```

[Federal Register: October 28, 2010 (Volume 75, Number 208)]
[Rules and Regulations]               
[Page 66433-66479]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr28oc10-15]                         

[[Page 66433]]

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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

[[Page 66434]]

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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: GHGReportingRule@epa.gov. 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
----------------------------------------------------------------------------------------------------------------
                    Category                         NAICS              Examples of affected facilities
----------------------------------------------------------------------------------------------------------------
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.
----------------------------------------------------------------------------------------------------------------

    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

[[Page 66436]]

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

[[Page 66437]]

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, paul.mcafee@mosaicco.com). 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, 
paul.mcafee@mosaicco.com).
* * * * *

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\ 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
```