d)(1) add ``If an MCF value other than
the default of 1 is used, provide an indication of whether active
aeration of the waste in the landfill was conducted during the
reporting year, a description of the aeration system, including
aeration blower capacity, the fraction of the landfill containing
waste affected by the aeration, the total number of hours during the
year the aeration blower was operated, and other factors used as a
basis for the selected MCF value.''
Revise 40 CFR 98.346(f) to read, ``The surface area of
the landfill containing waste (in square meters), identification of
the type of cover material used (as either organic cover, clay
cover, sand cover, or other soil mixtures). If multiple cover types
are used, the surface area associated with each cover type.''
Add ``for the reporting year'' to 40 CFR 98.346(i)(1)
as follows: ``Total volumetric
[[Page 66448]]
flow of landfill gas collected for destruction for the reporting
year (cubic feet at 520[deg]R or 60[deg]F and 1 atm).''
Add ``Annual average'' to 40 CFR 98.346(i)(2)as
follows: ``Annual average CH4 concentration of landfill
gas collected for destruction (percent by volume).''
In 40 CFR 98.346(i)(7), replace the parenthetical
``(manufacture, capacity, number of wells, etc.)'' with
``(manufacturer, capacity, and number of wells).''
We are also adding the following definitions within 40 CFR 98.348
of subpart HH: ``destruction device''; ``solid waste''; and ``working
capacity.''
We are amending Table HH-1 to subpart HH to delete the default
value for Lo, to provide additional DOC and k-values
including those for inerts, e.g., glass, plastics, metal, concrete, and
to provide additional DOC and k-values to provide additional options
for categorizing waste when applying Equation HH-1 in 40 CFR 98.343(a).
We are also amending Table HH-1 to subpart HH to provide a more
reasoned approach for determining the decay rate constant, k, when only
a small quantity of leachate is recirculated and/or when leachate
recirculation is used rarely (not every year). The leachate
recirculation rate will be calculated as the total volume of leachate
recirculated during the year divided by the area of the portion of the
landfill containing waste. No direct measurement of volume of leachate
recirculated is required; engineering estimates may be used. This
leachate recirculation rate (in inches/year) is added to the
precipitation rate and the sum used to determine what decay rate
constant is appropriate. Alternatively, landfills that use leachate
recirculation can elect to use the higher k value rather than
calculating the recirculated leachate rate. The footnotes for Table HH-
1 to subpart HH have been revised accordingly.
We are amending Table HH-2 to subpart HH to provide directly the
waste disposal factors rather than the waste generation rates and
percent disposed of in solid waste disposal sites (% to SWDS) and
correcting an error in the waste generation rates included in Table HH-
2 to subpart HH from 1989 to 2006. We are also adding waste disposal
rates for 2007, 2008, and 2009.
We are amending Table HH-3 to subpart HH to delete the references
to the average depth of waste within an area (H2, H3, H4, and H5). We
are also amending Table HH-3 to subpart HH to clarify what is
considered a ``final soil cover.'' The description for A5 is revised to
read, ``Area with a final soil cover of 3 feet or thicker of clay and/
or geomembrane cover system and active gas collection.'' The
description for A4 is revised to read, ``Area with an intermediate soil
cover, or a final soil cover not meeting the criteria for A5 below, and
active gas collection.''
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the Response to Comments: Technical Corrections,
Clarifying and Other Amendments (see EPA-HQ-OAR-2010-0109).
Deleted the word ``dedicated'' from the phrase
``dedicated construction and demolition waste landfill'' in 40 CFR
98.340(b) and replaced the proposed definition of ``dedicated
construction and demolition waste landfill'' with a definition of
``construction and demolition waste landfill'' taken from 40 CFR
part 257.2.
Revised the definition of MCF term in Equation HH-1 to
allow landfills with active aeration to select an MCF value less
than 1, but no lower than 0.5 and added reporting requirements to 40
CFR 98.346(d)(1) for facilities using an MCF value other than 1.
Revised Table HH-1 to subpart HH to include DOC and k
values for additional waste categories to provide an additional
option for characterizing waste materials when applying Equation HH-
1 of subpart HH.
Revised the footnotes to Table HH-1 to subpart HH to
allow the use of the greater k value in a given range when
recirculation is used without the need to calculate the recirculated
leachate quantity in inches per year.
Revised 40 CFR 98.343(a)(3) to account for those loads
that cannot be measured using scales due to their physical and/or
operational limitations.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments (see
EPA-HQ-OAR-2010-0109).
Comment: Several commenters stated that the new definition of
``dedicated construction and demolition (C&D) waste landfills'' is
problematic and inappropriate because it is inconsistent with the C&D
landfill definition already long-established in 40 CFR 257.2,
``Criteria for the Classification of Solid Waste Disposal Facilities
and Practices,'' it represents a significant material change to the
subpart HH applicability requirements, and it changes the data
collection requirements for landfills retroactively. The RCRA Subtitle
D definition 40 CFR 257.2 is:
``Construction and demolition (C&D) landfill means a solid waste
disposal facility subject to the requirements of subparts A or B of
this part that receives construction and demolition waste and does
not receive hazardous waste (defined in Sec. 261.3 of this chapter)
or industrial solid waste (defined in Sec. 258.2 of this chapter).
Only a C&D landfill that meets the requirements of subpart B of this
part may receive conditionally exempt small quantity generator waste
(defined in Sec. 261.5 of this chapter). A C&D landfill typically
receives any one or more of the following types of solid wastes:
Roadwork material, excavated material, demolition waste,
construction/renovation waste, and site clearance waste.''
According to the commenters, a dedicated C&D landfill, as defined
in the proposal, rarely exists and most states allow C&D landfills to
accept yard waste and other forms of household trash, pointing to the
use of the word ``typically'' with regard to the types of wastes
received, and suggesting that site clearance waste includes yard waste
among other materials. The commenters urged EPA to delete the new C&D
landfill definition in 40 CFR 98.348 and replace it with the definition
found in 40 CFR 257.2. On the other hand, one commenter expressed
concern with excluding ``dedicated C&D waste landfills'' even with the
proposed definition and requested EPA to quantify the methane emissions
from these C&D landfills.
Response: We generally agree with commenters that the RCRA Subtitle
D definition in 40 CFR 257.2 is appropriate and should be used in
preference to the proposed definition of ``dedicated C&D waste
landfills.'' However, we are concerned with some of the assertions made
by the commenters that a ``C&D waste landfill'' could accept some yard
wastes and possibly other household wastes. Yard waste and household
solid wastes are clearly included in the definition of ``municipal
solid waste or MSW'' in 40 CFR 98.6. The definition of ``MSW landfill''
in 40 CFR 98.6 ``means an entire disposal facility * * * where
household waste is placed in or on land.'' It is our interpretation and
intent that any landfill in which household wastes, including household
yard wastes or other MSW materials, are placed is a MSW landfill and is
subject to the reporting requirements of subpart HH. As we did not
change or alter the definition of MSW or MSW landfill, we do not agree
with commenters that interpret the RCRA Subtitle D definition of C&D
landfills in 40 CFR 257.2 to somehow supersede the definitions and
intent of subpart HH. Furthermore, the definition of MSW landfill
(MSWLF) unit in 40 CFR 257.2 specifies that ``a C&D waste landfill that
receives residential lead-based paint waste and
[[Page 66449]]
does not receive any other household waste is not a MSWLF unit.'' The
converse of the statement clearly suggests that a C&D waste landfill
that receives any household waste other than residential lead-based
paint waste is a MSWLF unit. Thus, while we are revising the definition
of C&D landfill to more closely follow the definition at 40 CFR 257.2,
we do not agree that we materially altered the rule by providing a
definition of dedicated C&D waste landfill and strongly object to the
supposition that landfills that receive even small quantities of
household wastes (other than residential lead-based paint wastes) are
anything other than MSW landfills. Therefore, to clarify our intent, we
have revised slightly the language adapted from the RCRA definition to
specifically state that a C&D waste landfill does not receive MSW. We
also deleted the sentence regarding conditionally exempt waste as
superfluous to the requirements of this definition in subpart HH. The
final definition reads ``Construction and demolition (C&D) waste
landfill means a solid waste disposal facility subject to the
requirements of subparts A or B of part 257 of this chapter that
receives construction and demolition waste and does not receive
hazardous waste (defined in 40 CFR 261.3 of this chapter) or industrial
solid waste (defined in 40 CFR 258.2 of this chapter) or municipal
solid waste (defined in 40 CFR 98.6) other than residential lead-based
paint waste. A C&D waste landfill typically receives any one or more of
the following types of solid wastes: roadwork material, excavated
material, demolition waste, construction/renovation waste, and site
clearance waste.''
While we have adopted, for the most part, the RCRA subtitle D
definition for C&D waste landfills, we maintain that the inclusion of a
definition of C&D waste landfills is not a material change in the rule
because it does not alter the definition of MSW landfill or the
applicability of the rule to MSW landfills. As the final definition of
C&D waste landfills expressly includes site clearance wastes, which
could include trees and other materials that have significant organic
content, we agree that additional evaluation is needed to assess the
methane generation potential of C&D waste landfills. Consequently, we
are taking this comment under advisement; we will determine whether or
not reporting requirements should be proposed for C&D waste landfills
at a future time based on the results of the additional evaluations of
C&D waste materials and their methane generation potential.
Comment: Several commenters expressed support for the amended
definition of ``gas collection systems or landfill gas collection
systems,'' intended to clarify that passive vents/flares are not
considered part of a landfill gas collection system for purposes of
subpart HH. However, these commenters opposed the proposed reporting
requirement to provide an indication of whether passive vents and/or
passive flares that are not considered part of the gas collection
system as defined in 40 CFR 98.6 are present at the landfill. The
commenters argued that this represents a new data element that would
require significant additional burden to contact landfill engineers to
collect this new information. The commenters recommended that EPA
finalize this data element, but delay its collection to January 1,
2011, and delay its reporting to March 31, 2012 and thereafter. On the
other hand, one commenter expressed concerned that EPA's decision to
exempt ``passive'' gas collection systems from flow meter reporting may
inadvertently exempt substantial emissions sources. The commenter noted
that the number of landfills with passive vent controls is uncertain
and argued that the cumulative emissions from these passive collection
systems could be significant. The commenter requested EPA include any
data on this point in the record for the final rulemaking and include
passive gas collection systems fully in the rule if warranted.
Response: The monitoring requirements for gas collection systems
within the final rule were developed considering forced ventilation
systems and those monitoring requirements are inappropriate for passive
gas collection systems. However, we agree with the commenter who
suggested that EPA must obtain more data on the prevalence of these
systems in order to properly understand and account for the impact
these systems may have on the GHG emissions from MSW landfills. We find
that ``an indication'' (essentially answering a yes/no question to
indicate whether or not a passive gas collection system is present) is
not a significant additional reporting burden. As this reporting
requirement requires no monitoring or other activities that might be
considered a retroactive requirement, we conclude that this reporting
requirement is appropriate and necessary for the 2010 reporting year.
Comment: A few commenters indicated that the requirement to use a
methane correction factor (MCF) of 1 will overestimate methane
generation from landfills that are actively aerated and recommended
that facilities be allowed to use alternative MCF values based on site-
specific conditions (e.g., the use of in-situ aeration).
Response: To the extent some MSW landfills actively aerate the
waste within the landfill, we agree that alternative MCF values should
be allowed for actively aerated landfills. Supplying air to the waste
within the landfill will reduce the fraction of carbon that is degraded
anaerobically, which is represented by the MCF value. However,
additional reporting requirements are needed to verify the MCF value
selected. These include the basis of the alternative value, such as an
indication of whether active aeration is used, a description of the
aeration system, including aeration blower capacity, the fraction of
the landfill containing waste affected by the aeration, the total
number of hours during the year the aeration blower was operated, and
other factors used as a basis for the selected MCF value. Based on
other comments received (e.g., comments described above on reporting of
the presence of passive gas collection systems), the inclusion of these
additional reporting requirements would likely be objectionable.
However, we have conditioned these additional reporting requirements to
be applicable only for facilities electing not to use an MCF value of
1. As the reporting requirements for facilities that use an MCF value
of 1 have not changed, and because all facilities can choose to use the
default value of 1 (including the relatively few landfills that use
active aeration), we find that we have not significantly altered the
reporting requirements of the final rule. Facilities electing to use an
MCF other than 1 must have active aeration and must provide information
regarding the aeration system to justify the lower MCF value.
Comment: One commenter noted that the new defaults for inert wastes
in Table HH-1 to subpart HH are designated for use only by those
landfills capable of segregating and measuring the waste they accept by
composition using EPA's prescribed waste categories, which include:
food waste, garden, paper, wood and straw, textiles, diapers, sewage
sludge and, now, inerts. According to commenters, U.S. MSW landfills do
not use these categories to categorize waste receipts, and few if any
MSW landfills will be able to adjust for large quantities of inerts
that may be disposed of at a specific landfill. The commenter noted
that the MSW landfill sector in the U.S.
[[Page 66450]]
typically records waste type receipts using the broad categories of MSW
bulk waste, construction and demolition (C&D) bulk waste, inert waste,
sewage sludge, and yard and garden waste. The commenter recommended
that the inert defaults be included in Table HH-1 to subpart HH for the
``Bulk Waste Option'' to allow landfills to take large shipments of
bulk inert wastes into account in their landfill gas generation models.
Response: The bulk DOC and k values were determined based on
monitored landfill gas generation rates and the total quantity of waste
disposed (annual average waste acceptance rates). We reviewed the C&D
waste acceptance policies of these landfills, as C&D waste can largely
be comprised of inert materials, and determined that each landfill
accepted C&D wastes. While we do not have a breakdown of the relative
quantities of different categories of wastes in these landfills, we
maintain that the default ``bulk waste'' DOC and k values are
representative of typical or average MSW landfill operations in the
U.S. However, we also acknowledge that there is significant variability
in the methane generation rates (per ton of waste disposed) at
individual landfills. We provided the waste composition option to
account for this variability, but this option needs a default value for
inert materials in order to be more comprehensive and therefore
reflective of waste composition at U.S. landfills. With regard to the
bulk waste option, which is applicable when a landfill cannot breakdown
their waste quantities at all, it is not appropriate to allow the use
of inert default parameters, because values provided for this option
already consider that there will be some amount of inerts in the
overall waste quantity. Therefore, this option remains as it appeared
in the October 2009 Final rule. However, we consider it reasonable to
provide an alternative bulk MSW option that allows landfills to
characterize their waste quantities into categories that the MSW
landfill industry more typically monitors and records. We reviewed
available MSW waste characterization data to develop default bulk MSW
model parameters excluding inerts and C&D wastes, and determined that
an appropriate DOC value for this waste category is 0.31 with a k value
similar to that for bulk waste. Therefore, we have included in the
final rule an additional option for characterizing waste materials. In
this ``bulk MSW'' option, there are three waste categories: bulk MSW
excluding inerts and C&D wastes; inert wastes; and C&D wastes. This new
option provides a means for individual landfills to better estimate the
methane generation rates to account for significant quantities of inert
materials or C&D wastes without needing to classify the wastes into the
detailed categories of the waste composition option. For more
information on the bulk MSW option, please see ``Modified Bulk MSW
Option'' in docket EPA-HQ-OAR-2010-0109.
Given these amendments to Table HH-1 to subpart HH, we are also
revising the reporting requirements in 40 CFR 98.346(c) to clarify that
the waste compositions should be reported only for the waste categories
in Table HH-1 to subpart HH that are used in the calculation of methane
generation using Equation HH-1 of subpart H. This amendment is needed
to avoid confusion with the ``municipal'' category currently listed in
40 CFR 98.346(c) and the bulk waste and bulk MSW categories.
Comment: A few commenters indicated that the amendment to the Table
HH-1 to subpart HH regarding leachate recirculation imposes substantial
new data collection requirements that would require significant
operational changes to implement. According to the commenters, most
landfills that recirculate leachate do not measure and track the volume
that is recirculated during each event and would not be able to provide
these data for the 2010 calendar year. Furthermore, the commenter
suggested that landfills would incur significant expense to install
appropriate leachate measurement devices and ancillary equipment for a
nominal impact on landfill GHG emissions calculation accuracy.
Response: We proposed the modifications to Table HH-1 to subpart HH
to address questions that arose concerning the use of the highest k
value in the range when leachate recirculation was used sporadically or
only in limited amounts. We did not specify any monitoring requirements
for the quantity of leachate recirculated; we anticipated that most
landfills would use company records or engineering estimates to
determine the quantity of leachate recirculated. We have revised the
first footnote to Table HH-1 to subpart HH to clarify this point.
Additionally, we have revised the footnotes to allow facilities to use
the highest k value in the range when leachate recirculation is used.
As such, the final amendments are effectively equivalent to those
proposed, but give reporters some flexibility to use high-range default
k values if leachate recirculation is used, but leachate recirculation
rates are unknown or otherwise not estimated. The use of the higher k
values may overestimate methane generation, but it will not result in
any additional monitoring or reporting burden for reporters. Further,
not all landfills use leachate recirculation and we expect that some of
the landfills that do use leachate recirculation will have records that
document the amount of leachate that is recirculated. Therefore, we
expect that only a small subset of landfills would default to the
higher k-value when a lower k-value might be more appropriate and that
there will not be a significant bias in overall emissions from
landfills.
Comment: Several commenters discussed the amendments in 40 CFR
98.343(a)(3) requiring landfills to use scales when scales are in-place
for all vehicles or containers delivering waste, except passenger
vehicles and light-duty pick-up truck. The commenters stated that this
requirement is problematic because it is not possible to physically
weigh all loads entering the landfill because their weight may exceed
the scales' capability or the dimensions of the waste may not allow the
waste load to pass through the physical constraints of the scale and
scale-house. Some commenters noted that state and local requirements
may require accounting of certain waste types on a volumetric basis
despite the landfill having scales. The commenters suggested that
having to maintain two sets of records in order to comply with all
established regulatory requirements is an unnecessary burden and
contrary to acceptable accounting practices. One commenter suggested
that the clarification to require all waste loads to be weighed via a
scale to be a substantial material change because the final MMR could
be interpreted to allow tipping fee receipts or company years for 2010
and beyond and not just direct measurement. The commenters generally
recommended that 40 CFR 98.343(a)(3) be revised so that waste loads can
be measured by using either methodologies as appropriate for the waste
type disposed even though scales are present at the landfill. Some of
the commenters suggested EPA allow facilities to estimate the weight/
volume of the delivered waste material using methods and factors
allowed or required by state or local agencies or other methods
documented in the relevant facility's GHG Monitoring Plan.
Response: We originally intended that scales be installed and
direct mass measurements be used for the year 2010 and beyond; the
allowance of tipping
[[Page 66451]]
fee receipts or other company records was intended for years prior to
the first emissions reporting year. While states and local
jurisdictions may require measurement by volume, Equation HH-1 of
subpart HH, which is the foundation for determining methane generation
from the landfill, requires the waste quantity in units of mass.
Section 98.343(a)(2) of subpart HH specifically requires these waste
quantities [in units of mass] to be determined daily, and 40 CFR
98.344(a) states that ``[t]he quantity of waste landfilled must be
determined using mass measurement equipment * * *'' EPA answered
numerous questions regarding this requirement and communicated the
above interpretation to the industry in webinars and other outreach
materials. Consequently, we do not consider the proposed amendments in
40 CFR 98.343(a)(3) to be a substantial material change in the
requirements of the rule published on October 30, 2009. However, we
recognize that some reporters did not believe that the rule language
was explicit with respect to these requirements. Additionally, we
reconsidered our original position that scales must be installed. The
proposed amendments addressed both of these issues.
We had not considered that there would be physical limitations to
accessing the scale. We also anticipated that the scales would cover
the range of sizes and weights received at the site. As we no longer
require the installation of permanent scales at a facility, we
certainly do not intend to require facilities to have to replace
existing scales to accommodate unusually sized or heavy loads. As such,
we conclude that it is reasonable to allow facilities to use the
methods in 40 CFR 98.343(a)(3)(ii) for certain waste loads even though
scales are present at the facility. However, because the mass of waste
is a critical input to Equation HH-1 and we desire accurate
measurements of this waste, the methods outlined in 40 CFR
98.343(a)(3)(ii) are limited to waste loads that cannot be measured
using the scales due to physical and operational limitations of the
scale. Physical limitations refers to the shape or size of the load so
that it cannot access the scale or does not fit on the scale.
Operational limitations refers to the weight of the load exceeding the
limits or sensitivity range of the scale. Operational limitations are
not intended to consider waiting times to access the scale. For all
other types of waste loads (other than passenger vehicles or light duty
trucks), the direct mass measurement methods in 40 CFR 98.343(a)(3)(i)
must be used.
Q. Subpart LL--Suppliers of Coal-Based Liquid Fuels
1. Summary of Final Amendments and Major Changes Since Proposal
First, we are amending 40 CFR 98.386(a)(5) and (6) to clarify that
fossil-fuel products that enter the facility will not be reported when
exiting the facility if they are not further refined or otherwise used
on site (e.g. products stored in a tank). It was not EPA's intent that
such products be reported.
Second, we are amending 40 CFR 98.386(a)(3), (a)(7), (b)(3), and
(c)(3) to harmonize the reporting requirements with the amendments in
40 CFR 98.393 of today's rule to account for denaturant in ethanol.
Third, we are replacing a comma with the words ``that were'' in 40 CFR
98.386(a)(16) and (a)(17) and adding a paragraph at 40 CFR 98.386(d) to
harmonize the reporting requirements with the amendment in 40 CFR
98.393(i) of today's rule to provide an optional method for calculating
GHG emissions from blended feedstock and products. Since subpart LL
reporters follow subpart MM methodologies for calculating GHG
emissions, these amendments are necessary to ensure complete reporting
of subpart LL data.
2. Summary of Comments and Responses
EPA did not receive any comments on the proposed amendments to
subpart LL and is finalizing the amendments to this subpart as
proposed.
R. Subpart MM--Suppliers of Petroleum Products
1. Summary of Final Amendments and Major Changes Since Proposal
We are adding a definition of ``batch'' in 40 CFR 98.398 to clarify
the crude oil reporting requirements in 40 CFR 98.396(a)(20) and to
minimize administrative burden. Under this final rule, a batch of crude
oil means either a volume that enters a refinery or a component of such
volume (e.g., the volumes of different crude streams that are blended
together and then delivered to a refinery). The batch volume is
dependent upon what a refiner knows about the crude oil it receives and
is the first appropriate tier in the following list:
(1) Up to an annual volume of a type of crude oil identified by an
EIA crude stream code,\6\ if the EIA crude stream code is known.
---------------------------------------------------------------------------
\6\ The EIA crude stream code is the numeric code used to
identify the type of domestic crude oil in Form EIA-182 (Domestic
Crude Oil First Purchase Report) and the alpha numeric code used to
identify the type of foreign crude oil in Form EIA-856 (Monthly
Foreign Crude Oil Acquisition Report).
---------------------------------------------------------------------------
(2) Up to an annual volume of a type of crude oil identified by a
generic name for the crude stream and an appropriate EIA two-letter
country or state and production area code \7\ if the generic name and
EIA two-letter code are known but no appropriate EIA crude stream code
exists.
---------------------------------------------------------------------------
\7\ EIA country code means the two-letter code identifying the
country associated with the alpha numeric crude stream codes used to
identify the type of foreign crude oil in Form EIA-856 and is
traditionally found in Appendix A of the form. The EIA state and
production area code is the two-letter code used to identify the
source of domestic crude oil in Form EIA-182 is traditionally found
in Appendix A of the instructions.
---------------------------------------------------------------------------
(3) Up to a calendar month volume from a single known foreign
country of origin if the crude stream name is unknown.
(4) Up to a calendar month volume from the United States if the
crude stream name and production area are unknown.
(5) Up to a calendar month volume if the country of origin is
unknown.
For example, if refiners know the EIA crude stream code of a volume
of crude oil that they receive, they must report the API gravity and
sulfur content of up to an annual volume of this type of crude oil. If
refiners only know the country of origin of a volume of foreign crude
oil (but not the crude stream name), they must report the API gravity
and sulfur content of up to a calendar month volume from that country.
For data collection in 2010 only, a refiner that knows the
information that we require them to report under a specific tier of the
batch definition, but does not have the necessary data collection and
management in place to readily report this information, can use the
next most appropriate tier of the batch definition for reporting batch
information in 40 CFR 98.396(a)(20).
With this definition of ``batch'', we are requiring refiners to
report on crude oil volumes in 40 CFR 98.396(a)(20) using the best data
they are collecting as part of normal business practices. For example,
refiners must use data on the American Petroleum Institute (API)
gravity and sulfur content of crude oil that they, or a third party,
currently collect as part of normal business practices, including data
refiners use to report monthly weighted average API gravity and sulfur
content to EIA. As another example, refiners must use data that they
currently collect on the EIA crude stream code or country of origin for
the components of a blended crude oil.
[[Page 66452]]
We are making harmonizing amendments to 40 CFR 98.396(a)(20) to
allow refiners to report the country of origin, EIA crude stream code
and name, or the generic name of the crude stream and associated
production area code for a given batch as appropriate, if known.
To better align the API gravity and sulfur content reporting
requirements with normal business practices, we are also amending the
recordkeeping requirements in 40 CFR 98.397 so that refiners will no
longer be required to maintain laboratory reports, calculations and
worksheets used in the measurement of API gravity and sulfur content of
crude oil. Instead, refiners must maintain sufficient records to
support the information they report to EPA (as required by 40 CFR
98.397(a) and (b)).
We are also amending 40 CFR 98.394(d) and 40 CFR 98.396(a)(20) to
clarify that we are seeking the weighted average API gravity and sulfur
content from representative samples of each batch.
To ensure that refiners can report readily available data in 40 CFR
98.386(a)(20) on the volume and associated characteristics of
components of a blended crude oil, we are amending the requirements for
determining quantity of crude oil in 40 CFR 98.394(a)(1) so that they
only apply to volumes of crude oil that refiners measure on site (e.g.,
the total volume rather than the components of such volume). Refiners
may now use an industry standard practice to determine volumes of crude
oil that are not measured on site, even if an appropriate standard
method published by a consensus-based standards organization exists, as
specified in a new paragraph, 40 CFR 98.394(a)(3). We are also amending
the recordkeeping requirements associated with quantity determination
in 40 CFR 98.397(b) so that refiners will not be required to maintain
metering and gauging records for quantities of crude oil that they do
not measure on site, including the date of initial calibration and
frequency of recalibration for associated measurement equipment. We are
also amending 98.394(d) to give refiners the option of following an
industry standard practice to measure API gravity and sulfur content of
crude oil.
We are amending the definition of Producti (annual
volume of product ``i'' produced, imported, or exported) in Equation
MM-1 in 40 CFR 98.393(a)(1) and (2) to make it clear that GHG emissions
should not be calculated for products leaving the refinery if those
products had entered the refinery but were not further refined or
otherwise used on site (e.g., products stored in a tank). As a
harmonizing change, we are amending 40 CFR 98.396(a)(5) and (6) to
clarify that these products are not reported.
We are amending the procedure in 40 CFR 98.393(f)(1) for
calculating emission factors for solid products when using Calculation
Method 1. The amendments will clarify that reporters should multiply
the default carbon share factor in column B of Table MM-1 to subpart MM
by 44/12 (the ratio of the molecular weight of CO2 to the
atomic weight of carbon) to convert the amount of carbon in the product
to CO2. Due to an oversight, 44/12 was not included in the
original formula. This amendment is necessary because otherwise
reporters would calculate the emissions of carbon instead of carbon
dioxide.
We are amending Equation MM-9 in 40 CFR 98.393(h)(2) to correct a
typographical error. The correct emission factor (EF) term in the
equation is EFj not EFi.
We are adding an optional method for reporters in 40 CFR 98.393(i)
to calculate CO2 emissions that would result from the
complete oxidation or combustion of a blended product or blended non-
crude feedstock. The procedures in the existing rule require reporters
to calculate CO2 emissions for blended products either by
selecting the default emission factor for the product listed in Table
MM-1 to subpart MM that resembles most closely the blended product
(Calculation Method 1) or by sampling and testing the blended product
(Calculation Method 2). If a reporter applies the former method, the
CO2 emissions calculation for the blended product will
likely reflect the CO2 content of only one blend component.
In such a case, the CO2 from the blended product will not be
as accurately accounted for in Equation MM-4 of subpart MM. The
optional method we are adding allows reporters to account for the
CO2 emissions of a blended product or blended non-crude
feedstock in the summary calculation of total facility CO2
by calculating the emissions of the blend's individual components using
appropriate default factors listed in Table MM-1 to subpart MM. This
increases flexibility for facilities that receive and supply blends.
This also improves accuracy of the summary calculation of total
refinery CO2 because it ensures that the same quantities and
emission factors are used for blend components coming in to the
refinery as for blended products going out.
The optional method is not available for a product that is biomass-
based because such biomass-based products are subject to paragraph (h)
of 40 CFR 98.393.
To align the existing regulatory text with the optional method for
blends, we are amending paragraphs (a)(1) and (b)(1) of 40 CFR 98.393
and paragraphs (a)(16) and (a)(17) of 40 CFR 98.396. We are also adding
paragraph (d) of 40 CFR 98.396 to create new data reporting
requirements for blends.
We are amending the calculation procedures in 40 CFR 98.393(h) for
blended biomass-based fuels. Part 98 (as finalized in 70 CFR 56260,
October 30, 2009) directed refineries that supply a petroleum product
that was produced by blending a petroleum-based product with denatured
ethanol to report emissions from the denaturant leaving the refinery
but not the denaturant in the ethanol that enters the refinery as a
feedstock. This resulted in over-reporting of GHG emissions across
subpart MM reporters because the blending refinery accounted for the
CO2 from denaturant in its GHG emissions calculation even
though the original refinery that produced the denaturant ex-refinery
gate already accounted for the CO2 in its GHG emission
calculation. To address the over-reporting for refineries using
Calculation Method 1 for petroleum products or non-crude petroleum
feedstocks that contain denatured ethanol, we are amending Equations
MM-8 and MM-9 of subpart MM to exclude denaturant from the term
``%vol'', respectively.
To address this over-reporting for refineries using Calculation
Method 2 for petroleum products that were produced by blending a
petroleum-based product with denatured ethanol on site, we are adding a
new Equation MM-10a of subpart MM. Equation MM-10a requires refineries
to sample the petroleum-based products prior to blending them with
denatured ethanol and use the resulting emissions factor and the volume
of the petroleum-based product to calculate emissions for the ultimate
petroleum products that leave the refinery. This new equation is
necessary and Equation MM-10 is incorrect for such situations because
the term for the biomass default emission factor in Equation MM-10 is
applied to the whole volume of biomass received for blending (which for
ethanol includes denaturant), even though the default factor for
ethanol does not account for denaturant. We are splitting 40 CFR
98.393(h)(3) into paragraphs (i) and (ii) so that Equation MM-10
remains in (i) for petroleum products blended with
[[Page 66453]]
biomass other than denatured ethanol while Equation MM-10a appears in
(ii) for petroleum products blended with denatured ethanol. We are
amending Equation MM-10 to exclude denaturant from the term ``%vol.''
Together, these amendments ensure that the denaturant present in
ethanol is not accounted for in the calculation of CO2 that
would result from the complete combustion or oxidation of the biomass-
blended product or feedstock. We have concluded that these amendments
simplify reporting for reporters while maintaining the level of data
quality and accuracy required by EPA for subpart MM because we would
expect any denaturant in ethanol that enters the refinery in a
feedstock to leave the refinery in a product and therefore the
CO2 emissions from the denaturant would be a net of zero.
We cannot identify a situation, nor did any commenters, in which a
refinery would want to use Calculation Method 2 for a non-crude
feedstock that contains denatured ethanol or an importer or exporter
would want to use Calculation Method 2 for products containing
denatured ethanol. Therefore, we are splitting 40 CFR 98.393(h)(4) into
paragraphs (i) and (ii) so that Equation MM-11 of subpart MM remains in
(i) for non-crude feedstocks blended with biomass other than denatured
ethanol while directions to use Calculation Method 1 appear in (ii) for
non-crude feedstocks blended with denatured ethanol by refineries. We
are also adding directions in 40 CFR 98.393(h)(3)(ii) for importers and
exporters of petroleum products blended with denatured ethanol to use
Calculation Method 1. We are amending Equation MM-11 to exclude
denaturant from the term ``%vol.''
We are amending 40 CFR 98.396(a)(3), (a)(7), (b)(3), and (c)(3) to
align the reporting requirements with the amendments to account for
denaturant in ethanol.
Major changes since the proposal are identified in the following
list. The rationale for these and any other significant changes can be
found in Response to Comments: Technical Corrections, Clarifying and
Other Amendments (see EPA-HQ-OAR-2010-0109).
We expanded on the proposed definition of ``batch'' to
require refiners to report up to an annual volume of a type of crude
oil identified by an EIA crude stream code (or the generic crude
stream name and production area code if no appropriate EIA crude
stream code exists) if refiners know this information. If refiners
do not know this information, refiners must report according to the
proposed definition of batch (e.g., up to a calendar month volume
from a single country of origin or, if refiners do not know the
country of origin, up to a total calendar month volume).
We clarified that ``batch'' can mean either the volume
that enters a refinery or the components of such volume. We amended
40 CFR 98.394(a) to allow refiners to use industry standard
practices to determine crude oil volumes that they do not measure on
site, rather than standard methods published by a consensus-based
standard, if desired. We also amended the recordkeeping requirements
associated with quantity determination in 40 CFR 98.397(b) so that
refiners are not required to maintain metering and gauging records
for quantities of crude oil that they do not measure on site.
We amended 40 CFR 98.394(d) to allow refiners to use
industry standard practices to measure API gravity and sulfur
content of crude oil, rather than standard methods published by a
consensus-based standards organization, if desired.
For reporting year 2010 only, we are providing
reporters some flexibility in defining a batch of crude oil. A
refiner that knows the information under a specific tier of the
batch definition, but does not have the necessary data collection
and management in place to readily report this information, can use
the next most appropriate tier of the batch definition for reporting
batch information in 40 CFR 98.396(a)(20).
As a harmonizing amendment with the final definition of
crude oil (as discussed in Section II.B, Subpart A--General
Provisions, of this preamble), we added a reporting requirements for
refineries in 40 CFR 98.396(a). Refiners are now required to report
on the volume of crude oil that they inject into a crude supply or
reservoir under a new paragraph (22).
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in Response to
Comments: Technical Corrections, Clarifying and Other Amendments (see
EPA-HQ-OAR-2010-0109).
Comment: We received three comments related to our proposed
amendments regarding the treatment of denatured ethanol. Two comments
supported the proposed change. The third commented that reporting of
gasoline-ethanol blends (i.e., a petroleum product that contains
denatured ethanol and is a blended biomass-based fuel) was burdensome
and suggested that only the petroleum portion of these blends should be
reported. That commenter stated that the blending of ethanol with
gasoline should not be considered ``to be further refined or otherwise
used on site'' (40 CFR 98.396(a)(1)) and that therefore, ethanol should
not have to be reported.
Response: We are finalizing our proposed amendments related to
denaturant in ethanol in today's rule.
When finalizing subpart MM, (74 FR 56260, October 30, 2009), EPA
concluded that reporting the total volume of gasoline-ethanol blends ex
refinery gate as well as the percentage of that volume that is
petroleum-based is not unnecessarily burdensome to reporters. The
changes to 40 CFR Part 98.396(a) that would be necessary to remove
biomass reporting as suggested by the commenter are outside the scope
of the specific amendments proposed for public comment in the Federal
Register notice of June 15, 2010. The proposed changes to 40 CFR
98.396(a) only addressed how the denaturant in ethanol should be
treated, and EPA did not seek comment on removing reporting on biomass
entirely.
As a result of the comments we received, we have concluded that
there has been confusion regarding how ethanol should be reported when
it leaves the facility. When ethanol leaves a facility covered by
subpart MM, it is generally being blended with finished gasoline as it
is being loaded into a truck. We are clarifying here that EPA considers
the ethanol and the gasoline to be leaving the facility separately if
they are leaving through different ``spigots'' and being blended in the
truck. Under these circumstances, there is no gasoline-ethanol blend on
site at the facility. The gasoline is the petroleum product that must
be reported as leaving the facility. The denatured ethanol is not part
of a petroleum product leaving the facility and, as a result of the
technical correction being made in this rule for how to treat the
denaturant in ethanol, need not be reported as entering or leaving the
facility under these circumstances.
The phrase ``to be further refined or otherwise used on site'' only
applies to petroleum products, including blended biomass-based fuels,
and natural gas liquids. EPA has clarified through guidance that a
petroleum product or natural gas liquid that stays in the same
container or vessel while on site and that is not blended with any
other product is not ``otherwise used on site'' and that blending is
considered ``otherwise used on site''. If refiners blend ethanol with a
petroleum product on site--for example, a refiner blends gasoline and
ethanol on site and stores the blend in a tank before it leaves the
facility--then the total volume of the ethanol-gasoline blend as well
as the percentage of that volume that is petroleum-based must be
reported when the blend leaves the facility. The
[[Page 66454]]
volume of ethanol entering the facility need not be reported.
Comment: In the proposal, we sought comment on defining a ``batch''
to help clarify crude oil reporting requirements in 40 CFR
98.396(a)(20) and reduce administrative burden, while continuing to
collect adequate crude oil data to support the purposes of subpart MM.
We received several comments on our proposed definition of batch
and potential alternatives. One commenter supported defining a batch as
the annual volume of a type of crude oil characterized by an EIA crude
stream code (rather than monthly volumes) if EPA maintains the
requirement to report API gravity, sulfur content, and country of
origin of crude oil. One commenter expressed support for the proposed
definition of batch but cautioned that it would limit refiners to
report the country of origin as ``unknown'' when the crude oil batch is
a blend of crude oil from several known countries. The commenter
therefore advised EPA to allow refiners to report on the components in
a crude oil blend and to amend the quantity determination requirements
so that refiners can use information obtained from normal business
practices on blend component volumes. The commenter further opined
that, similar to the problem of reporting a single country of origin,
refiners receiving a crude oil blend would be unable to report a single
EIA crude stream code. Therefore the commenter recommended that EPA
include annual crude volumes by EIA crude stream codes in the
definition of batch only if it is presented as one of multiple options.
Two commenters advocated that EPA limit the definition of batch to the
annual volume of each EIA crude stream code category and remove the
requirement to report API gravity, sulfur content, and country of
origin for every batch. One commenter expressed concern about limiting
the definition of batch to the annual volume of each EIA crude stream
code category if it means losing data on API gravity. That commenter
urged EPA to require refiners to report the sample data they already
collect for EIA reporting. The commenter also asked that EPA define
``batch'' in a way that captures the differences in crude oil
originating from the same country since different crude streams from
the same country can have different API gravity and sulfur contents.
Response: In today's rule we are finalizing a definition of
``batch'' that builds on our proposed definition by adding two
additional features. First, we are requiring refiners to define a batch
as up to an annual volume of a type of crude oil identified by an EIA
crude stream code (or a generic crude stream name and production area
code) if refiners know this information. Second, we are defining batch
as either the total volume of crude oil that enters a refinery or the
components of such volume so that refiners will be able to report
representative data they currently collect on all three crude
parameters--(1) API gravity, (2) sulfur content, and (3) country of
origin or crude stream name and production area--for the components in
a blended crude volume instead of having to report the third parameter
as unknown. These amendments were generally supported by commenters and
we concluded that they would result in better data and be less
burdensome than the proposed definition.
With regard to comments on defining a batch as a monthly versus
annual volume of crude, we determined that API gravity and sulfur
content of specific crude streams do not vary enough to warrant
requiring batch to be defined as only up to a monthly volume. On the
other hand, API gravity and sulfur content can vary significantly
between different crude streams coming from the same country of origin
(or multiple countries of origin). Therefore, we determined that
monthly reporting outlined in the proposed definition of ``batch''
would be necessary in those cases where refiners only know the country
of origin of their crude volume (rather than the crude stream name and
production area) or when they do not know the country of origin. We did
not conclude that reporting batches more frequently than a monthly
basis would be necessary in any situation.
We considered eliminating the requirement that refiners report API
gravity and sulfur content if they report the EIA crude stream code
associated with the batch, but we determined that there were too many
EIA crude stream codes without corresponding API gravity and sulfur
content values and that even when present these values, while
illustrative, were based on limited information and would not always be
representative of the characteristics of the crude oil used at a
refinery. Furthermore, refiners already collect data on the API gravity
and sulfur content of their crude oil in order to report this
information to EIA on a monthly basis, and it is our understanding,
based on an industry comment, that refiners also track this information
to determine how well the physical characteristics of the crude oil
align with the processing capability of their refineries.
Comment: In the proposal, we sought comment on other technical
amendments (besides defining ``batch'') that would help clarify crude
oil reporting requirements in 40 CFR 98.396(a)(20) and reduce
administrative burden. In particular, we sought comment on ways to
better align the provisions related to crude oil reporting with normal
business practices.
We received two comments with input on ways to better align the
monitoring and QA/QC provisions related to crude oil reporting with
normal business practices. According to the two commenters, it is
normal business practice for refiners to maintain data on crude batch
volumes and other parameters required in 40 CFR 98.396(a)(20). They
described a number of different sources they use to identify the sulfur
content and API gravity of crude oil batches (including components of
blended crude oil volumes) such as grab samples, contract laboratory
records, crude assay reports, invoices, and pipeline receipt tickets.
They explained that the data contained in these sources are often
collected outside of the refinery under normal business practices,
which may be inconsistent with the current requirements in the rule to
use standard methods to measure these data (resulting in the need to
collect the data again inside the refinery). In addition, one of the
two commenters explained that they maintain data on the components of
blended crude volumes but they may not be able to determine the volume
of the components of blended crude according to the quantity
determination requirements in 40 CFR 98.394(a)(1) since the components
arrive at the refinery already blended. Therefore, they will be forced
to report the total volume of the blended crude oil and the country of
origin (or EIA crude stream code) as ``unknown'' even though they know
information about the volume components.
We also received two comments in support of the proposed
elimination of recordkeeping requirements in 40 CFR 98.397 related to
the measurement of API gravity and sulfur content of crude oil because
it would support the use of data collected in normal business records.
We received one comment that objected to EPA's deletion of specific
recordkeeping requirements for API gravity and sulfur content
measurements on the basis that these records were important
verification tools.
Response: In response to comments, we are retaining our proposed
amendment to eliminate the recordkeeping requirements in 40 CFR
[[Page 66455]]
98.397 related to the measurement of API gravity and sulfur content of
crude oil. We are also making several additional amendments to improve
the flexibility of the QA/QC and recordkeeping requirements in the rule
to facilitate the reporting of similar and, in many cases, better
quality data on API gravity, sulfur content, and geographic origin of
crude oil batches while reducing administrative burden. We are amending
40 CFR 98.394(d) to allow refiners to use industry standard practices
to determine the API gravity and sulfur content of crude oil. We are
amending the quantity determination monitoring and QA/QC requirements
in 40 CFR 98.394(a) so that refiners can use industry standard
practices to determine the volume of components of a blended crude
batch (which are never directly measured on site at a refinery).
Therefore, refiners will be able to report representative data they
currently collect on all three crude parameters--(1) API gravity, (2)
sulfur content, and (3) country of origin or crude stream name and
production area--of the components in a blended crude volume instead of
having to report the third parameter as unknown. We are also making a
harmonizing amendment to 40 CFR 98.397(b) to eliminate the requirement
that refiners maintain metering and gauging records for crude oil batch
volumes that they do not measure on site. Together, these amendments
will allow refiners to report crude characteristics contained in crude
assay reports, third party laboratory reports, or pipeline receipt
tickets if the characteristics are representative of the crude oil used
at the refinery and it is an industry standard practice to use these
sources. We have determined that these amendments will still ensure
that the data refiners report is adequately representative of the crude
oil they receive at the refinery and that the records they keep will be
sufficient to support EPA verification of the data. We made this
determination in light of the fact that crude oil data is not used to
calculate the CO2 emissions reported under subpart MM.
Comment: We sought comment on our proposed timeline of implementing
the technical amendments to subpart MM for the 2010 reporting year and
whether this timeline was appropriate considering the nature of the
proposed changes and/or the way in which data have been collected thus
far in 2010. We received one comment indicating that defining ``batch''
in a manner that would require monthly reporting of crude oil volumes
may necessitate modifications to current refinery sampling and
monitoring practices and that refiners may not be able to provide this
information by the March 31, 2011 reporting deadline for 2010 data.
Response: While data collection methods may vary by refinery, we
have determined that refiners currently collect data as part of normal
business practices on the API gravity and sulfur content for at least
one of the five tiers described in the definition of ``batch'' in
today's rule and should therefore be able to meet the crude oil
reporting requirements in 40 CFR 98.396(a)(20) in a timely manner.
However, since we did not include a definition of ``batch'' in the
final rule (74 FR 56260), refiners may not have established data
collection and management systems in 2010 to link the information they
collect on API gravity, sulfur content, and volumes of crude batches to
an EIA crude stream code or generic crude stream name and production
area code (i.e., tiers 1 and 2 of the ``batch'' definition). Likewise,
refiners may not have had adequate time to link data they collect on
API gravity and sulfur content from crude coming from a single country
of origin to ``up to a calendar month volume'' (i.e., tiers 3 and 4 of
the ``batch'' definition). We are therefore providing refiners the
flexibility to report at a lower tier for reporting year 2010 if they
do not have appropriate data collection and management systems in place
to readily report the information in the higher tier.
S. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the definition of the term ``Fuelh'' in
Equation NN-1 of subpart NN to clarify that the abbreviation ``Mscf''
refers to ``thousand standard cubic feet'' in order to avoid confusion
on if this abbreviation means ``million standard cubic feet''. We are
also adding the subscript ``h'' to the terms for Fuel and HHV in
Equation NN-1.
We are amending the definition of the term ``EF'' in Equation NN-7
of subpart NN to clarify that the emission factor is for each natural
gas liquid (NGL) product ``g'' and to add the subscript ``g'' to the
term ``EF.''
We are amending Equation NN-8 of subpart NN to correct the term for
``Annual CO2 mass emissions that would result from the
combustion or oxidation of fractionated NGLs received from other
fractionators'' from ``CO2j'' to ``CO2m''. We are
also amending Equation NN-8 to remove the summation signs that were
unnecessary from this equation for clarification purposes. We are also
amending the definition of the term CO2i to clarify that
this term includes NGLs delivered to customers or, on behalf of,
customers, recognizing that some customers may not receive the NGLs
directly.
We are amending 40 CFR 98.406(a)(6) to correct two cross
references. The incorrect references referred the reader to 40 CFR
98.406(b)(1) and (b)(2), when they were supposed to refer to 40 CFR
98.406(a)(1) and (a)(2). Similarly, we are amending an incorrect
reference in 40 CFR 98.407(d) to refer the reader to 40 CFR
98.406(b)(7) instead of 40 CFR 98.406(b)(6).
We are amending 40 CFR 98.406(a)(9) to correct the abbreviation of
NGL (from LNG) and to specify that reporting under that paragraph is
for each product type.
We are amending 40 CFR 98.407(a) to remove the word ``daily''
because daily meter readings are not specifically required under this
subpart.
Finally, we are updating the high heat values (HHVs) and default
CO2 emission factors in Tables NN-1 and NN-2 to subpart NN
to be consistent with the emission factors in Tables C-1 to subpart C
and MM-1 to subpart MM.
2. Summary of Comments and Responses
There were no major comments received on the proposed amendments to
this section. A few comments seeking minor technical clarification or
correction were received on this subpart. Responses to these comments
can be found in Response to Comments: Technical Corrections, Clarifying
and Other Amendments document (see EPA-HQ-OAR-2010-0109).
III. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under the executive order.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
These amendments do not make any substantive changes to the reporting
requirements in any of the subparts for which amendments are being
made. In many cases, the amendments to the reporting requirements
reduce the reporting burden by making the reporting requirements
conform more
[[Page 66456]]
closely to current industry practices. However, the Office of
Management and Budget (OMB) has previously approved the information
collection requirements contained in the regulations promulgated on
October 30, 2009, under 40 CFR Part 98 under the provisions of the
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB
control number 2060-0629. Burden is defined at 5 CFR 1320.3(b). An
agency may not conduct or sponsor, and a person is not required to
respond to, a collection of information unless it displays a currently
valid OMB control number. The OMB control numbers for EPA's regulations
in 40 CFR are listed in 40 CFR part 9.
Further information on EPA's assessment on the impact on burden can
be found in the Technical Corrections and Amendments Cost Memo (EPA-HQ-
OAR-2010-0109).
C. Regulatory Flexibility Act (RFA)
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of these amendments on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
After considering the economic impacts of these rule amendments on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The rule
amendments will not impose any new requirement on small entities that
are not currently required by Part 98 promulgated on October 30, 2009
(i.e., calculating and reporting annual GHG emissions).
EPA took several steps to reduce the impact on small entities. For
example, EPA determined appropriate thresholds that reduced the number
of small businesses reporting. In addition, EPA did not require
facilities to install CEMS if they did not already have them.
Facilities without CEMS can calculate emissions using readily available
data or data that are less expensive to collect such as process data or
material consumption data. For some source categories, EPA developed
tiered methods that are simpler and less burdensome. Also, EPA required
annual instead of more frequent reporting. Finally, EPA continues to
conduct significant outreach on the mandatory GHG reporting rule and
maintains an ``open door'' policy for stakeholders to help inform EPA's
understanding of key issues for the industries.
D. Unfunded Mandates Reform Act (UMRA)
This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local or
tribal governments or the private sector. In addition, EPA determined
that the rule amendments contain no regulatory requirements that might
significantly or uniquely affect small governments because the
amendments will not impose any new requirements that are not currently
required by Part 98 promulgated on October 30, 2009 (i.e., calculating
and reporting annual GHG emissions), and the rule amendments will not
unfairly apply to small governments. Therefore, this action is not
subject to the requirements of CAA section 203 of the UMRA.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It will not have
substantial direct effects on the States, on the relationship between
the national government and the States, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. However, for a more detailed
discussion about how these rule amendments will relate to existing
State programs, please see Section II of the proposal preamble for the
Mandatory GHG Reporting Rule (74 FR 16457-16461, April 10, 2009).
These amendments apply directly to facilities that supply fuel that
when used emit greenhouse gases or facilities that directly emit
greenhouses gases. They do not apply to governmental entities unless
the government entity owns a facility that directly emits greenhouse
gases above threshold levels (such as a landfill), so relatively few
government facilities will be affected. This regulation also does not
limit the power of States or localities to collect GHG data and/or
regulate GHG emissions. Thus, Executive Order 13132 does not apply to
this action.
Although section 6 of Executive Order 13132 does not apply to this
action, EPA did consult with State and local officials or
representatives of State and local governments in developing Part 98. A
summary of EPA's consultations with State and local governments is
provided in Section VIII.E of the preamble to Part 98 (74 FR 56260,
October 30, 2009).
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The rule
amendments will not result in any changes to the requirements of Part
98. Thus, Executive Order 13175 does not apply to this action.
Although Executive Order 13175 does not apply to this action, EPA
sought opportunities to provide information to Tribal governments and
representatives during the development of the rules promulgated on
October 30, 2009. A summary of the EPA's consultations with Tribal
officials is provided Sections VIII.E and VIII.F of the preamble to the
2009 Final Mandatory GHG Reporting Rule (74 FR 56260, October 30,
2009).
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997)
as applying only to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the executive order has the potential to influence the regulation. This
action is not subject to Executive Order 13045 because it does not
establish an environmental standard intended to mitigate health or
safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This action is not subject to Executive Order 13211 (66 FR 28355,
May 22, 2001), because it is not a significant regulatory action under
Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs
EPA to
[[Page 66457]]
use voluntary consensus standards in its regulatory activities unless
to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
This rulemaking involves the use of one new voluntary consensus
standard from ASTM. Specifically, EPA will allow facilities in the
glass industry to use ASTM D6349-09 Standard Test Method for
Determination of Major and Minor Elements in Coal, Coke, and Solid
Residues from Combustion of Coal and Coke by Inductively Coupled
Plasma--Atomic Emission Spectrometry in addition to the methods
incorporated by reference in Part 98. This additional voluntary
consensus standard will provide an alternative method that owners or
operators in the glass industry can use to monitor GHG emissions. No
new test methods were developed for this action.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that Part 98 does not have disproportionately
high and adverse human health or environmental effects on minority or
low-income populations because it does not affect the level of
protection provided to human health or the environment because it is a
rule addressing information collection and reporting procedures.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on November 29, 2010.
List of Subjects
40 CFR Part 86
Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements, Motor
vehicle pollution.
40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.
Dated: October 7, 2010.
Lisa P. Jackson,
Administrator.
0
For the reasons set out in the preamble, title 40, Chapter I, of the
Code of Federal Regulations is amended as follows:
PART 86--[AMENDED]
0
1. The authority citation for part 86 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
0
2. Section 86.1844-01 is amended by adding paragraph (j) to read as
follows:
Sec. 86.1844-01 Information requirements: Application for
certification and submittal of information upon request.
* * * * *
(j) For complete heavy-duty vehicles only, measure CO2,
N2O, and CH4 as described in this paragraph (j)
with each certification test on an emission data vehicle. Do not apply
deterioration factors to the results. Use the analytical equipment and
procedures specified in 40 CFR part 1065 as needed to measure
N2O and CH4. Report these values in your
application for certification. The requirements of this paragraph (j)
apply starting with model year 2011 for CO2 and 2012 for
CH4. The requirements of this paragraph (j) related to
N2O emissions apply for test groups that depend on
NOX after-treatment to meet emission standards starting with
model year 2013. Businesses that are defined as a small business by the
Small Business Administration size standards in 13 CFR 121.201 may omit
measurement of N2O and CH4; other manufacturers
may provide appropriate data and/or information and omit measurement of
N2O and CH4 as described in 40 CFR 1065.5. Use
the same measurement methods as for your other results to report a
single value for CO2, N2O, and CH4.
Round the final values as follows:
(1) Round CO2 to the nearest 1 g/mi.
(2) Round N2O to the nearest 0.001 g/mi.
(3) Round CH4 to the nearest 0.001 g/mi.
PART 98--[AMENDED]
0
3. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
0
4. Section 98.6 is amended by:
0
a. Removing the definition of ``Argon-oxygen decarburization (AOD)
vessel.''
0
b. Adding a definition for ``Decarburization vessel.''
0
c. Revising the definitions of ``Carbonate-based mineral,''
``Carbonate-based mineral mass fraction,'' ``Carbonate-based raw
material,'' ``Crude oil,'' ``Gas collection system or landfill gas
collection system,'' ``Mscf,'' and ``Non-crude feedstocks.''
The addition and revisions read as follows:
Sec. 98.6 Definitions.
* * * * *
Carbonate-based mineral means any of the following minerals used in
the manufacture of glass: Calcium carbonate (CaCO3), calcium
magnesium carbonate (CaMg(CO3)2), sodium
carbonate (Na2CO3), barium carbonate
(BaCO3), potassium carbonate (K2CO3),
lithium carbonate (Li2CO3), and strontium
carbonate (SrCO3).
Carbonate-based mineral mass fraction means the following: For
limestone, the mass fraction of calcium carbonate (CaCO3) in
the limestone; for dolomite, the mass fraction of calcium magnesium
carbonate (CaMg(CO3)2) in the dolomite; for soda
ash, the mass fraction of sodium carbonate
(Na2CO3) in the soda ash; for barium carbonate,
the mass fraction of barium carbonate (BaCO3) in the barium
carbonate; for potassium carbonate, the mass fraction of potassium
carbonate (K2CO3) in the potassium carbonate; for
lithium carbonate, the mass fraction of lithium carbonate
(Li2CO3); and for strontium
[[Page 66458]]
carbonate, the mass fraction of strontium carbonate (SrCO3).
Carbonate-based raw material means any of the following materials
used in the manufacture of glass: Limestone, dolomite, soda ash, barium
carbonate, potassium carbonate, lithium carbonate, and strontium
carbonate.
* * * * *
Crude oil means a mixture of hydrocarbons that exists in liquid
phase in natural underground reservoirs and remains liquid at
atmospheric pressure after passing through surface separating
facilities. (1) Depending upon the characteristics of the crude stream,
it may also include any of the following:
(i) Small amounts of hydrocarbons that exist in gaseous phase in
natural underground reservoirs but are liquid at atmospheric conditions
(temperature and pressure) after being recovered from oil well (casing-
head) gas in lease separators and are subsequently commingled with the
crude stream without being separately measured. Lease condensate
recovered as a liquid from natural gas wells in lease or field
separation facilities and later mixed into the crude stream is also
included.
(ii) Small amounts of non-hydrocarbons, such as sulfur and various
metals.
(iii) Drip gases, and liquid hydrocarbons produced from tar sands,
oil sands, gilsonite, and oil shale.
(iv) Petroleum products that are received or produced at a refinery
and subsequently injected into a crude supply or reservoir by the same
refinery owner or operator.
(2) Liquids produced at natural gas processing plants are excluded.
Crude oil is refined to produce a wide array of petroleum products,
including heating oils; gasoline, diesel and jet fuels; lubricants;
asphalt; ethane, propane, and butane; and many other products used for
their energy or chemical content.
* * * * *
Decarburization vessel means any vessel used to further refine
molten steel with the primary intent of reducing the carbon content of
the steel, including but not limited to vessels used for argon-oxygen
decarburization and vacuum oxygen decarburization.
* * * * *
Gas collection system or landfill gas collection system means a
system of pipes used to collect landfill gas from different locations
in the landfill by means of a fan or similar mechanical draft equipment
to a single location for treatment (thermal destruction) or use.
Landfill gas collection systems may also include knock-out or separator
drums and/or a compressor. A single landfill may have multiple gas
collection systems. Landfill gas collection systems do not include
``passive'' systems, whereby landfill gas flows naturally to the
surface of the landfill where an opening or pipe (vent) is installed to
allow for natural gas flow.
* * * * *
Mscf means thousand standard cubic feet.
* * * * *
Non-crude feedstocks means any petroleum product or natural gas
liquid that enters the refinery to be further refined or otherwise used
on site.
* * * * *
5. Section 98.7 is amended by removing and reserving paragraph (a),
and adding paragraph (e)(45).
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
* * * * *
(e) * * *
(45) ASTM D6349-09 Standard Test Method for Determination of Major
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of
Coal and Coke by Inductively Coupled Plasma--Atomic Emission
Spectrometry, IBR approved for Sec. 98.144(b).
* * * * *
Subpart E--[Amended]
0
6. Section 98.53 is revised to read as follows:
Sec. 98.53 Calculating GHG emissions.
(a) You must determine annual N2O emissions from adipic
acid production according to paragraphs (a)(1) or (2) of this section.
(1) Use a site-specific emission factor and production data
according to paragraphs (b) through (i) of this section.
(2) Request Administrator approval for an alternative method of
determining N2O emissions according to paragraphs (a)(2)(i)
and (ii) of this section.
(i) You must submit the request within 45 days following
promulgation of this subpart or within the first 30 days of each
subsequent reporting year.
(ii) If the Administrator does not approve your requested
alternative method within 150 days of the end of the reporting year,
you must determine the N2O emissions for the current
reporting period using the procedures specified in paragraphs (b)
through (h) of this section.
(b) You must conduct an annual performance test according to
paragraphs (b)(1) through (3) of this section.
(1) You must conduct the test on the vent stream from the nitric
acid oxidation step of the process, referred to as the test point,
according to the methods specified in Sec. 98.54(b) through (f). If
multiple adipic acid production units exhaust to a common abatement
technology and/or emission point, you must sample each process in the
ducts before the emissions are combined, sample each process when only
one process is operating, or sample the combined emissions when
multiple processes are operating and base the site-specific emission
factor on the combined production rate of the multiple adipic acid
production units.
(2) You must conduct the performance test under normal process
operating conditions.
(3) You must measure the adipic acid production rate during the
test and calculate the production rate for the test period in metric
tons per hour.
(c) Using the results of the performance test in paragraph (b) of
this section, you must calculate an emission factor for each adipic
acid unit according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.018
Where:
EFN2O,z = Average facility-specific
N2O emission factor for each adipic acid production unit
``z'' (lb N2O/ton adipic acid produced).
CN2O = N2O concentration per test
run during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).
[[Page 66459]]
Q = Volumetric flow rate of effluent gas per test run during the
performance test (dscf/hr).
P = Production rate per test run during the performance test (tons
adipic acid produced/hr).
n = Number of test runs.
(d) If any N2O abatement technology ``N'' is located
after your test point, you must determine the destruction efficiency
according to paragraphs (d)(1), (2), or (3) of this section.
(1) Use the manufacturer's specified destruction efficiency.
(2) Estimate the destruction efficiency through process knowledge.
Examples of information that could constitute process knowledge include
calculations based on material balances, process stoichiometry, or
previous test results provided the results are still relevant to the
current vent stream conditions. You must document how process knowledge
was used to determine the destruction efficiency.
(3) Calculate the destruction efficiency by conducting an
additional performance test on the vent stream following the
N2O abatement technology.
(e) If any N2O abatement technology ``N'' is located
after your test point, you must determine the annual amount of adipic
acid produced while N2O abatement technology ``N'' is
operating according to Sec. 98.54(f). Then you must calculate the
abatement factor for N2O abatement technology ``N''
according to Equation E-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.019
Where:
AFN = Abatement utilization factor of N2O
abatement technology ``N'' (fraction of annual production that
abatement technology is operating).
Pz,N = Annual adipic acid production during which
N2O abatement technology ``N'' was used on unit ``z''
(ton adipic acid produced).
Pz = Total annual adipic acid production from unit ``z''
(ton acid produced).
(f) You must determine the annual amount of adipic acid produced
according to Sec. 98.54(f).
(g) You must calculate N2O emissions according to
paragraph (g)(1), (2), (3), or (4) of this section for each adipic acid
production unit.
(1) If one N2O abatement technology ``N'' is located
after your test point, you must use the emissions factor (determined in
Equation E-1 of this section), the destruction efficiency (determined
in paragraph (d) of this section), the annual adipic acid production
(determined in paragraph (f) of this section), and the abatement
utilization factor (determined in paragraph (e) of this section),
according to Equation E-3a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.020
Where:
Ea,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3a (metric
tons).
EFN2Oz = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF = Destruction efficiency of N2O abatement technology
``N'' (percent of N2O removed from vent stream).
AF = Abatement utilization factor of N2O abatement
technology ``N'' (percent of time that the abatement technology is
operating).
2205 = Conversion factor (lb/metric ton).
(2) If multiple N2O abatement technologies are located
in series after your test point, you must use the emissions factor
(determined in Equation E-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
adipic acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation E-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.021
Where:
Eb,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3b (metric
tons).
EFN2O,z = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DF1 = Destruction efficiency of N2O abatement
technology 1 (percent of N2O removed from vent stream).
AF1 = Abatement utilization factor of N2O
abatement technology 1 (percent of time that abatement technology 1
is operating).
DF2 = Destruction efficiency of N2O abatement
technology 2 (percent of N2O removed from vent stream).
AF2 = Abatement utilization factor of N2O
abatement technology 2 (percent of time that abatement technology 2
is operating).
DFN = Destruction efficiency of N2O abatement
technology N (percent of N2O removed from vent stream).
AFN = Abatement utilization factor of N2O
abatement technology N (percent of time that abatement technology N
is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.
(3) If multiple N2O abatement technologies are located
in parallel after your test point, you must use the emissions factor
(determined in Equation E-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
adipic acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation E-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.022
[[Page 66460]]
Where:
Ec,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to this Equation E-3c (metric
tons).
EFN2O,z = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
Pz = Annual adipic acid produced from unit ``z'' (tons).
DFN = Destruction efficiency of N2O abatement
technology ``N'' (percent of N2O removed from vent
stream).
AFN = Abatement utilization factor of N2O
abatement technology ``N'' (percent of time that the abatement
technology is operating).
FCN = Fraction control factor of N2O abatement
technology ``N'' (percent of total emissions from unit ``z'' that
are sent to abatement technology ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a
fraction control factor.
(4) If no N2O abatement technologies are located after
your test point, you must use the emissions factor (determined using
Equation E-1 of this section) and the annual adipic acid production
(determined in paragraph (f) of this section) according to Equation E-
3d of this section for each adipic acid production unit.
[GRAPHIC] [TIFF OMITTED] TR28OC10.023
Where:
Ed,z = Annual N2O mass emissions from adipic
acid production for unit ``z'' according to this Equation E-3d
(metric tons).
EFN2O = N2O emissions factor for
unit ``z'' (lb N2O/ton adipic acid produced).
PZ = Annual adipic acid produced from unit ``z'' (tons).
2205 = Conversion factor (lb/metric ton).
(h) You must determine the emissions for the facility by summing
the unit level emissions according to Equation E-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.024
Where:
Ea,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3a of this
section (metric tons).
Eb,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3b of this
section (metric tons).
Ec,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3c of this
section (metric tons).
Ed,z = Annual N2O mass emissions from adipic
acid production unit ``z'' according to Equation E-3d of this
section (metric tons).
M = Total number of adipic acid production units.
(i) You must determine the amount of process N2O
emissions that is sold or transferred off site (if applicable). You can
determine the amount using existing process flow meters and
N2O analyzers.
0
7. Section 98.54 is amended by:
0
a. Revising paragraph (a) introductory text.
0
b. Adding second and third sentences to the end of paragraph (a)(1).
0
c. Revising paragraph (a)(3).
0
d. Revising paragraph (c) introductory text.
0
e. Revising the first sentence of paragraph (d) introductory text.
0
f. Revising paragraphs (e) and (f).
The revisions and additions read as follows:
Sec. 98.54 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test and calculate a new
emissions factor for each adipic acid production unit according to the
frequency specified in paragraphs (a)(1) through (3) of this section.
(1) * * * The test must be conducted at a point during production
that is representative of the average emissions rate from your process.
You must document the methods used to determine the representative
point.
* * * * *
(3) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec. 98.53(a)(2),
you must conduct the performance test if your request has not been
approved by the Administrator within 150 days of the end of the
reporting year in which it was submitted.
* * * * *
(c) You must determine the adipic acid production rate during the
performance test according to paragraph (c)(1) or (c)(2) of this
section.
* * * * *
(d) You must determine the volumetric flow rate during the
performance test in conjunction with the applicable EPA methods in 40
CFR part 60, appendices A-1 through A-4. * * *
* * * * *
(e) You must determine the monthly amount of adipic acid produced.
You must also determine the monthly amount of adipic acid produced
during which N2O abatement technology, located after the
test point, is operating. These monthly amounts are determined
according to the methods in paragraphs (c)(1) or (2) of this section.
(f) You must determine the annual amount of adipic acid produced.
You must also determine the annual amount of adipic acid produced
during which N2O abatement technology located after the test
point is operating. These are determined by summing the respective
monthly adipic acid production quantities determined in paragraph (e)
of this section.
0
8. Section 98.56 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (j) introductory text.
0
d. Revising paragraph (j)(1).
0
e. Revising paragraph (k) introductory text.
0
f. Adding paragraph (l).
The revisions and addition read as follows:
Sec. 98.56 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (l) of this section at the facility level.
* * * * *
(c) Annual adipic acid production during which N2O
abatement technology (located after the test point) is operating
(tons).
* * * * *
(j) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec. 98.53(a)(1), each annual
report must also contain the information specified in paragraphs (j)(1)
through (7) of this section for each adipic acid production unit.
(1) Emission factor (lb N2O/ton adipic acid).
* * * * *
(k) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec. 98.53(a)(2),
each annual report must also contain the information specified in
paragraphs (k)(1) through (4) of this
[[Page 66461]]
section for each adipic acid production facility.
* * * * *
(l) Fraction control factor for each abatement technology (percent
of total emissions from the production unit that are sent to the
abatement technology) if equation E-3c is used.
0
9. Section 98.57 is amended by revising paragraphs (c) and (f) to read
as follows:
Sec. 98.57 Records that must be retained.
* * * * *
(c) Number of facility and unit operating hours in calendar year.
* * * * *
(f) Performance test reports.
* * * * *
Subpart H--[Amended]
0
10. Section 98.83 is amended by revising the introductory text of
paragraph (d)(3); and by revising the definitions of ``rm'', ``TOCrm'',
and ``M'' in Equation H-5 of paragraph (d)(3) to read as follows:
Sec. 98.83 Calculating GHG emissions.
* * * * *
(d) * * *
(3) CO2 emissions from raw materials. Calculate
CO2 emissions from raw materials using Equation H-5 of this
section:
* * * * *
rm = The amount of raw material i consumed annually, tons/yr (dry
basis) or the amount of raw kiln feed consumed annually, tons/yr
(dry basis).
* * * * *
TOCrm = Organic carbon content of raw material i or organic carbon
content of combined raw kiln feed (dry basis), as determined in
Sec. 98.84(c) or using a default factor of 0.2 percent of total raw
material weight.
M = Number of raw materials or 1 if calculating emissions based on
combined raw kiln feed.
* * * * *
0
11. Section 98.84 is amended by revising paragraphs (b) through (f) to
read as follows:
Sec. 98.84 Monitoring and QA/QC requirements.
* * * * *
(b) You must determine the weight fraction of total CaO and total
MgO in clinker from each kiln using ASTM C114-09 Standard Test Methods
for Chemical Analysis of Hydraulic Cement (incorporated by reference,
see Sec. 98.7). The monitoring must be conducted monthly for each kiln
from a monthly clinker sample drawn from bulk clinker storage if
storage is dedicated to the specific kiln, or from a monthly arithmetic
average of daily clinker samples drawn from the clinker conveying
systems exiting each kiln.
(c) The total organic carbon content (dry basis) of raw materials
must be determined annually using ASTM C114-09 Standard Test Methods
for Chemical Analysis of Hydraulic Cement (incorporated by reference,
see Sec. 98.7) or a similar industry standard practice or method
approved for total organic carbon determination in raw mineral
materials. The analysis must be conducted either on sample material
drawn from bulk raw kiln feed storage or on sample material drawn from
bulk raw material storage for each category of raw material (i.e.,
limestone, sand, shale, iron oxide, and alumina). Facilities that opt
to use the default total organic carbon factor provided in Sec.
98.83(d)(3), are not required to monitor for TOC.
(d) The quantity of clinker produced monthly by each kiln must be
determined by direct weight measurement of clinker using the same plant
techniques used for accounting purposes, such as reconciling weigh
hopper or belt weigh feeder measurements against inventory
measurements. As an alternative, facilities may also determine clinker
production by direct measurement of raw kiln feed and application of a
kiln-specific feed-to-clinker factor. Facilities that opt to use a
feed-to-clinker factor must verify the accuracy of this factor on a
monthly basis.
(e) The quantity of CKD not recycled to the kiln generated by each
kiln must be determined quarterly using the same plant techniques used
for accounting purposes, such as direct weight measurement using weigh
hoppers, truck weigh scales, or belt weigh feeders.
(f) The annual quantity of raw kiln feed or annual quantity of each
category of raw materials consumed by the facility (e.g., limestone,
sand, shale, iron oxide, and alumina) must be determined monthly by
direct weight measurement using the same plant instruments used for
accounting purposes, such as weigh hoppers, truck weigh scales, or belt
weigh feeders.
* * * * *
0
12. Section 98.86 is amended by:
0
a. Revising paragraph (b)(3).
0
b. Revising paragraph (b)(4).
0
c. Revising paragraph (b)(12).
0
d. Revising paragraph (b)(13).
0
e. Adding paragraph (b)(15).
The revisions and addition read as follows:
Sec. 98.86 Data reporting requirements.
* * * * *
(b) * * *
(3) Annual cement production at the facility.
(4) Number of kilns and number of operating kilns.
* * * * *
(12) Annual organic carbon content of raw kiln feed or annual
organic carbon content of each raw material (wt-fraction, dry basis).
(13) Annual consumption of raw kiln feed or annual consumption of
each raw material (dry basis).
* * * * *
(15) Method used to determine the monthly clinker production from
each kiln reported under (b)(2) of this section, including monthly
kiln-specific clinker factors, if used.
13. Section 98.87 is revised to read as follows:
Sec. 98.87 Records that must be retained.
(a) If a CEMS is used to measure CO2 emissions, then in
addition to the records required by Sec. 98.3(g), you must retain
under this subpart the records required for the Tier 4 Calculation
Methodology in Sec. 98.37.
(b) If a CEMS is not used to measure CO2 emissions, then
in addition to the records required by Sec. 98.3(g), you must retain
the records specified in this paragraph (b) for each portland cement
manufacturing facility.
(1) Documentation of monthly calculated kiln-specific clinker
CO2 emission factor.
(2) Documentation of quarterly calculated kiln-specific CKD
CO2 emission factor.
(3) Measurements, records and calculations used to determine
reported parameters.
Subpart K--[Amended]
0
14. Section 98.112 is amended by revising paragraph (a) to read as
follows:
Sec. 98.112 GHGs to report.
* * * * *
(a) Process CO2 emissions from each electric arc furnace
(EAF) used for the production of any ferroalloy listed in Sec. 98.110,
and process CH4 emissions from each EAF that is used for the
production of any ferroalloy listed in Table K-1 to subpart K.
* * * * *
0
15. Section 98.113 is amended by revising the introductory text to read
as follows:
Sec. 98.113 Calculating GHG emissions.
You must calculate and report the annual process CO2
emissions from each
[[Page 66462]]
EAF not subject to paragraph (c) of this section using the procedures
in either paragraph (a) or (b) of this section. For each EAF also
subject to annual process CH4 emissions reporting, you must
also calculate and report the annual process CH4 emissions
from the EAF using the procedures in paragraph (d) of this section.
* * * * *
0
16. Section 98.116 is amended by:
0
a. Revising paragraph (b).
0
b. Revising paragraph (c).
0
c. Revising paragraph (d) introductory text.
0
d. Revising paragraph (d)(1).
0
e. Revising paragraph (e)(1).
The revisions read as follows:
Sec. 98.116 Data reporting requirements.
* * * * *
(b) Annual production for each ferroalloy product identified in
Sec. 98.110, from each EAF (tons).
(c) Total number of EAFs at facility used for production of
ferroalloy products.
(d) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec. 98.36 for the Tier 4 Calculation Methodology and the following
information specified in paragraphs (d)(1) through (d)(3) of this
section.
(1) Annual process CO2 emissions (in metric tons) from
each EAF used for the production of any ferroalloy product identified
in Sec. 98.110.
* * * * *
(e) * * *
(1) Annual process CO2 emissions (in metric tons) from
each EAF used for the production of any ferroalloy identified in Sec.
98.110 (metric tons).
* * * * *
Subpart N--[Amended]
0
17. Section 98.144 is amended by revising paragraph (b) to read as
follows:
Sec. 98.144 Monitoring and QA/QC requirements.
* * * * *
(b) You must measure carbonate-based mineral mass fractions at
least annually to verify the mass fraction data provided by the
supplier of the raw material; such measurements shall be based on
sampling and chemical analysis using ASTM D3682-01 (Reapproved 2006)
Standard Test Method for Major and Minor Elements in Combustion
Residues from Coal Utilization Processes (incorporated by reference,
see Sec. 98.7) or ASTM D6349-09 Standard Test Method for Determination
of Major and Minor Elements in Coal, Coke, and Solid Residues from
Combustion of Coal and Coke by Inductively Coupled Plasma--Atomic
Emission Spectrometry (incorporated by reference, see Sec. 98.7).
* * * * *
0
18. Section 98.146 is amended by:
0
a. Revising paragraph (a) introductory text.
0
b. Revising paragraph (a)(2).
0
c. Revising paragraph (b)(7).
0
d. Revising paragraph (b)(9).
The revisions read as follows:
Sec. 98.146 Data reporting requirements.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required under
Sec. 98.36 for the Tier 4 Calculation Methodology and the following
information specified in paragraphs (a)(1) and (2) of this section:
* * * * *
(2) Annual quantity of glass produced by each glass melting furnace
and by all furnaces combined (tons).
(b) * * *
(7) Method used to determine fraction of calcination.
* * * * *
(9) The number of times in the reporting year that missing data
procedures were followed to measure monthly quantities of carbonate-
based raw materials or mass fraction of the carbonate-based minerals
for any continuous glass melting furnace (months).
0
19. In the Table to Subpart N of Part 98, Table N-1 to subpart N is
amended by adding entries for ``Barium carbonate,'' ``Potassium
carbonate,'' ``Lithium carbonate,'' and ``Strontium carbonate'' to the
end of the table to read as follows:
Table to Subpart N of Part 98
Table N-1 to Subpart N--CO2 Emission Factors for Carbonate-Based Raw
Materials
------------------------------------------------------------------------
CO2 emission
Carbonate-based raw material--mineral factor \a\
------------------------------------------------------------------------
* * * * * * *
Barium carbonate--BaCO3................................. 0.223
Potassium carbonate--K2CO3.............................. 0.318
Lithium carbonate (Li2CO3).............................. 0.596
Strontium carbonate (SrCO3)............................. 0.298
------------------------------------------------------------------------
\a\ Emission factors in units of metric tons of CO2 emitted per metric
ton of carbonate-based raw material charged to the furnace.
Subpart O--[Amended]
0
20. Section 98.154 is amended by:
0
a. Revising the first and second sentences of paragraph (k).
0
b. Revising the second sentence of paragraph (l) introductory text.
0
c. Revising paragraph (o).
The revisions read as follows:
Sec. 98.154 Monitoring and QA/QC requirements.
* * * * *
(k) The mass of HFC-23 emitted from process vents shall be
estimated at least monthly by incorporating the results of the most
recent emissions test into Equation O-7 of this subpart. HCFC-22
production facilities that use a destruction device connected to the
HCFC-22 production equipment shall conduct emissions tests at process
vents at least once every five years or after significant changes to
the process. * * *
(l) * * * HFC-23 destruction facilities shall conduct annual
measurements of HFC-23 concentrations at the outlet of the destruction
device in accordance with EPA Method 18 at 40 CFR part 60, appendix A-
6. * * *
* * * * *
(o) In their estimates of the mass of HFC-23 destroyed, HFC-23
destruction facilities shall account for any temporary reductions in
the destruction efficiency that result from any startups, shutdowns, or
malfunctions of the destruction device, including departures from the
operating conditions defined in State or local permitting requirements
[[Page 66463]]
and/or destruction device manufacturer specifications.
* * * * *
0
21. Section 98.156 is amended by:
0
a. Revising paragraph (b)(1).
0
b. Revising paragraph (b)(3).
0
c. Revising paragraph (c).
0
d. Revising paragraph (d).
0
e. Revising paragraph (e) introductory text.
The revisions read as follows:
Sec. 98.156 Data reporting requirements.
* * * * *
(b) * * *
(1) Annual mass of HFC-23 fed into the destruction device.
* * * * *
(3) Annual mass of HFC-23 emitted from the destruction device.
(c) Each HFC-23 destruction facility shall report the concentration
(mass fraction) of HFC-23 measured at the outlet of the destruction
device during the facility's annual HFC-23 concentration measurements
at the outlet of the device.
(d) If the HFC-23 concentration measured pursuant to Sec.
98.154(l) is greater than that measured during the performance test
that is the basis for the destruction efficiency (DE), the facility
shall report the revised destruction efficiency calculated under Sec.
98.154(l) and the values used to calculate it, specifying whether Sec.
98.154(l)(1) or Sec. 98.154(l)(2) has been used for the calculation.
Specifically, the facility shall report the following:
(1) Flow rate of HFC-23 being fed into the destruction device in
kg/hr.
(2) Concentration (mass fraction) of HFC-23 at the outlet of the
destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate (in kg/hr) calculated from paragraphs (d)(2) and
(d)(3) of this section.
(5) Destruction efficiency (DE) calculated from paragraphs (d)(1)
and (d)(4) of this section.
(e) By March 31, 2011 or within 60 days of commencing HFC-23
destruction, HFC-23 destruction facilities shall submit a one-time
report including the following information for each destruction
process:
* * * * *
0
22. Section 98.157 is amended by revising paragraph (b)(1) to read as
follows:
Sec. 98.157 Records that must be retained.
* * * * *
(b) * * *
(1) Records documenting their one-time and annual reports in Sec.
98.156(b) through (e).
* * * * *
Subpart P--[Amended]
0
23. Section 98.160 is amended by revising paragraph (c) to read as
follows:
Sec. 98.160 Definition of the source category.
* * * * *
(c) This source category includes merchant hydrogen production
facilities located within another facility if they are not owned by, or
under the direct control of, the other facility's owner and operator.
0
24. Section 98.162 is amended by revising paragraph (a) and removing
and reserving paragraph (b).
The revision reads as follows:
Sec. 98.162 GHGs to report.
* * * * *
(a) CO2 emissions from each hydrogen production process
unit.
* * * * *
0
25. Section 98.163 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (a).
0
c. Revising paragraph (b) introductory text.
0
d. In paragraph (b)(1), revising the introductory text and revising the
definition of ``CO2'' in Equation P-1.
0
e. Revising paragraphs (b)(2) introductory text and (b)(3) introductory
text.
The revisions read as follows:
Sec. 98.163 Calculating GHG emissions.
You must calculate and report the annual CO2 emissions
from each hydrogen production process unit using the procedures
specified in either paragraph (a) or (b) of this section.
(a) Continuous Emissions Monitoring Systems (CEMS). Calculate and
report under this subpart the CO2 emissions by operating and
maintaining CEMS according to the Tier 4 Calculation Methodology
specified in Sec. 98.33(a)(4) and all associated requirements for Tier
4 in subpart C of this part (General Stationary Fuel Combustion
Sources).
(b) Fuel and feedstock material balance approach. Calculate and
report CO2 emissions as the sum of the annual emissions
associated with each fuel and feedstock used for hydrogen production by
following paragraphs (b)(1) through (b)(3) of this section.
(1) Gaseous fuel and feedstock. You must calculate the annual
CO2 emissions from each gaseous fuel and feedstock according
to Equation P-1 of this section:
* * * * *
CO2 = Annual CO2 emissions arising from fuel
and feedstock consumption (metric tons/yr).
* * * * *
(2) Liquid fuel and feedstock. You must calculate the annual
CO2 emissions from each liquid fuel and feedstock according
to Equation P-2 of this section:
* * * * *
(3) Solid fuel and feedstock. You must calculate the annual
CO2 emissions from each solid fuel and feedstock according
to Equation P-3 of this section:
* * * * *
0
26. Section 98.166 is amended by revising the introductory text and
paragraphs (a)(1), (b)(1), and (c) to read as follows:
Sec. 98.166 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as appropriate, and paragraphs (c) and (d) of
this section:
(a) * * *
(1) Unit identification number and annual CO2 emissions.
* * * * *
(b) * * *
(1) Unit identification number and annual CO2 emissions.
* * * * *
(c) Quantity of CO2 collected and transferred off site
in either gas, liquid, or solid forms, following the requirements of
subpart PP of this part.
* * * * *
Subpart Q--[Amended]
0
27. Section 98.172 is amended by revising paragraphs (b) and (c) to
read as follows:
Sec. 98.172 GHGs to report.
* * * * *
(b) You must report CO2 emissions from flares that burn
blast furnace gas or coke oven gas according to the procedures in Sec.
98.253(b)(1) of subpart Y (Petroleum Refineries) of this part. When
using the alternatives set forth in Sec. 98.253(b)(1)(ii)(B) and Sec.
98.253(b)(1)(iii)(C), you must use the default CO2 emission
factors for coke oven gas and blast furnace gas from Table C-1 to
subpart C in Equations Y-2 and Y-3 of subpart Y. You must report
CH4 and N2O emissions from flares according to
the requirements in Sec. 98.33(c)(2) using the emission factors for
coke oven gas and blast furnace gas in Table C-2 to subpart C of this
part.
(c) You must report process CO2 emissions from each
taconite indurating
[[Page 66464]]
furnace; basic oxygen furnace; non-recovery coke oven battery
combustion stack; coke pushing process; sinter process; EAF;
decarburization vessel; and direct reduction furnace by following the
procedures in this subpart.
0
28. Section 98.173 is amended by:
0
a. Revising the first sentence of the introductory text.
0
b. In paragraph (b)(1)(vi), revising the introductory text and the
definition of ``CO2'' in Equation Q-6 of subpart Q.
0
c. Revising the first sentence of paragraph (d).
The revisions read as follows:
Sec. 98.173 Calculating GHG emissions.
You must calculate and report the annual process CO2
emissions from each taconite indurating furnace, basic oxygen furnace,
non-recovery coke oven battery, sinter process, EAF, decarburization
vessel, and direct reduction furnace using the procedures in either
paragraph (a) or (b) of this section. * * *
* * * * *
(b) * * *
(1) * * *
(vi) For decarburization vessels, estimate CO2 emissions
using Equation Q-6 of this section.
* * * * *
CO2 = Annual CO2 mass emissions from the
decarburization vessel (metric tons).
* * * * *
(d) If GHG emissions from a taconite indurating furnace, basic
oxygen furnace, non-recovery coke oven battery, sinter process, EAF,
decarburization vessel, or direct reduction furnace are vented through
the same stack as any combustion unit or process equipment that reports
CO2 emissions using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part (General Stationary
Fuel Combustion Sources), then the calculation methodology in paragraph
(b) of this section shall not be used to calculate process emissions. *
* *
0
29. Section 98.174 is amended by revising the first sentence of
paragraph (c)(2) and revising paragraph (c)(7) to read as follows:
Sec. 98.174 Monitoring and QA/QC requirements.
* * * * *
(c) * * *
(2) For the furnace exhaust from basic oxygen furnaces, EAFs,
decarburization vessels, and direct reduction furnaces, sample the
furnace exhaust for at least three complete production cycles that
start when the furnace is being charged and end after steel or iron and
slag have been tapped. * * *
* * * * *
(7) If your EAF and decarburization vessel exhaust to a common
emission control device and stack, you must sample each process in the
ducts before the emissions are combined, sample each process when only
one process is operating, or sample the combined emissions when both
processes are operating and base the site-specific emission factor on
the steel production rate of the EAF.
* * * * *
0
30. Section 98.175 is amended by revising the introductory text to read
as follows:
Sec. 98.175 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations in Sec. 98.173 is required. Therefore, whenever
a quality-assured value of a required parameter is unavailable, a
substitute data value for the missing parameter shall be used in the
calculations as specified in the paragraphs (a) and (b) of this
section. You must follow the missing data procedures in Sec. 98.255(b)
of subpart Y (Petroleum Refineries) of this part for flares burning
coke oven gas or blast furnace gas. You must document and keep records
of the procedures used for all such estimates.
* * * * *
0
31. Section 98.176 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (e)(3).
0
d. Adding paragraphs (g) and (h).
The revisions and additions read as follows:
Sec. 98.176 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information required in paragraphs (a)
through (h) of this section for each coke pushing operation; taconite
indurating furnace; basic oxygen furnace; non-recovery coke oven
battery; sinter process; EAF; decarburization vessel; direct reduction
furnace; and flare burning coke oven gas or blast furnace gas. For
reporting year 2010, the information required in paragraphs (a) through
(h) of this section is not required for decarburization vessels that
are not argon-oxygen decarburization vessels. For reporting year 2011
and each subsequent reporting year, the information in paragraphs (a)
through (h) of this section must be reported for all decarburization
vessels.
* * * * *
(c) If a CEMS is used to measure CO2 emissions, then you
must report the relevant information required under Sec. 98.36 for the
Tier 4 Calculation Methodology.
* * * * *
(e) * * *
(3) The annual volume of each type of gaseous fuel (reported
separately for each type in standard cubic feet), the annual volume of
each type of liquid fuel (reported separately for each type in
gallons), and the annual mass (in metric tons) of each other process
inputs and outputs used to determine CO2 emissions.
* * * * *
(g) The annual amount of coal charged to the coke ovens (in metric
tons).
(h) For flares burning coke oven gas or blast furnace gas, the
information specified in Sec. 98.256(e) of subpart Y (Petroleum
Refineries) of this part.
0
32. Section 98.177 is amended by revising paragraph (d) to read as
follows:
Sec. 98.177 Records that must be retained.
* * * * *
(d) Annual operating hours for each taconite indurating furnace,
basic oxygen furnace, non-recovery coke oven battery, sinter process,
electric arc furnace, decarburization vessel, and direct reduction
furnace.
* * * * *
Subpart S--[Amended]
0
33. Section 98.190 is amended by revising paragraph (a) to read as
follows:
Sec. 98.190 Definition of the source category.
(a) 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 lime products) by calcination of limestone, dolomite, shells or
other calcareous substances as defined in 40 CFR 63.7081(a)(1).
* * * * *
0
34. Section 98.193 is amended by:
0
a. In paragraph (b)(2)(i), revising the second sentence of the
introductory text and the definition of ``2000/2205'' in Equation S-1.
0
b. In paragraph (b)(2)(ii), revising the introductory text and the
definitions of ``EFLKD,i,n'', ``CaOLKD,i,n'',
``MgOLKD,i,n'', and ``2000/2205'' in Equation S-2.
0
c. In paragraph (b)(2)(iii), revising the introductory text and the
definitions of
[[Page 66465]]
``Ewaste,i'', ``CaOwaste,i'',
``MgOwaste,i'', ``Mwaste,i'', and ``2000/2205''
in Equation S-3.
0
d. In Paragraph (b)(2)(iv), revising the definitions of
``EFLIME,i,n'', ``MLIME,i,n'',
``EFLKD,i,n'', ``MLKD,i,n'',
``Ewaste,i'', ``t'', ``b'', and ``z'' in Equation S-4.
The revisions read as follows:
Sec. 98.193 Calculating GHG emissions.
* * * * *
(b) * * *
(2) * * *
(i) * * * Calcium oxide and magnesium oxide content must be
analyzed monthly for each lime product type that is produced:
* * * * *
2000/2205 = Conversion factor for tons to metric tons.
(ii) You must calculate a monthly emission factor for each type of
calcined byproduct/waste sold (including lime kiln dust) using Equation
S-2 of this section:
* * * * *
EFLKD,i,n = Emission factor for calcined lime byproduct/
waste type i sold, for month n (metric tons CO2/ton lime
byproduct).
* * * * *
CaOLKD,i,n = Calcium oxide content for calcined lime
byproduct/waste type i sold, for month n (metric tons CaO/metric ton
lime).
MgOLKD,i,n = Magnesium oxide content for calcined lime
byproduct/waste type i sold, for month n (metric tons MgO/metric ton
lime).
2000/2205 = Conversion factor for tons to metric tons.
(iii) You must calculate the annual CO2 emissions from
each type of calcined byproduct/waste that is not sold (including lime
kiln dust and scrubber sludge) using Equation S-3 of this section:
* * * * *
Ewaste,i = Annual CO2 emissions for calcined
lime byproduct/waste type i that is not sold (metric tons
CO2).
* * * * *
CaOwaste,i = Calcium oxide content for calcined lime
byproduct/waste type i that is not sold (metric tons CaO/metric ton
lime).
MgOwaste,i = Magnesium oxide content for calcined lime
byproduct/waste type i that is not sold (metric tons MgO/metric ton
lime).
Mwaste,i = Annual weight or mass of calcined byproducts/
wastes for lime type i that is not sold (tons).
2000/2205 = Conversion factor for tons to metric tons.
(iv) * * *
EFLIME,i,n = Emission factor for lime type i produced, in
calendar month n (metric tons CO2/ton lime) from Equation
S-1 of this section.
MLIME,i,n = Weight or mass of lime type i produced in
calendar month n (tons).
EFLKD,i,n = Emission factor of calcined byproducts/wastes
sold for lime type i in calendar month n, (metric tons
CO2/ton byproduct/waste) from Equation S-2 of this
section.
MLKD,i,n = Monthly weight or mass of calcined byproducts/
waste sold (such as lime kiln dust, LKD) for lime type i in calendar
month n (tons).
Ewaste,i = Annual CO2 emissions for calcined
lime byproduct/waste type i that is not sold (metric tons
CO2) from Equation S-3 of this section.
t = Number of lime types produced
b = Number of calcined byproducts/wastes that are sold
z = Number of calcined byproducts/wastes that are not sold
* * * * *
0
35. Section 98.194 is amended by:
0
a. Revising the first sentence of paragraph (a).
0
b. Revising paragraph (c) introductory text.
0
c. Revising paragraph (d).
The revisions read as follows:
Sec. 98.194 Monitoring and QA/QC requirements.
(a) You must determine the total quantity of each type of lime
product that is produced and each calcined byproduct/waste (such as
lime kiln dust) that is sold. * * *
* * * * *
(c) You must determine the chemical composition (percent total CaO
and percent total MgO) of each type of lime product that is produced
and each type of calcined byproduct/waste sold according to paragraph
(c)(1) or (2) of this section. You must determine the chemical
composition of each type of lime product that is produced and each type
of calcined byproduct/waste sold on a monthly basis. You must determine
the chemical composition for each type of calcined byproduct/waste that
is not sold on an annual basis.
* * * * *
(d) You must use the analysis of calcium oxide and magnesium oxide
content of each lime product that is produced and that is collected
during the same month as the production data in monthly calculations.
* * * * *
0
36. Section 98.195 is amended by revising the first sentence of the
introductory text and paragraph (a) to read as follows:
Sec. 98.195 Procedures for estimating missing data.
For the procedure in Sec. 98.193(b)(1), a complete record of all
measured parameters used in the GHG emissions calculations is required
(e.g., oxide content, quantity of lime products, etc.). * * *
(a) For each missing value of the quantity of lime produced (by
lime type), and quantity of calcined byproduct/waste produced and sold,
the substitute data value shall be the best available estimate based on
all available process data or data used for accounting purposes.
* * * * *
0
37. Section 98.196 is revised to read as follows:
Sec. 98.196 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
or (b) of this section, as applicable.
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec. 98.36 and the information listed in paragraphs (a)(1) through (8)
of this section.
(1) Method used to determine the quantity of lime that is produced
and sold.
(2) Method used to determine the quantity of calcined lime
byproduct/waste sold.
(3) Beginning and end of year inventories for each lime product
that is produced, by type.
(4) Beginning and end of year inventories for calcined lime
byproducts/wastes sold, by type.
(5) Annual amount of calcined lime byproduct/waste sold, by type
(tons).
(6) Annual amount of lime product sold, by type (tons).
(7) Annual amount of calcined lime byproduct/waste that is not
sold, by type (tons).
(8) Annual amount of lime product not sold, by type (tons).
(b) If a CEMS is not used to measure CO2 emissions, then
you must report the information listed in paragraphs (b)(1) through
(17) of this section.
(1) Annual CO2 process emissions from all kilns combined
(metric tons).
(2) Monthly emission factors for each lime type produced.
(3) Monthly emission factors for each calcined byproduct/waste by
lime type that is sold.
(4) Standard method used (ASTM or NLA testing method) to determine
chemical compositions of each lime type produced and each calcined lime
byproduct/waste type.
(5) Monthly results of chemical composition analysis of each type
of lime product produced and calcined byproduct/waste sold.
(6) Annual results of chemical composition analysis of each type of
lime byproduct/waste that is not sold.
[[Page 66466]]
(7) Method used to determine the quantity of lime produced and/or
lime sold.
(8) Monthly amount of lime product sold, by type (tons).
(9) Method used to determine the quantity of calcined lime
byproduct/waste sold.
(10) Monthly amount of calcined lime byproduct/waste sold, by type
(tons).
(11) Annual amount of calcined lime byproduct/waste that is not
sold, by type (tons).
(12) Monthly weight or mass of each lime type produced (tons).
(13) Beginning and end of year inventories for each lime product
that is produced.
(14) Beginning and end of year inventories for calcined lime
byproducts/wastes sold.
(15) Annual lime production capacity (tons) per facility.
(16) Number of times in the reporting year that missing data
procedures were followed to measure lime production (months) or the
chemical composition of lime products sold (months).
(17) Indicate whether CO2 was used on-site (i.e. for use
in a purification process). If CO2 was used on-site, provide
the information in paragraphs (b)(17)(i) and (ii) of this section.
(i) The annual amount of CO2 captured for use in the on-
site process.
(ii) The method used to determine the amount of CO2
captured.
Subpart V--[Amended]
0
38. Section 98.223 is amended by:
0
a. Revising paragraphs (a)(1) and (a)(2)(ii).
0
b. Revising paragraph (b) introductory text.
0
c. Revising paragraphs (b)(1) and (b)(2).
0
d. Revising paragraph (c).
0
e. Revising paragraph (d) introductory text.
0
f. Revising paragraph (e).
0
g. Removing and reserving paragraph (f).
0
h. Revising paragraph (g).
0
i. Adding paragraph (i).
The revisions and addition read as follows:
Sec. 98.223 Calculating GHG emissions.
(a) * * *
(1) Use a site-specific emission factor and production data
according to paragraphs (b) through (i) of this section.
(2) * * *
(ii) If the Administrator does not approve your requested
alternative method within 150 days of the end of the reporting year,
you must determine the N2O emissions for the current
reporting period using the procedures specified in paragraph (a)(1) of
this section.
(b) You must conduct an annual performance test for each nitric
acid train according to paragraphs (b)(1) through (3) of this section.
(1) You must conduct the performance test at the absorber tail gas
vent, referred to as the test point, for each nitric acid train
according to Sec. 98.224(b) through (f). If multiple nitric acid
production units exhaust to a common abatement technology and/or
emission point, you must sample each process in the ducts before the
emissions are combined, sample each process when only one process is
operating, or sample the combined emissions when multiple processes are
operating and base the site-specific emission factor on the combined
production rate of the multiple nitric acid production units.
(2) You must conduct the performance test under normal process
operating conditions.
* * * * *
(c) Using the results of the performance test in paragraph (b) of
this section, you must calculate an average site-specific emission
factor for each nitric acid train ``t'' according to Equation V-1 of
this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.025
Where:
EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ``t'' (lb N2O/ton
nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration for each test run
during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas for each test run during
the performance test (dscf/hr).
P = Production rate for each test run during the performance test
(tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.
(d) If nitric acid train ``t'' exhausts to any N2O
abatement technology ``N'' after the test point, you must determine the
destruction efficiency for each N2O abatement technology
``N'' according to paragraphs (d)(1), (d)(2), or (d)(3) of this
section.
* * * * *
(e) If nitric acid train ``t'' exhausts to any N2O
abatement technology ``N'' after the test point, you must determine the
annual amount of nitric acid produced on train ``t'' while
N2O abatement technology ``N'' is operating according to
Sec. 98.224(f). Then you must calculate the abatement utilization
factor for each N2O abatement technology ``N'' for each
nitric acid train ``t'' according to Equation V-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.026
Where:
AFt,N = Abatement utilization factor of N2O
abatement technology ``N'' at nitric acid train ``t'' (fraction of
annual production that abatement technology is operating).
Pt = Total annual nitric acid production from nitric acid
train ``t'' (ton acid produced, 100 percent acid basis).
Pa,t,N = Annual nitric acid production from nitric acid
train ``t'' during which N2O abatement technology ``N''
was operational (ton acid produced, 100 percent acid basis).
* * * * *
(g) You must calculate N2O emissions for each nitric
acid train ``t'' according to paragraph (g)(1), (g)(2), (g)(3), or
(g)(4) of this section.
(1) If nitric acid train ``t'' exhausts to one N2O
abatement technology ``N'' after the test point, you must use the
emissions factor (determined in Equation V-1 of this section), the
destruction efficiency (determined in paragraph (d) of this section),
the annual nitric acid production (determined in paragraph (i) of this
section), and the abatement utilization factor (determined in paragraph
(e) of this section) according to Equation V-3a of this section:
[[Page 66467]]
[GRAPHIC] [TIFF OMITTED] TR28OC10.027
Where:
EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3a (metric tons).
EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ''t'' (lb N2O/ton
acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from the train ``t''
(ton acid produced, 100 percent acid basis).
DF = Destruction efficiency of N2O abatement technology N
that is used on nitric acid train ``t'' (percent of N2O
removed from vent stream).
AF = Abatement utilization factor of N2O abatement
technology ``N'' for nitric acid train ``t'' (percent of time that
the abatement technology is operating).
2205 = Conversion factor (lb/metric ton).
(2) If multiple N2O abatement technologies are located
in series after your test point, you must use the emissions factor
(determined in Equation V-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
nitric acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation V-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.028
Where:
EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3b (metric tons).
EFN2O,t = N2O emissions factor for
unit ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from unit ``t'' (ton
acid produced, 100 percent acid basis).
DF1 = Destruction efficiency of N2O abatement
technology 1 (percent of N2O removed from vent stream).
AF1 = Abatement utilization factor of N2O
abatement technology 1 (percent of time that abatement technology 1
is operating).
DF2 = Destruction efficiency of N2O abatement
technology 2 (percent of N2O removed from vent stream).
AF2 = Abatement utilization factor of N2O
abatement technology 2 (percent of time that abatement technology 2
is operating).
DFN = Destruction efficiency of N2O abatement
technology N (percent of N2O removed from vent stream).
AFN = Abatement utilization factor of N2O
abatement technology N (percent of time that abatement technology N
is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.
(3) If multiple N2O abatement technologies are located
in parallel after your test point, you must use the emissions factor
(determined in Equation V-1 of this section), the destruction
efficiency (determined in paragraph (d) of this section), the annual
nitric acid production (determined in paragraph (f) of this section),
and the abatement utilization factor (determined in paragraph (e) of
this section), according to Equation V-3c of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.029
Where:
EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3c (metric tons).
EFN2O,t = N2O emissions factor for
unit ``t'' (lb N2O/ton nitric acid produced).
Pt = Annual nitric acid produced from unit ``t'' (ton
acid produced, 100 percent acid basis).
DFN = Destruction efficiency of N2O abatement
technology ``N'' (percent of N2O removed from vent
stream).
AFN = Abatement utilization factor of N2O
abatement technology ``N'' (percent of time that abatement
technology ``N'' is operating).
FCN = Fraction control factor of N2O abatement
technology ``N'' (percent of total emissions from unit ``t'' that
are sent to abatement technology ``N'').
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies with a
fraction control factor.
(4) If nitric acid train ``t'' does not exhaust to any
N2O abatement technology after the test point, you must use
the emissions factor (determined in Equation V-1 of this section), and
the annual nitric acid production (determined in paragraph (i) of this
section) according to Equation V-3b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.030
Where:
EN2Ot = Annual N2O mass emissions
from nitric acid production unit ``t'' according to this Equation V-
3d (metric tons).
EFN2Ot = Average site-specific N2O
emissions factor for nitric acid train ''t'' (lb N2O/ton
acid produced, 100 percent acid basis).
Pt = Annual nitric acid production from nitric acid train
``t'' (ton acid produced, 100 percent acid basis).
2205 = Conversion factor (lb/metric ton).
* * * * *
(i) You must determine the total annual amount of nitric acid
produced on nitric acid train ``t'' for each nitric acid train (tons
acid produced, 100 percent acid basis), according to Sec. 98.224(f).
0
39. Section 98.224 is amended by:
0
a. Revising paragraph (a).
0
b. Revising the first sentence in paragraph (d) introductory text.
0
c. Revising paragraphs (e) and (f).
The revisions read as follows:
Sec. 98.224 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test according to a test
plan as specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct the performance test annually. The test should be
conducted at a point during the campaign which is representative of the
average emissions rate from the nitric acid campaigns. Facilities must
document the methods used to determine the representative
[[Page 66468]]
point of the campaign when the performance test is conducted.
(2) Conduct the performance test when your nitric acid production
process is changed, specifically when abatement equipment is installed.
(3) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.
98.223(a)(2), you must conduct the performance test if your request has
not been approved by the Administrator within 150 days of the end of
the reporting year in which it was submitted.
* * * * *
(d) You must determine the volumetric flow rate during the
performance test in conjunction with the applicable EPA methods in 40
CFR part 60, appendices A-1 through A-4. * * *
* * * * *
(e) You must determine the total monthly amount of nitric acid
produced. You must also determine the monthly amount of nitric acid
produced while N2O abatement technology (located after the
test point) is operating from each nitric acid train. These monthly
amounts are determined according to the methods in paragraphs (c)(1) or
(2) of this section.
(f) You must determine the annual amount of nitric acid produced.
You must also determine the annual amount of nitric acid produced while
N2O abatement technology (located after the test point) is
operating for each train. These annual amounts are determined by
summing the respective monthly nitric acid quantities determined in
paragraph (e) of this section.
0
40. Section 98.226 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (g).
0
c. Revising paragraph (m) introductory text.
0
d. Revising paragraph (n) introductory text.
0
e. Adding paragraph (p).
The revisions and addition read as follows:
Sec. 98.226 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (p) of this section.
* * * * *
(g) Number of different N2O abatement technologies per
nitric acid train ``t''.
* * * * *
(m) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec. 98.223(a)(1), each annual
report must also contain the information specified in paragraphs (m)(1)
through (7) of this section.
* * * * *
(n) If you requested Administrator approval for an alternative
method of determining N2O emissions under Sec.
98.223(a)(2), each annual report must also contain the information
specified in paragraphs (n)(1) through (4) of this section.
* * * * *
(p) Fraction control factor for each abatement technology (percent
of total emissions from the production unit that are sent to the
abatement technology) if equation V-3c is used.
Subpart Z--[Amended]
0
41. Section 98.263 is amended by revising paragraph (b)(1) to read as
follows:
Sec. 98.263 Calculating GHG emissions.
* * * * *
(b) * * *
(1) Calculate the annual CO2 mass emissions from each
wet-process phosphoric acid process line using the methods in
paragraphs (b)(1)(i) or (ii) of this section, as applicable.
(i) If your process measurement provides the inorganic carbon
content of phosphate rock as an output, calculate and report the
process CO2 emissions from each wet-process phosphoric acid
process line using Equation Z-1a of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.031
Where:
Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m according to this Equation Z-
1a (metric tons).
ICn,i = Inorganic carbon content of a grab sample batch
of phosphate rock by origin i obtained during month n, from the
carbon analysis results (percent by weight, expressed as a decimal
fraction).
Pn,i = Mass of phosphate rock by origin i consumed in
month n by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin.
If the grab sample is a composite sample of rock from more than one
origin, b = 1.
2000/2205 = Conversion factor to convert tons to metric tons.
44/12 = Ratio of molecular weights, CO2 to carbon.
(ii) If your process measurement provides the CO2
emissions directly as an output, calculate and report the process
CO2 emissions from each wet-process phosphoric acid process
line using Equation Z-1b of this section:
[GRAPHIC] [TIFF OMITTED] TR28OC10.032
Where:
Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m according to this Equation Z-
1b (metric tons).
CO2n,i = Carbon dioxide emissions of a grab sample batch
of phosphate rock by origin i obtained during month n (percent by
weight, expressed as a decimal fraction).
Pn,i = Mass of phosphate rock by origin i consumed in
month n by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin.
If the grab sample is a composite sample of rock from more than one
origin, b=1.
2000/2205 = Conversion factor to convert tons to metric tons.
* * * * *
0
42. Section 98.264 is amended by revising paragraphs (a) and (b) to
read as follows:
[[Page 66469]]
Sec. 98.264 Monitoring and QA/QC requirements.
(a) You must obtain a monthly grab sample of phosphate rock
directly from the rock being fed to the process line before it enters
the mill using one of the following methods. You may conduct the
representative bulk sampling using a method published by a consensus
standards organization, or you may use industry consensus standard
practice methods, including but not limited to the Phosphate Mining
States Methods Used and Adopted by the Association of Fertilizer and
Phosphate Chemists (AFPC) (P.O. Box 1645, Bartow, Florida 33831, (863)
534-9755, http://afpc.net, [email protected]). If phosphate rock
is obtained from more than one origin in a month, you must obtain a
sample from each origin of rock or obtain a composite representative
sample.
(b) You must determine the carbon dioxide or inorganic carbon
content of each monthly grab sample of phosphate rock (consumed in the
production of phosphoric acid). You may use a method published by a
consensus standards organization, or you may use industry consensus
standard practice methods, including but not limited to the Phosphate
Mining States Methods Used and Adopted by AFPC (P.O. Box 1645, Bartow,
Florida 33831, (863) 534-9755, http://afpc.net,
[email protected]).
* * * * *
0
43. Section 98.265 is amended by revising the first and second
sentences of paragraph (a) to read as follows:
Sec. 98.265 Procedures for estimating missing data.
* * * * *
(a) For each missing value of the inorganic carbon content of
phosphate rock or carbon dioxide (by origin), you must use the
appropriate default factor provided in Table Z-1 this subpart.
Alternatively, you must determine a substitute data value by
calculating the arithmetic average of the quality-assured values of
inorganic carbon contents of phosphate rock of origin i from samples
immediately preceding and immediately following the missing data
incident. * * *
* * * * *
0
44. Section 98.266 is amended by:
0
a. Revising the introductory text.
0
b. Revising paragraph (c).
0
c. Revising paragraph (f) introductory text.
0
d. Revising paragraph (f)(2).
0
e. Revising paragraph (f)(4).
0
f. Revising paragraph (f)(5).
0
g. Adding paragraph (f)(9).
The revisions and addition read as follows:
Sec. 98.266 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (f) of this section.
* * * * *
(c) Annual arithmetic average percent inorganic carbon or carbon
dioxide in phosphate rock from monthly records (percent by weight,
expressed as a decimal fraction).
* * * * *
(f) If you do not use a CEMS to measure emissions, then you must
report the information in paragraphs (f)(1) through (9) of this
section.
* * * * *
(2) Annual CO2 emissions from each wet-process
phosphoric acid process line (metric tons) as calculated by either
Equation Z-1a or Equation Z-1b of this subpart.
* * * * *
(4) Method used to estimate any missing values of inorganic carbon
content or carbon dioxide content of phosphate rock for each wet-
process phosphoric acid process line.
(5) Monthly inorganic carbon content of phosphate rock for each
wet-process phosphoric acid process line for which Equation Z-1a is
used (percent by weight, expressed as a decimal fraction), or
CO2 (percent by weight, expressed as a decimal fraction) for
which Equation Z-1b is used.
* * * * *
(9) Annual process CO2 emissions from phosphoric acid
production facility (metric tons).
Subpart CC--[Amended]
0
45. Section 98.294 is amended by revising the third sentence of
paragraph (a)(1) to read as follows:
Sec. 98.294 Monitoring and QA/QC requirements.
* * * * *
(a) * * *
(1) * * * The modified method referred to above adjusts the regular
ASTM method to express the results in terms of trona.* * *
* * * * *
0
46. Section 98.296 is amended by:
0
a. Revising paragraph (a)(1).
0
b. Revising paragraph (b)(3).
0
c. Revising paragraph (b)(6).
0
d. Revising paragraph (b)(10).
0
e. Removing paragraphs (b)(11)(iv) through (vi).
The revisions read as follows:
Sec. 98.296 Data reporting requirements.
* * * * *
(a) * * *
(1) Annual consumption of trona or liquid alkaline feedstock for
each manufacturing line (tons).
* * * * *
(b) * * *
(3) Annual production of soda ash for each manufacturing line
(tons).
* * * * *
(6) Monthly production of soda ash for each manufacturing line
(tons).
* * * * *
(10) If you produce soda ash using the liquid alkaline feedstock
process and use the site-specific emission factor method (Sec.
98.293(b)(3)) to estimate emissions then you must report the following
relevant information for each manufacturing line or stack:
(i) Stack gas volumetric flow rate during performance test (dscfm).
(ii) Hourly CO2 concentration during performance test
(percent CO2).
(iii) CO2 emission factor (metric tons CO2/
metric tons of process vent flow from mine water stripper/evaporator).
(iv) CO2 mass emission rate during performance test
(metric tons/hour).
* * * * *
Subpart EE--[Amended]
0
47. Section 98.314 is amended by revising paragraph (e) to read as
follows:
Sec. 98.314 Monitoring and QA/QC requirements.
* * * * *
(e) You must determine the quantity of carbon-containing waste
generated from each titanium dioxide production line on a monthly basis
using plant instruments used for accounting purposes including direct
measurement weighing the carbon-containing waste not used during the
process (by belt scales or a similar device) or through the use of
sales records.
* * * * *
0
48. Section 98.316 is amended by revising paragraphs (b)(9) and (b)(11)
to read as follows:
Sec. 98.316 Data reporting requirements.
* * * * *
(b) * * *
(9) Monthly carbon content factor of petroleum coke (percent by
weight expressed as a decimal fraction).
* * * * *
(11) Carbon content for carbon-containing waste for each process
line (percent by weight expressed as a decimal fraction).
* * * * *
[[Page 66470]]
Subpart GG--[Amended]
0
49. Section 98.333 is amended by revising the definitions of
``(Electrode)k'' and ``(CElectrode)k''
in Equation GG-1 of paragraph (b)(1) to read as follows:
Sec. 98.333 Calculating GHG emissions.
* * * * *
(b) * * *
(1) * * * * *
(Electrode)k = Annual mass of carbon electrode consumed
in furnace ``k'' (tons).
(CElectrode)k = Carbon content of the carbon
electrode consumed in furnace ``k'', from the annual carbon analysis
(percent by weight, expressed as a decimal fraction).
* * * * *
0
50. Section 98.336 is amended by revising paragraph (a) introductory
text; and by revising paragraphs (b)(1), (b)(7), and (b)(10) to read as
follows:
Sec. 98.336 Data reporting requirements.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required for
the Tier 4 Calculation Methodology in Sec. 98.36 and the information
listed in this paragraph (a):
* * * * *
(b) * * *
(1) Identification number and annual process CO2
emissions from each individual Waelz kiln or electrothermic furnace
(metric tons).
* * * * *
(7) Carbon content of each carbon-containing input material charged
to each kiln or furnace (including zinc bearing material, flux
materials, and other carbonaceous materials) from the annual carbon
analysis or from information provided by the material supplier for each
kiln or furnace (percent by weight, expressed as a decimal fraction).
* * * * *
(10) Carbon content of the carbon electrode used in each furnace
from the annual carbon analysis or from information provided by the
material supplier (percent by weight, expressed as a decimal fraction).
* * * * *
Subpart HH--[Amended]
0
51. Section 98.340 is amended by revising paragraph (b) to read as
follows:
Sec. 98.340 Definition of the source category.
* * * * *
(b) This source category does not include Resource Conservation and
Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA)
hazardous waste landfills, construction and demolition waste landfills,
or industrial waste landfills.
* * * * *
0
52. Section 98.343 is amended by:
0
a. In paragraph (a)(1), revising Equation HH-1 and the definitions of
``x,'' ``S,'' ``Wx,'' ``MCF,'' ``DOCF,'' ``F,''
and ``k'' in Equation HH-1; and removing the definition of
``L0'' in Equation HH-1.
0
b. Revising the last sentence of paragraph (a)(2).
0
c. Redesignating paragraph (a)(3) as (a)(4) and revising new paragraph
(a)(4).
0
d. Adding a new paragraph (a)(3).
0
e. Revising paragraph (b)(1), and revising paragraph (b)(2)
introductory text.
0
f. Revising paragraphs (b)(2)(ii), (b)(2)(iii)(A), and (b)(2)(iii)(B).
0
g. Revising paragraph (c) introductory text.
The revisions and additions read as follows:
Sec. 98.343 Calculating GHG emissions.
(a) * * *
(1) * * *
[GRAPHIC] [TIFF OMITTED] TR28OC10.033
* * * * *
x = Year in which waste was disposed.
S = Start year of calculation. Use the year 1960 or the opening year
of the landfill, whichever is more recent.
* * * * *
Wx = Quantity of waste disposed in the landfill in year x
from measurement data, tipping fee receipts, or other company
records (metric tons, as received (wet weight)).
MCF = Methane correction factor (fraction). Use the default value of
1 unless there is active aeration of waste within the landfill
during the reporting year. If there is active aeration of waste
within the landfill during the reporting year, use either the
default value of 1 or select an alternative value no less than 0.5
based on site-specific aeration parameters.
* * * * *
DOCF = Fraction of DOC dissimilated (fraction). Use the
default value of 0.5.
F = Fraction by volume of CH4 in landfill gas from
measurement data on a dry basis, if available (fraction); default is
0.5.
k = Rate constant from Table HH-1 to this subpart
(yr-\1\). Select the most applicable k value for the
majority of the past 10 years (or operating life, whichever is
shorter).
(2) * * * For years when waste composition data are not available,
use the bulk waste parameter values for k and DOC in Table HH-1 to this
subpart for the total quantity of waste disposed in those years.
(3) Beginning in the first emissions reporting year and for each
year thereafter, if scales are in place, you must determine the annual
quantity of waste (in metric tons as received, i.e., wet weight)
disposed of in the landfill using paragraph (a)(3)(i) of this section
for all containers and for all vehicles used to haul waste to the
landfill, except for passenger cars, light duty pickup trucks, or waste
loads that cannot be measured using the scales due to physical
limitations (load cannot physically access or fit on the scale) and/or
operational limitations of the scale (load exceeding the limits or
sensitivity range of the scale). If scales are not in place, you must
use paragraph (a)(3)(ii) of this section to determine the annual
quantity of waste disposed. For waste hauled to the landfill in
passenger cars or light duty pickup trucks, you may use either
paragraph (a)(3)(i) or paragraph (a)(3)(ii) of this section to
determine the annual quantity of waste disposed. For loads that cannot
be measured using the scales due to physical and/or operational
limitations of the scale, you must use paragraph (a)(3)(ii) of this
section or similar engineering calculations to determine the annual
quantity of waste disposed. The approach used to determine the annual
quantity of waste disposed of must be documented in the monitoring
plan.
(i) Use direct mass measurements of each individual load received
at the landfill using either of the following methods:
(A) Weigh using mass scales each vehicle or container used to haul
waste as it enters the landfill or disposal area; weigh using mass
scales each vehicle or container after it has off-loaded the waste;
determine the quantity of waste received from the individual load as
the difference in the two mass measurements; and determine the annual
quantity of waste received as the sum of all waste loads received
during the year. Alternatively, you may
[[Page 66471]]
determine annual quantity of waste by summing the weights of all
vehicles and containers entering the landfill and subtracting from it
the sum of all the weights of vehicles and containers after they have
off-loaded the waste in the landfill.
(B) Weigh using mass scales each vehicle or container used to haul
waste as it enters the landfill or disposal area; determine a
representative tare weight by vehicle or container type by weighing no
less than 5 of each type of vehicle or container after it has off-
loaded the waste; determine the quantity of waste received from the
individual load as the difference between the measured weight in and
the tare weight determined for that container/vehicle type; and
determine the annual quantity of waste received as the sum of all waste
loads received during the year.
(ii) Determine the working capacity in units of mass for each type
of container or vehicle used to haul waste to the landfill (e.g., using
volumetric capacity and waste density measurements; direct measurement
of a selected number of passenger vehicles and light duty pick-up
trucks; or similar methods); record the number of loads received at the
landfill by vehicle/container type; calculate the annual mass per
vehicle/container type as the mass product of the number of loads of
that vehicle/container multiplied by its working capacity; and
calculate the annual quantity of waste received as the sum of the
annual mass per vehicle/container type across all of the vehicle/
container types used to haul waste to the landfill.
(4) For years prior to the first emissions reporting year, use
methods in paragraph (a)(3) of this section when waste disposal
quantity data are readily available. When waste disposal quantity data
are not readily available, Wx shall be estimated using one
of the applicable methods in paragraphs (a)(4)(i) through (a)(4)(iii)
of this section. You must determine which method is most applicable to
the conditions and disposal history of your facility. Historical waste
disposal quantities should only be determined once, as part of the
first annual report, and the same values should be used for all
subsequent annual reports, supplemented by the next year's data on new
waste disposal.
(i) Assume all prior years waste disposal quantities are the same
as the waste quantity in the first year for which waste quantities are
available.
(ii) Use the estimated population served by the landfill in each
year, the values for national average per capita waste disposal rates
found in Table HH-2 to this subpart, and calculate the waste quantity
landfilled using Equation HH-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.034
Where:
Wx = Quantity of waste placed in the landfill in year x
(metric tons, wet basis).
POPx = Population served by the landfill in year x from
city population, census data, or other estimates (capita).
WDRx = Average per capita waste disposal rate for year x
from Table HH-2 to this subpart (metric tons per capita per year,
wet basis; tons/cap/yr).
(iii) Use a constant average waste disposal quantity calculated
using Equation HH-3 of this section for each year the landfill was in
operation (i.e., from the first year accepting waste until the last
year for which waste disposal data is unavailable, inclusive).
[GRAPHIC] [TIFF OMITTED] TR28OC10.035
Where:
Wx = Quantity of waste placed in the landfill in year x
(metric tons, wet basis).
LFC = Landfill capacity or, for operating landfills, capacity of the
landfill used (or the total quantity of waste-in-place) at the end
of the year prior to the year when waste disposal data are available
from design drawings or engineering estimates (metric tons).
YrData = Year in which the landfill last received waste or, for
operating landfills, the year prior to the first reporting year when
waste disposal data is first available from company records, or best
available data.
YrOpen = Year in which the landfill first received waste from
company records or best available data. If no data are available for
estimating YrOpen for a closed landfill, use 30 years as the default
operating life of the landfill.
(b) * * *
(1) If you continuously monitor the flow rate, CH4
concentration, temperature, pressure, and, if necessary, moisture
content of the landfill gas that is collected and routed to a
destruction device (before any treatment equipment) using a monitoring
meter specifically for CH4 gas, as specified in Sec.
98.344, you must use this monitoring system and calculate the quantity
of CH4 recovered for destruction using Equation HH-4 of this
section. A fully integrated system that directly reports CH4
content requires no other calculation than summing the results of all
monitoring periods for a given year.
[GRAPHIC] [TIFF OMITTED] TR28OC10.036
Where:
R = Annual quantity of recovered CH4 (metric tons
CH4).
N = Total number of measurement periods in a year. Use daily
averaging periods for a continuous monitoring system and N = 365 (or
N = 366 for leap years). For weekly sampling, as provided in
paragraph (b)(2) of this section, use N=52.
n = Index for measurement period.
(V)n = Cumulative volumetric flow for the measurement
period in actual cubic feet (acf). If the flow rate meter
automatically corrects for temperature and pressure, replace
``520[deg]R/(T)n x (P)n/1 atm'' with ``1''.
(KMC)n = Moisture correction term for the
measurement period, volumetric basis, as follows:
(KMC)n = 1 when (V)n and
(C)n are both measured on a dry basis or if both are
measured on a wet basis; (KMC)n = [1-
(fH2O)n] when (V)n is
measured on a wet basis and (C)n is measured on a dry
basis; and (KMC)n = 1/[1-
(fH2O)n] when (V)n is measured on a
dry basis and (C)n is measured on a wet basis.
(fH2O)n = Average moisture content
of landfill gas during the measurement period, volumetric basis
(cubic feet water per cubic feet landfill gas)
(CCH4)n = Average CH4 concentration
of landfill gas for the measurement period (volume %).
0.0423 = Density of CH4 lb/cfm at 520[deg]R or 60 degrees
Fahrenheit and 1 atm.
(T)n = Average temperature at which flow is measured for
the measurement period ([deg]R).
(P)n = Average pressure at which flow is measured for the
measurement period (atm).
0.454/1,000 = Conversion factor (metric ton/lb).
(2) If you do not continuously monitor according to paragraph
(b)(1) of this section, you must determine the flow rate,
CH4 concentration, temperature, pressure, and moisture
content of the landfill gas that is collected and routed to a
destruction device (before any treatment equipment) according to the
requirements in paragraphs (b)(2)(i) through (b)(2)(iii) of this
section and
[[Page 66472]]
calculate the quantity of CH4 recovered for destruction
using Equation HH-4 of this section.
* * * * *
(ii) Determine the CH4 concentration in the landfill gas
that is collected and routed to a destruction device (before any
treatment equipment) in a location near or representative of the
location of the gas flow meter at least once each calendar week; if
only one measurement is made each calendar week, there must be at least
three days between measurements.
(iii) * * *
(A) Determine the temperature and pressure in the landfill gas that
is collected and routed to a destruction device (before any treatment
equipment) in a location near or representative of the location of the
gas flow meter at least once each calendar week; if only one
measurement is made each calendar week, there must be at least three
days between measurements.
(B) If the CH4 concentration is determined on a dry
basis and flow is determined on a wet basis or CH4
concentration is determined on a wet basis and flow is determined on a
dry basis, and the flow meter does not automatically correct for
moisture content, determine the moisture content in the landfill gas
that is collected and routed to a destruction device (before any
treatment equipment) in a location near or representative of the
location of the gas flow meter at least once each calendar week; if
only one measurement is made each calendar week, there must be at least
three days between measurements.
(c) For all landfills, calculate CH4 generation
(adjusted for oxidation in cover materials) and actual CH4
emissions (taking into account any CH4 recovery, and
oxidation in cover materials) according to the applicable methods in
paragraphs (c)(1) through (c)(3) of this section.
* * * * *
0
53. Section 98.344 is amended by:
0
a. Revising paragraph (a).
0
b. Revising the first sentence of paragraph (b) introductory text.
0
c. Revising paragraphs (b)(6)(ii) introductory text, (b)(6)(ii)(A), and
(b)(6)(ii)(B).
0
d. Revising the definition of ``CCH4'' in Equation HH-9 of
paragraph (b)(6)(iii).
0
e. Revising the second and third sentences of paragraph (c)
introductory text.
0
f. Revising paragraph (d).
0
g. Revising the first sentence of paragraph (e).
The revisions read as follows:
Sec. 98.344 Monitoring and QA/QC requirements.
(a) Mass measurement equipment used to determine the quantity of
waste landfilled on or after January 1, 2010 must meet the requirements
for weighing equipment as described in ``Specifications, Tolerances,
and Other Technical Requirements For Weighing and Measuring Devices''
NIST Handbook 44 (2009) (incorporated by reference, see Sec. 98.7).
(b) For landfills with gas collection systems, operate, maintain,
and calibrate a gas composition monitor capable of measuring the
concentration of CH4 in the recovered landfill gas using one
of the methods specified in paragraphs (b)(1) through (b)(6) of this
section or as specified by the manufacturer. * * *
* * * * *
(6) * * *
(ii) Determine a non-methane organic carbon correction factor at
the routine sampling location no less frequently than once a reporting
year following the requirements in paragraphs (b)(6)(ii)(A) through
(b)(6)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the landfill gas with a
minimum of 20 minutes between samples and determine the methane
composition of the landfill gas using one of the methods specified in
paragraphs (b)(1) through (b)(5) of this section.
(B) As soon as practical after each grab sample is collected and
prior to the collection of a subsequent grab sample, determine the
total gaseous organic concentration of the landfill gas using either
Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in
paragraph (b)(6)(i) of this section.
* * * * *
(iii) * * *
CCH4 = Methane concentration in the landfill gas (volume
%) for use in Equation HH-4 of this subpart.
* * * * *
(c) * * * Each gas flow meter shall be recalibrated either
biennially (every 2 years) or at the minimum frequency specified by the
manufacturer. Except as provided in Sec. 98.343(b)(2)(i), each gas
flow meter must be capable of correcting for the temperature and
pressure and, if necessary, moisture content.
* * * * *
(d) All temperature, pressure, and if necessary, moisture content
monitors must be calibrated using the procedures and frequencies
specified by the manufacturer.
(e) The owner or operator shall document the procedures used to
ensure the accuracy of the estimates of disposal quantities and, if
applicable, gas flow rate, gas composition, temperature, pressure, and
moisture content measurements. * * *
0
54. Section 98.346 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b).
0
c. Revising paragraph (c).
0
d. Revising paragraph (d)(1).
0
e. Revising paragraph (f).
0
f. Revising paragraph (h).
0
g. Revising paragraph (i)(1)
0
h. Revising paragraph (i)(2)
0
i. Revising paragraph (i)(3)
0
j. Revising paragraph (i)(4)
0
k. Revising paragraph (i)(5)
0
l. Revising paragraph (i)(7).
The revisions read as follows:
Sec. 98.346 Data reporting requirements.
* * * * *
(a) A classification of the landfill as ``open'' (actively received
waste in the reporting year) or ``closed'' (no longer receiving waste),
the year in which the landfill first started accepting waste for
disposal, the last year the landfill accepted waste (for open
landfills, enter the estimated year of landfill closure), the capacity
(in metric tons) of the landfill, an indication of whether leachate
recirculation is used during the reporting year and its typical
frequency of use over the past 10 years (e.g., used several times a
year for the past 10 years, used at least once a year for the past 10
years, used occasionally but not every year over the past 10 years, not
used), an indication as to whether scales are present at the landfill,
and the waste disposal quantity for each year of landfilling required
to be included when using Equation HH-1 of this subpart (in metric
tons, wet weight).
(b) Method for estimating reporting year and historical waste
disposal quantities, reason for its selection, and the range of years
it is applied. For years when waste quantity data are determined using
the methods in Sec. 98.343(a)(3), report separately the quantity of
waste determined using the methods in Sec. 98.343(a)(3)(i) and the
quantity of waste determined using the methods in Sec.
98.343(a)(3)(ii). For historical waste disposal quantities that were
not determined using the methods in Sec. 98.343(a)(3), provide the
population served by the landfill for each year the Equation HH-2 of
this subpart is applied, if applicable, or, for open landfills using
Equation HH-3 of this subpart, provide the value of landfill capacity
(LFC) used in the calculation.
(c) Waste composition for each year required for Equation HH-1 of
this subpart, in percentage by weight, for each waste category listed
in Table HH-1 to this subpart that is used in Equation
[[Page 66473]]
HH-1 of this subpart to calculate the annual modeled CH4
generation.
(d) * * *
(1) Degradable organic carbon (DOC), methane correction factor
(MCF), and fraction of DOC dissimilated (DOCF) values used
in the calculations. If an MCF value other than the default of 1 is
used, provide an indication of whether active aeration of the waste in
the landfill was conducted during the reporting year, a description of
the aeration system, including aeration blower capacity, the fraction
of the landfill containing waste affected by the aeration, the total
number of hours during the year the aeration blower was operated, and
other factors used as a basis for the selected MCF value.
* * * * *
(f) The surface area of the landfill containing waste (in square
meters), identification of the type of cover material used (as either
organic cover, clay cover, sand cover, or other soil mixtures). If
multiple cover types are used, the surface area associated with each
cover type.
* * * * *
(h) For landfills without gas collection systems, the annual
methane emissions (i.e., the methane generation, adjusted for
oxidation, calculated using Equation HH-5 of this subpart), reported in
metric tons CH4, and an indication of whether passive vents
and/or passive flares (vents or flares that are not considered part of
the gas collection system as defined in Sec. 98.6) are present at this
landfill.
(i) * * *
(1) Total volumetric flow of landfill gas collected for destruction
for the reporting year (cubic feet at 520 [deg]R or 60 degrees
Fahrenheit and 1 atm).
(2) Annual average CH4 concentration of landfill gas
collected for destruction (percent by volume).
(3) Monthly average temperature and pressure for each month at
which flow is measured for landfill gas collected for destruction, or
statement that temperature and/or pressure is incorporated into
internal calculations run by the monitoring equipment.
(4) An indication as to whether flow was measured on a wet or dry
basis, an indication as to whether CH4 concentration was
measured on a wet or dry basis, and if required for Equation HH-4 of
this subpart, monthly average moisture content for each month at which
flow is measured for landfill gas collected for destruction.
(5) An indication of whether destruction occurs at the landfill
facility or off-site. If destruction occurs at the landfill facility,
also report an indication of whether a back-up destruction device is
present at the landfill, the annual operating hours for the primary
destruction device, the annual operating hours for the back-up
destruction device (if present), and the destruction efficiency used
(percent).
* * * * *
(7) A description of the gas collection system (manufacturer,
capacity, and number of wells), the surface area (square meters) and
estimated waste depth (meters) for each area specified in Table HH-3 to
this subpart, the estimated gas collection system efficiency for
landfills with this gas collection system, the annual operating hours
of the gas collection system, and an indication of whether passive
vents and/or passive flares (vents or flares that are not considered
part of the gas collection system as defined in Sec. 98.6) are present
at the landfill.
* * * * *
0
55. Section 98.347 is amended by adding a second sentence to read as
follows:
Sec. 98.347 Records that must be retained.
* * * You must retain records of all measurements made to determine
tare weights and working capacities by vehicle/container type if these
are used to determine the annual waste quantities.
0
56. Section 98.348 is revised to read as follows:
Sec. 98.348 Definitions.
Except as specified in this section, all terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part.
Construction and demolition (C&D) waste landfill means a solid
waste disposal facility subject to the requirements of part 257,
subparts A or B of this chapter that receives construction and
demolition waste and does not receive hazardous waste (defined in Sec.
261.3 of this chapter) or industrial solid waste (defined in Sec.
258.2 of this chapter) or municipal solid waste (as defined in Sec.
98.6) other than residential lead-based paint waste. A C&D waste
landfill typically receives any one or more of the following types of
solid wastes: Roadwork material, excavated material, demolition waste,
construction/renovation waste, and site clearance waste.
Destruction device means a flare, thermal oxidizer, boiler,
turbine, internal combustion engine, or any other combustion unit used
to destroy or oxidize methane contained in landfill gas.
Industrial waste landfill means any landfill other than a municipal
solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a
TSCA hazardous waste landfill, in which industrial solid waste, such a
RCRA Subtitle D wastes (nonhazardous industrial solid waste, defined in
Sec. 257.2 of this chapter), commercial solid wastes, or conditionally
exempt small quantity generator wastes, is placed. An industrial waste
landfill includes all disposal areas at the facility.
Solid waste has the meaning established by the Administrator
pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
Working capacity means the maximum volume or mass of waste that is
actually placed in the landfill from an individual or representative
type of container (such as a tank, truck, or roll-off bin) used to
convey wastes to the landfill, taking into account that the container
may not be able to be 100 percent filled and/or 100 percent emptied for
each load.
0
57. Table HH-1 to subpart HH is revised to read as follows:
Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation Factors and Methods
----------------------------------------------------------------------------------------------------------------
Factor Default value Units
----------------------------------------------------------------------------------------------------------------
DOC and k values--Bulk waste option
----------------------------------------------------------------------------------------------------------------
DOC (bulk waste)................. 0.20..................... Weight fraction, wet basis.
k (precipitation plus 0.02..................... yr -1
recirculated leachate \a\ <20
inches/year).
k (precipitation plus 0.038.................... yr -1
recirculated leachate \a\ 20-40
inches/year).
k (precipitation plus 0.057.................... yr -1
recirculated leachate \a\ >40
inches/year).
----------------------------------------------------------------------------------------------------------------
[[Page 66474]]
DOC and k values--Modified bulk MSW option
----------------------------------------------------------------------------------------------------------------
DOC (bulk MSW, excluding inerts 0.31..................... Weight fraction, wet basis.
and C&D waste).
DOC (inerts, e.g., glass, 0.00..................... Weight fraction, wet basis.
plastics, metal, concrete).
DOC (C&D waste).................. 0.08..................... Weight fraction, wet basis.
k (bulk MSW, excluding inerts and 0.02 to 0.057 \b\........ yr -1
C&D waste).
k (inerts, e.g., glass, plastics, 0.00..................... yr -1
metal, concrete).
k (C&D waste).................... 0.02 to 0.04 \b\......... yr -1
----------------------------------------------------------------------------------------------------------------
DOC and k values--Waste composition option
----------------------------------------------------------------------------------------------------------------
DOC (food waste)................. 0.15..................... Weight fraction, wet basis.
DOC (garden)..................... 0.2...................... Weight fraction, wet basis.
DOC (paper)...................... 0.4...................... Weight fraction, wet basis.
DOC (wood and straw)............. 0.43..................... Weight fraction, wet basis.
DOC (textiles)................... 0.24..................... Weight fraction, wet basis.
DOC (diapers).................... 0.24..................... Weight fraction, wet basis.
DOC (sewage sludge).............. 0.05..................... Weight fraction, wet basis.
DOC (inerts, e.g., glass, 0.00..................... Weight fraction, wet basis.
plastics, metal, cement).
k (food waste)................... 0.06 to 0.185 \c\........ yr -1
k (garden)....................... 0.05 to 0.10 \c\......... yr -1
k (paper)........................ 0.04 to 0.06 \c\......... yr -1
k (wood and straw)............... 0.02 to 0.03 \c\......... yr -1
k (textiles)..................... 0.04 to 0.06 \c\......... yr -1
k (diapers)...................... 0.05 to 0.10 \c\......... yr -1
k (sewage sludge)................ 0.06 to 0.185 \c\........ yr -1
k (inerts e.g., glass, plastics, 0.00..................... yr -1
metal, concrete).
----------------------------------------------------------------------------------------------------------------
Other parameters--All MSW landfills
----------------------------------------------------------------------------------------------------------------
MCF.............................. 1. ..................................................
DOCF............................. 0.5......................
F................................ 0.5......................
OX............................... 0.1......................
DE............................... 0.99 ....................
----------------------------------------------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or
engineering estimates divided by the area of the portion of the landfill containing waste with appropriate
unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of
0.057 rather than calculating the recirculated leachate rate.
\b\ Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the
greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of
the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive).
Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than
calculating the recirculated leachate rate.
\c\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate
plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed
the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate
recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate
or recirculated leachate rate.
0
58. Table HH-2 to subpart HH is amended by:
0
a. Removing the third column ``% to SWDS.''
0
b. Removing the entries for ``1950'' through ``1959.''
0
c. Revising the entries for ``1989'' through ``2006.''
0
d. Adding entries for ``2007'' through ``2009.''
Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal
Rates
------------------------------------------------------------------------
Waste per
Year capita ton/
cap/yr
------------------------------------------------------------------------
* * * *
1989....................................................... 0.83
1990....................................................... 0.82
1991....................................................... 0.76
1992....................................................... 0.74
1993....................................................... 0.76
1994....................................................... 0.75
1995....................................................... 0.70
1996....................................................... 0.68
1997....................................................... 0.69
1998....................................................... 0.75
1999....................................................... 0.75
2000....................................................... 0.80
2001....................................................... 0.91
2002....................................................... 1.02
2003....................................................... 1.02
2004....................................................... 1.01
2005....................................................... 0.98
2006....................................................... 0.95
2007....................................................... 0.95
2008....................................................... 0.95
2009....................................................... 0.95
------------------------------------------------------------------------
0
59. Table HH-3 to subpart HH-3 is amended by revising the entries for
``A2: Area without active gas collection, regardless of cover type H2:
Average depth of waste in area A2,'' ``A3: Area with daily soil cover
and active gas collection H3: Average depth of waste in area A3,''
``A4: Area with an intermediate soil cover and active gas
[[Page 66475]]
collection H4: Average depth of waste in area A4,'' and ``A5: Area with
a final soil and geomembrane cover system and active gas collection H5:
Average depth of waste in area A5'' to read as follows:
Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection
Efficiencies
------------------------------------------------------------------------
Landfill gas collection
Description efficiency
------------------------------------------------------------------------
* * * * * * *
A2: Area without active gas collection, CE2: 0%.
regardless of cover type.
A3: Area with daily soil cover and active gas CE3: 60%.
collection.
A4: Area with an intermediate soil cover, or CE4: 75%.
a final soil cover not meeting the criteria
for A5 below, and active gas collection.
A5: Area with a final soil cover of 3 feet or CE5: 95%.
thicker of clay and/or geomembrane cover
system and active gas collection.
* * * * * * *
------------------------------------------------------------------------
Subpart LL--[Amended]
0
60. Section 98.386 is amended by:
0
a. Revising paragraph (a)(3).
0
b. Adding a third sentence to the end of paragraph (a)(5).
0
c. Adding a third sentence to the end of paragraph (a)(6).
0
d. Revising paragraph (a)(7).
0
e. Revising paragraphs (a)(16) and (a)(17).
0
f. Revising paragraphs (b)(3) and (c)(3).
0
g. Adding paragraph (d).
The revisions and additions read as follows:
Sec. 98.386 Data reporting requirements.
* * * * *
(a) * * *
(3) For each feedstock reported in paragraph (a)(2) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (a)(2) of this section that is fossil fuel-based (excluding
any denaturant that may be present in any ethanol product).
* * * * *
(5) * * * Those products that enter the facility, but are not
reported in (a)(1), shall not be reported under this paragraph.
(6) * * * Those products that enter the facility, but are not
reported in (a)(2), shall not be reported under this paragraph.
(7) For each product reported in paragraph (a)(6) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (a)(6) of this section that is fossil fuel-based (excluding
any denaturant that may be present in any ethanol product).
* * * * *
(16) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each feedstock reported in
paragraph (a)(2) of this section that were calculated according to
Sec. 98.393(b) or (h).
(17) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each product (leaving the
coal-to-liquid facility) reported in paragraph (a)(6) of this section
that were calculated according to Sec. 98.393(a) or (h).
* * * * *
(b) * * *
(3) For each product reported in paragraph (b)(2) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (b)(2) of this section that is fossil fuel-based (excluding
any denaturant that may be present in any ethanol product).
* * * * *
(c) * * *
(3) For each product reported in paragraph (c)(2) of this section
that was produced by blending a fossil fuel-based product with a
biomass-based product, report the percent of the volume reported in
paragraph (c)(2) of this section that is fossil fuel-based (excluding
any denaturant that may be present in any ethanol product).
* * * * *
(d) Blended feedstock and products. (1) Producers, exporters, and
importers must report the following information for each blended
product and feedstock where emissions were calculated according to
Sec. 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each blended feedstock or
product, using Equation MM-12 or Equation MM-13 of Sec. 98.393.
(iii) Whether it is a blended feedstock or a blended product.
(2) For a product that enters the facility to be further refined or
otherwise used on site that is a blended feedstock, producers must meet
the reporting requirements of paragraphs (a)(1) and (a)(2) of this
section by reflecting the individual components of the blended
feedstock.
(3) For a product that is produced, imported, or exported that is a
blended product, producers, importers, and exporters must meet the
reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2),
(c)(1), and (c)(2) of this section, as applicable, by reflecting the
individual components of the blended product.
Subpart MM--[Amended]
0
61. Section 98.393 is amended by:
0
a. In paragraph (a)(1), revising the only sentence and the definition
of ``Producti'' in Equation MM-1.
0
b. Revising the definition of ``Producti'' in Equation MM-2
of paragraph (a)(2).
0
c. Revising the only sentence of paragraph (b)(1) and the first
sentence in paragraph (f)(1).
0
d. Revising the definition of ``%Voli'' in Equation MM-8 in
paragraph (h)(1).
0
e. Revising Equation MM-9 and the definition of ``%Volj'' in
paragraph (h)(2).
0
f. Revising paragraphs (h)(3) and (h)(4).
0
g. Adding paragraph (i).
The revisions and additions read as follows:
Sec. 98.393 Calculating GHG emissions.
(a) * * *
(1) Except as provided in paragraphs (h) and (i) of this section,
any refiner, importer, or exporter shall calculate CO2
emissions from each individual petroleum product and natural gas liquid
using Equation MM-1 of this section.
* * * * *
Producti = Annual volume of product ``i'' produced,
imported, or exported by the reporting party (barrels). For
refiners, this volume only includes products ex
[[Page 66476]]
refinery gate, and excludes products that entered the refinery but
are not reported under Sec. 98.396(a)(1). For natural gas liquids,
volumes shall reflect the individual components of the product as
listed in Table MM-1 to subpart MM.
* * * * *
(2) * * *
Producti = Annual mass of product ``i'' produced,
imported, or exported by the reporting party (metric tons). For
refiners, this mass only includes products ex refinery gate, and
excludes products that entered the refinery but are not reported
under Sec. 98.396(a)(1).
* * * * *
(b) * * *
(1) Except as provided in paragraphs (h) and (i) of this section,
any refiner shall calculate CO2 emissions from each non-
crude feedstock using Equation MM-2 of this section.
* * * * *
(f) * * *
(1) Calculation Method 1. To determine the emission factor (i.e.,
EFi in Equation MM-1) for solid products, multiply the
default carbon share factor (i.e., percent carbon by mass) in column B
of Table MM-1 to this subpart for the appropriate product by 44/12. * *
*
* * * * *
(h) * * *
(1) * * *
%Voli = Percent volume of product ``i'' that is
petroleum-based, not including any denaturant that may be present in
any ethanol product, expressed as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).
(2) * * *
[GRAPHIC] [TIFF OMITTED] TR28OC10.037
* * * * *
%Volj = Percent volume of feedstock ``j'' that is
petroleum-based, not including any denaturant that may be present in
any ethanol product, expressed as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).
(3) Calculation Method 2 procedures for products.
(i) A reporter using Calculation Method 2 of this subpart to
determine the emission factor of a petroleum product that does not
contain denatured ethanol must calculate the CO2 emissions
associated with that product using Equation MM-10 of this section in
place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.038
Where:
CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each product ``i''
(metric tons).
Producti = Annual volume of each petroleum product ``i''
produced, imported, or exported by the reporting party (barrels).
For refiners, this volume only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-2 to subpart MM that most closely represents the component of
product ``i'' that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is
biomass-based, expressed as a fraction (e.g., 75% would be expressed
as 0.75 in the above equation).
(ii) In the event that a petroleum product contains denatured
ethanol, importers and exporters must follow Calculation Method 1
procedures in paragraph (h)(1) of this section; and refineries must
sample the petroleum portion of the blended biomass-based fuel prior to
blending and calculate CO2 emissions using Equation MM-10a
of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.039
Where:
CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of each biomass-blended
fuel ``i'' (metric tons).
Productp = Annual volume of the petroleum-based portion
of each biomass blended fuel ``i'' produced by the refiner
(barrels).
EFi = Petroleum product-specific CO2 emission
factor (metric tons CO2 per barrel).
(4) Calculation Method 2 procedures for non-crude feedstocks.
(i) A refiner using Calculation Method 2 of this subpart to
determine the emission factor of a non-crude petroleum feedstock that
does not contain denatured ethanol must calculate the CO2
emissions associated with that feedstock using Equation MM-11 of this
section in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.040
Where:
CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of each non-crude
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product
``j'' that enters the refinery to be further refined or otherwise
used on site (barrels).
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-2 to subpart MM that most closely represents the component of
petroleum product ``j'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that
is biomass-based, expressed as a fraction (e.g., 75% would be
expressed as 0.75 in the above equation).
(ii) In the event that a non-crude feedstock contains denatured
ethanol, refiners must follow Calculation Method 1 procedures in
paragraph (h)(2) of this section.
(i) Optional procedures for blended products that do not contain
biomass.
(1) In the event that a reporter produces, imports, or exports a
blended product that does not include biomass, the reporter may
calculate emissions for the blended product according to the method in
paragraph (i)(2) of this section. In the event that a refiner receives
a blended non-crude feedstock that does not include biomass, the
refiner may calculate emission for the blended non-crude feedstock
according
[[Page 66477]]
to the method in paragraph (i)(3) of this section. The procedures in
this section may be used only if all of the following criteria are met:
(i) The reporter knows the relative proportion of each component of
the blend (i.e., the mass or volume percentage).
(ii) Each component of blended product ``i'' or blended non-crude
feedstock ``j'' meets the strict definition of a product listed in
Table MM-1 to subpart MM.
(iii) The blended product or non-crude feedstock is not comprised
entirely of natural gas liquids.
(iv) The reporter uses Calculation Method 1.
(v) Solid components are blended only with other solid components.
(2) The reporter must calculate emissions for the blended product
using Equation MM-12 of this section in place of Equation MM-1 of this
section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.041
Where:
CO2i = Annual CO2 emissions that would result
from the complete combustion or oxidation of a blended product ``i''
(metric tons).
Blending Componenti...n = Annual volume or mass of each
blending component that is blended (barrels or metric tons).
EFi...n = CO2 emission factors specific to
each blending component (metric tons CO2 per barrel or
per metric ton of product).
n = Number of blending components blended into blended product
``i''.
(3) For refineries, the reporter must calculate emissions for the
blended non-crude feedstock using Equation MM-13 of this section in
place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR28OC10.042
Where:
CO2j = Annual CO2 emissions that would result
from the complete combustion or oxidation of a blended non-crude
feedstock ``j'' (metric tons).
Blending Componenti...n = Annual volume or mass of each
blending component that is blended (barrels or metric tons).
EFi...n = CO2 emission factors specific to
each blending component (metric tons CO2 per barrel or
per metric ton of product).
n = Number of blending components blended into blended non-crude
feedstock ``j''.
(4) For refineries, if a blending component ``k'' used in paragraph
(i)(2) of this section enters the refinery before blending as non-crude
feedstock:
(i) The emissions that would result from the complete combustion or
oxidation of non-crude feedstock ``k'' must still be calculated
separately using Equation MM-2 of this section and applied in Equation
MM-4 of this section.
(ii) The quantity of blending component ``k'' applied in Equation
MM-12 of this section and the quantity of non-crude feedstock ``k''
applied in Equation MM-2 of this section must be determined using the
same method or practice.
0
62. Section 98.394 is amended by:
0
a. Revising paragraph (a)(1) introductory text.
0
b. Adding paragraph (a)(3).
0
c. Revising paragraphs (d)(1) through (d)(4).
The revisions and additions read as follows:
Sec. 98.394 Monitoring and QA/QC requirements.
(a) * * *
(1) The quantity of petroleum products, natural gas liquids, and
biomass, as well as the quantity of crude oil measured on site at a
refinery, shall be determined as follows:
* * * * *
(3) The quantity of crude oil not measured on site at a refinery
shall be determined according to one of the following methods. You may
use an appropriate standard method published by a consensus-based
standards organization or you may use an industry standard practice.
* * * * *
(d) * * *
(1) A representative sample or multiple representative samples of
each batch of crude oil shall be taken according to one of the
following methods. You may use an appropriate standard method published
by a consensus-based standards organization or you may use an industry
standard practice.
(2) Samples shall be handled according to one of the following
methods. You may use an appropriate standard method published by a
consensus-based standards organization or you may use an industry
standard practice.
(3) API gravity shall be measured according to one of the following
methods. You may use an appropriate standard method published by a
consensus-based standards organization or you may use an industry
standard practice. The weighted average API gravity for each batch
shall be calculated by multiplying the volume associated with each
representative sample by the API gravity, adding these values for all
the samples, and then dividing that total value by the volume of the
batch.
(4) Sulfur content shall be measured according to one of the
following methods. You may use an appropriate standard method published
by a consensus-based standards organization or you may use an industry
standard practice. The weighted average sulfur content for each batch
shall be calculated by multiplying the volume associated with each
representative sample by the sulfur content, adding these values for
all the samples, and then dividing that total value by the volume of
the batch.
* * * * *
0
63. Section 98.396 is amended by:
0
a. Revising paragraph (a)(3).
0
b. Amending paragraphs (a)(5) and (a)(6) by adding a third sentence.
0
c. Revising paragraphs (a)(7), (a)(16), and (a)(17), (a)(20)(ii),
(a)(20)(iii), and (a)(20)(iv).
0
d. Adding paragraphs (a)(20)(v), (a)(20)(vi), (a)(22), and (a)(23).
0
e. Revising paragraphs (b)(3) and (c)(3).
0
f. Adding paragraph (d).
Sec. 98.396 Data reporting requirements.
* * * * *
(a) * * *
(3) For each feedstock reported in paragraph (a)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(a)(2) of this section that is petroleum-based
[[Page 66478]]
(excluding any denaturant that may be present in any ethanol product).
* * * * *
(5) * * * Petroleum products and natural gas liquids that enter the
refinery, but are not reported in (a)(1), shall not be reported under
this paragraph.
(6) * * * Petroleum products and natural gas liquids that enter the
refinery, but are not reported in (a)(2), shall not be reported under
this paragraph.
(7) For each product reported in paragraph (a)(6) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(a)(6) of this section that is petroleum-based (excluding any
denaturant that may be present in any ethanol product).
* * * * *
(16) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each petroleum product and
natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of
this section that were calculated according to Sec. 98.393(a) or (h).
(17) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each feedstock reported in
paragraph (a)(2) of this section that were calculated according to
Sec. 98.393(b) or (h).
* * * * *
(20) * * *
(ii) Weighted average API gravity representing the batch at the
point of entry at the refinery.
(iii) Weighted average sulfur content representing the batch at the
point of entry at the refinery.
(iv) Country of origin, of the batch, if known and data in
paragraphs (a)(20)(v) and (a)(20)(vi) of this section are unknown.
(v) EIA crude stream code and crude stream name of the batch, if
known.
(vi) Generic name for the crude stream and the appropriate EIA two-
letter country or state and production area code of the batch, if known
and no appropriate EIA crude stream code exists.
* * * * *
(22) Volume of crude oil in barrels that you injected into a crude
oil supply or reservoir. A volume of crude oil that entered the
refinery, but was not reported in paragraphs (a)(2) or (a)(20), shall
not be reported under this paragraph.
(23) Special provisions for 2010. For reporting year 2010 only, a
refiner that knows the information under a specific tier of the batch
definition in 40 CFR 98.398, but does not have the necessary data
collection and management in place to readily report this information,
can use the next most appropriate tier of the batch definition for
reporting batch information under paragraph 98.396(a)(20).
(b) * * *
(3) For each product reported in paragraph (b)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(b)(2) of this section that is petroleum-based (excluding any
denaturant that may be present in any ethanol product).
* * * * *
(c) * * *
(3) For each product reported in paragraph (c)(2) of this section
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph
(c)(2) of this section that is petroleum based (excluding any
denaturant that may be present in any ethanol product).
* * * * *
(d) Blended non-crude feedstock and products. (1) Refineries,
exporters, and importers must report the following information for each
blended product and non-crude feedstock where emissions were calculated
according to Sec. 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO2 emissions in metric tons that would result
from the complete combustion or oxidation of each blended non-crude
feedstock or product, using Equation MM-12 or Equation MM-13 of this
section.
(iii) Whether it is a blended non-crude feedstock or a blended
product.
(2) For a product that enters the refinery to be further refined or
otherwise used on site that is a blended non-crude feedstock, refiners
must meet the reporting requirements of paragraphs (a)(1) and (a)(2) of
this section by reflecting the individual components of the blended
non-crude feedstock.
(3) For a product that is produced, imported, or exported that is a
blended product, refiners, importers, and exporters must meet the
reporting requirements of paragraphs (a)(5), (a)(6), (b)(1), (b)(2),
(c)(1), and (c)(2) of this section, as applicable, by reflecting the
individual components of the blended product.
0
64. Section 98.397 is amended by:
a. Revising the second sentence of paragraph (b).
b. Removing paragraph (e).
c. Redesignating paragraphs (f) and (g) as (e) and (f),
respectively.
The amended text reads as follows:
Sec. 98.397 Records that must be retained.
* * * * *
(b) * * * For all reported quantities of petroleum products,
natural gas liquids, and biomass, as well as crude oil quantities
measured on site at a refinery, reporters shall maintain metering,
gauging, and other records normally maintained in the course of
business to document product and feedstock flows including the date of
initial calibration and the frequency of recalibration for the
measurement equipment used.
* * * * *
0
65. Section 98.398 is revised to read as follows:
Sec. 98.398 Definitions.
Except as specified in this section, all terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part.
Batch means either a volume of crude oil that enters a refinery or
the components of such volume (e.g., the volumes of different crude
streams that are blended together and then delivered to a refinery).
The batch volume is the first appropriate tier in the following list:
(1) Up to an annual volume of a type of crude oil identified by an
EIA crude stream code, if the EIA crude stream code is known.
(2) Up to an annual volume of a type of crude oil identified by a
generic name for the crude stream and an appropriate EIA two-letter
country or state and production area code, if the generic name and EIA
two-letter code are known but no appropriate EIA crude stream code
exists.
(3) Up to a calendar month of crude oil volume from a single known
foreign country of origin if the crude stream name is unknown.
(4) Up to a calendar month of crude oil volume from the United
States if the crude stream name and production area are unknown.
(5) Up to a calendar month of crude oil volume if the country of
origin is unknown.
Subpart NN--[Amended]
0
66. Section 98.403 is amended by:
0
a. Revising the definitions of ``Fuelh'' and
``HHVh'' in Equation NN-1 of paragraph (a)(1).
0
b. Revising the definition of ``Fuelh'' in Equation NN-2 of
paragraph (a)(2).
0
c. Revising the definition of ``Fuel1'' in Equation NN-5 of
paragraph (b)(3).
[[Page 66479]]
0
d. Revising the definition of ``EFg'' in Equation NN-7 of
paragraph (c)(1).
0
e. In paragraph (c)(2), revising Equation NN-8 and the definition of
``CO2i'' in Equation NN-8.
The revisions read as follows:
Sec. 98.403 Calculating GHG emissions.
(a) * * *
(1) * * *
Fuelh = Total annual volume of product ``h'' supplied
(volume per year, in thousand standard cubic feet (Mscf) for natural
gas and bbl for NGLs).
HHVh = Higher heating value of product ``h'' supplied
(MMBtu/Mscf or MMBtu/bbl).
* * * * *
(2) * * *
Fuelh = Total annual volume of product ``h'' supplied
(bbl or Mscf per year)
* * * * *
(b) * * *
(3) * * *
Fuel1 = Total annual volume of natural gas received by
the LDC at the city gate and stored on-system or liquefied and
stored in the reporting year (Mscf per year).
* * * * *
(c) * * *
(1) * * *
EFg = Fuel-specific CO2 emission factor of NGL
product ``g'' (MT CO2/bbl).
(2) * * *
[GRAPHIC] [TIFF OMITTED] TR28OC10.043
* * * * *
CO2i = Annual CO2 mass emissions that would
result from the combustion or oxidation of fractionated NGLs
delivered to all customers or on behalf of customers as calculated
in paragraph (a)(1) or (a)(2) of this section (metric tons).
* * * * *
0
67. Section 98.406 is amended by revising paragraphs (a)(6) and (a)(9)
introductory text to read as follows:
Sec. 98.406 Data reporting requirements.
(a) * * *
(6) Annual CO2 emissions (metric tons) that would result
from the complete combustion or oxidation of the quantities in
paragraphs (a)(1) and (a)(2) of this section, calculated in accordance
with Sec. 98.403(a) and (c)(1).
* * * * *
(9) If the NGL fractionator developed reporter-specific EFs or
HHVs, report the following for each product type:
* * * * *
0
68. Section 98.407 is amended by revising paragraphs (a) and (d) to
read as follows:
Sec. 98.407 Records that must be retained.
* * * * *
(a) Records of all meter readings and documentation to support
volumes of natural gas and NGLs that are reported under this part.
* * * * *
(d) Records related to the large end-users identified in Sec.
98.406(b)(7).
* * * * *
0
69. Tables NN-1 and NN-2 to Subpart NN are revised to read as follows:
Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation
Methodology 1 of This Subpart
------------------------------------------------------------------------
Default CO2
Fuel Default high heating emission factor
value factor (kg CO2/MMBtu)
------------------------------------------------------------------------
Natural Gas................... 1.028 MMBtu/Mscf..... 53.02
Propane....................... 3.822 MMBtu/bbl...... 61.46
Normal butane................. 4.242 MMBtu/bbl...... 65.15
Ethane........................ 4.032 MMBtu/bbl...... 62.64
Isobutane..................... 4.074 MMBtu/bbl...... 64.91
Pentanes plus................. 4.620 MMBtu/bbl...... 70.02
------------------------------------------------------------------------
Table NN-2 to Subpart NN of Part 98--Lookup Default Values for
Calculation Methodology 2 of This Subpart
------------------------------------------------------------------------
Default CO2
Fuel Unit emission value
(MT CO2/Unit)
------------------------------------------------------------------------
Natural Gas................... Mscf................. 0.055
Propane....................... Barrel............... 0.235
Normal butane................. Barrel............... 0.276
Ethane........................ Barrel............... 0.253
Isobutane..................... Barrel............... 0.266
Pentanes plus................. Barrel............... 0.324
------------------------------------------------------------------------
[FR Doc. 2010-26506 Filed 10-27-10; 8:45 am]
BILLING CODE 6560-50-P