Document ID: EPA-HQ-OAR-2010-0109-0001
Agency: epa
Document Type: Proposed Rule
Title: Mandatory Reporting of Greenhouse Gases
Posted Date: 2010-06-15T04:00Z

[Federal Register: June 15, 2010 (Volume 75, Number 114)]
[Proposed Rules]               
[Page 33949-33982]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr15jn10-37]                         

[[Page 33949]]

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Part III

Environmental Protection Agency

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40 CFR Parts 86 and 98

 Mandatory Reporting of Greenhouse Gases; Proposed Rule

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 86 and 98

[EPA-HQ-OAR-2010-0109; FRL-9158-6]
RIN 2060-A079

 
Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing to amend specific provisions in the 2009 
Final Mandatory Greenhouse Gas Reporting rule (2009 Final MRR) to 
correct certain technical and editorial errors that have been 
identified since promulgation and to clarify or propose minor updates 
to certain provisions that have been the subject of questions from 
reporting entities. These proposed 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. EPA has received six petitions for 
reconsideration on the 2009 Final MRR. EPA is still considering these 
petitions, and the issues raised in the petitions are not discusssed or 
addressed in today's action.

DATES: Comments. Comments must be received on or before July 30, 2010.
    Public Hearing. EPA does not plan to conduct a public hearing 
unless requested. To request a hearing, please contact the person 
listed in the following FOR FURTHER INFORMATION CONTACT section by June 
22, 2010. If requested, the hearing will be conducted on June 30, 2010, 
in the Washington, DC area. EPA will provide further information about 
the hearing on its webpage if a hearing is requested.

ADDRESSES: You may submit your comments, identified by docket ID No. 
EPA-HQ-OAR-2010-0109 by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: MRR_Corrections@epa.gov. Include docket ID No. 
EPA-HQ-OAR-2010-0109 [and/or RIN number] in the subject line of the 
message.
     Fax: (202) 566-1741.
     Mail: Environmental Protection Agency, EPA Docket Center 
(EPA/DC), Mailcode 2822T, Attention Docket ID No. OAR-2010-0109, 1200 
Pennsylvania Avenue, NW., Washington, DC 20004.
     Hand/Courier Delivery: EPA Docket Center, Public Reading 
Room, EPA West Building, Room 3334, 1301 Constitution Avenue, NW., 
Washington, DC 20004. Such deliveries are only accepted during the 
Docket's normal hours of operation, and special arrangements should be 
made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2010-0109, Technical Corrections, Clarifying and Other Amendments to 
Certain Provisions of the Mandatory Greenhouse Gas Reporting Rule. 
EPA's policy is that all comments received will be included in the 
public docket without change and may be made available online at http:/
/www.regulations.gov, including any personal information provided, 
unless the comment includes information claimed to be confidential 
business information (CBI) or other information whose disclosure is 
restricted by statute. Do not submit information that you consider to 
be CBI or otherwise protected through http://www.regulations.gov or e-
mail. The http://www.regulations.gov Web site is an ``anonymous 
access'' system, which means EPA will not know your identity or contact 
information unless you provide it in the body of your comment. If you 
send an e-mail comment directly to EPA without going through http://
www.regulations.gov your e-mail address will be automatically captured 
and included as part of the comment that is placed in the public docket 
and made available on the Internet. If you submit an electronic 
comment, EPA recommends that you include your name and other contact 
information in the body of your comment and with any disk or CD-ROM you 
submit. If EPA cannot read your comment due to technical difficulties 
and cannot contact you for clarification, EPA may not be able to 
consider your comment. Electronic files should avoid the use of special 
characters, any form of encryption, and be free of any defects or 
viruses.
    Docket: All documents in the docket are listed in the 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, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, 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 INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
GHGReportingRule@epa.gov. For technical information contact the 
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: ghgmrr@epa.gov. To obtain information about the public 
hearings or to register to speak at the hearings, please go to http://
www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively, 
contact Carole Cook at 202-343-9263.
    Worldwide Web (WWW). In addition to being available in the docket, 
an electronic copy of today's proposal will also be available through 
the WWW. Following the Administrator's signature, a copy of this action 
will be posted on EPA's greenhouse gas reporting rule Web site at 
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.

SUPPLEMENTARY INFORMATION: 
    Additional Information on Submitting Comments: To expedite review 
of your comments by Agency staff, you are encouraged to send a separate 
copy of your comments, in addition to the copy you submit to the 
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric 
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC 
20460, telephone (202) 343-9263, e-mail address: 
GHGReportingRule@epa.gov.
    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 
proposed amendments to existing regulations. If finalized, these 
amended regulations would affect owners or operators of certain fossil 
fuel suppliers, direct emitters of GHGs, and manufacturers of highway 
heavy-duty vehicles. Regulated categories and entities include those 
listed in Table 1 of this preamble:

[[Page 33951]]

                               Table 1--Examples of Affected Entities by Category
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                   Category                          NAICS               Examples of affected facilities
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Adipic Acid Production........................          325199  Adipic acid manufacturing facilities.
Cement Production.............................          327310  Portland cement manufacturing plants.
Ferroalloy Production.........................          331112  Ferroalloys manufacturing facilities.
Glass Production..............................          327211  Flat glass manufacturing facilities.
                                                        327213  Glass container manufacturing facilities.
                                                        327212  Other pressed and blown glass and glassware
                                                                 manufacturing facilities.
HCFC-22 Production and HFC-23 Destruction.....          325120  Chlorodifluoromethane manufacturing facilities.
Hydrogen Production...........................          325120  Hydrogen manufacturing facilities.
Iron and Steel Production.....................          331111  Integrated iron and steel mills, steel
                                                                 companies, sinter plants, blast furnaces, basic
                                                                 oxygen process furnace shops.
Lime Production...............................          327410  Calcium oxide, calcium hydroxide, dolomitic
                                                                 hydrates manufacturing facilities.
Nitric Acid Production........................          325311  Nitric acid manufacturing facilities.
Phosphoric Acid Production....................          325312  Phosphoric acid manufacturing facilities.
Soda Ash Manufacturing........................          325181  Alkalies and chlorine manufacturing facilities.
                                                        212391  Soda ash, natural, mining and/or beneficiation.
Titanium Dioxide Production...................          325188  Titanium dioxide manufacturing facilities.
Zinc Production...............................          331419  Primary zinc refining facilities.
                                                        331492  Zinc dust reclaiming facilities, recovering from
                                                                 scrap and/or alloying purchased metals.
Municipal Solid Waste Landfills...............          562212  Solid Waste Landfills.
                                                        221320  Sewage Treatment Facilities.
Suppliers of Coal Based Liquids Fuels.........          211111  Coal liquefaction at mine sites.
Suppliers of Natural Gas and NGLs.............          221210  Natural gas distribution facilities.
                                                        211112  Natural gas liquid extraction facilities.
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    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Table 1 of this preamble lists the types of 
facilities that EPA is now aware could be potentially affected by the 
reporting requirements. Other types of facilities than those listed in 
the table could also be subject to reporting requirements. To determine 
whether you are affected by this action, you should carefully examine 
the applicability criteria found in 40 CFR part 98, subpart A or the 
relevant criteria in the sections related to fossil fuel suppliers, 
direct emitters of GHGs, and manufacturers of highway heavy-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.
    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
CAA Clean Air Act
CaO calcium oxide
CBI confidential business information
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
DE destruction efficiency
EAF electric arc furnace
EF emission factor
EIA Energy Information Administration
EO Executive Order
EPA U.S. Environmental Protection Agency
FR Federal Register
GHG greenhouse gas
HHV higher heating value
ID identification
kg kilograms
LNG liquefied natural gas
MgO magnesium oxide
Mscf thousand standard cubic feet
MRR mandatory GHG reporting rule
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
NOX nitrogen oxides
OMB Office of Management and Budget
QA/QC quality assurance/quality control
RFA Regulatory Flexibility Act
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Background on Today's Action
    C. Legal Authority
    D. How would these amendments apply to 2011 reports?
II. Technical Corrections and Other Amendments
    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
    Q. Subpart LL--Suppliers of Coal-based Liquid Fuels
    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

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I. Background

A. How is this preamble organized?

    The first section of this preamble contains the basic background 
information about the origin of these proposed rule amendments and 
request for public comment. This section also discusses EPA's use of 
our legal authority under the Clean Air Act to collect data under the 
mandatory GHG reporting rule.
    The second section of this preamble describes in detail the changes 
that are being proposed to correct technical errors, to provide 
clarification, or propose amendments to address implementation issues 
identified by EPA and others. This section also presents EPA's 
rationale for the proposed changes and identifies issues on which EPA 
is particularly interested in receiving public comments.
    Finally, the last (third) section of the preamble discusses the 
various statutory and executive order requirements applicable to this 
proposed rulemaking.

B. Background on Today's Action

    The 2009 Final MRR was signed by EPA Administrator Lisa Jackson on 
September 22, 2009 and published in the Federal Register on October 30, 
2009 (74 FR 56260-56519, October 30, 2009). The 2009 Final MRR, which 
became effective on December 29, 2009, included reporting of GHGs from 
various facilities and suppliers, consistent with the 2008 Consolidated 
Appropriations Act.\1\ The source categories in the 2009 Final MRR 
cover approximately 85 percent of U.S. GHG emissions through reporting 
by direct emitters as well as suppliers of fossil fuels and industrial 
gases.
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    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128.
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C. Legal Authority

    EPA is proposing these rule amendments under its existing CAA 
authority, specifically authorities provided in section 114 and section 
208 of the CAA.
    As stated in the preamble to the 2009 Final MRR (74 FR 56260, 
October 30, 2009), CAA section 114 provides EPA broad authority to 
require the information proposed to be gathered by this rule because 
such data would inform and are relevant to EPA's carrying out a wide 
variety of CAA provisions. As discussed in the preamble to the initial 
proposed rule (74 FR 16448, April 10, 2009), section 114(a)(1) of the 
CAA authorizes the Administrator to require emissions sources, persons 
subject to the CAA, manufacturers of control or process equipment, or 
persons whom the Administrator believes may have necessary information 
to monitor and report emissions and provide such other information the 
Administrator requests for the purposes of carrying out any provision 
of the CAA. For further information about EPA's legal authority, see 
the preambles to the proposed and 2009 Final MRR.\2\
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    \2\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 
2009).
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D. How would these amendments apply to 2011 reports?

    EPA is planning to address the comments on these proposed 
amendments and publish the final amendments before the end of 2010. 
Therefore, reporters would be expected to calculate emissions and other 
relevant data for the reports that are submitted in 2011 using the 2009 
Final MRR as amended. We have determined that it is feasible for the 
sources to implement these changes for the 2010 reporting year since 
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.
    For example, many proposed revisions simply provide additional 
information to provide additional clarity on existing requirements. For 
example, in subpart E (Adipic Acid Production) we are proposing to 
clarify that the location of the testing point for determining the 
emission factor can occur before or after N2O abatement 
technology as long as the destruction efficiency of the N2O 
abatement technology is properly accounted for. This proposed 
clarification is consistent with clarifications EPA has issued in 
response to industry questions and would not change how facilities 
collected data during 2010. In subpart K, clarifying text is proposed 
in Sec.  98.112 to ensure that facilities calculate CH4 
emissions for all ferroalloys included in Table K-1. Again, this 
clarification does not change the rule requirements for facilities 
collecting data in 2010 as the requirement was already clear in Sec.  
98.113(d).
    Some proposed amendments are to the data reporting requirements to 
provide additional clarity on the level of reporting for a specific 
parameter (e.g., unit level or facility level). For example, in subpart 
CC (Soda Ash Manufacturing) we are proposing to clarify that reporting 
is by soda ash manufacturing line. While the data reporting 
requirements in the 2009 Final MRR could have been misinterpreted, the 
calculation methods in Sec.  98.293 are very clear that emissions 
calculations are by manufacturing line. EPA has concluded that 
amendments such as these can be implemented for the reports submitted 
to EPA in 2011 because the proposed changes are consistent with the 
calculation methodologies in the 2009 Final MRR and the owners or 
operators are not required to actually report until March 2011, several 
months after we expect this proposal to be finalized.
    For some subparts, we propose amendments to address issues 
identified as a result of working with the affected sources during rule 
implementation. These proposed revisions provide additional flexibility 
to the sources. Thus, while they would be free to use the amended 
regulations once final, facilities are not required to follow the 
amendments for 2010 data collection. For example, in subpart H, cement 
production, facilities are provided an additional approach for 
calculating the weight fraction of total calcium oxide and total 
magnesium oxide in clinker. Some facilities were already determining 
their weight fraction following this method. In some cases, these 
facilities may have been following both their current practice during 
2010 data collection, as well as the method required by the 2009 Final 
MRR. With these proposed amendments, these facilities would have the 
option, but not be required, to use the newly proposed option for the 
reports submitted to EPA in 2011.
    EPA is also proposing corrections to terms and definitions in 
certain equations. For example, in subpart NN, Suppliers of Natural Gas 
and Natural Gas Liquids, we are proposing to clarify in an equation 
that the fuel-specific emission factor should be developed for NGL 
product ``g''. It was clear from the rest of the equation that the mass 
emissions should be developed for each NGL product ``g'', but this 
phrase was omitted from the definition of EFg. Other 
examples are found in similar clarifications made in subpart P 
(Hydrogen Production) and subpart S (Lime Production). These 
clarifications do not result in additional requirements therefore EPA 
has concluded that reporters can follow the 2009 Final MRR, as amended, 
in submitting their first reports in 2011.
    Finally, EPA is proposing other technical corrections (example 
correcting cross references) that have no impact on facility's data 
collection efforts in 2010.

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    In summary, these amendments would not require any additional 
monitoring or information collection above what was already included in 
the 2009 Final MRR. Therefore, we expect that sources can use the same 
information that they have been collecting under the 2009 Final MRR for 
each subpart to calculate and report GHG emissions for 2010 and submit 
reports in 2011 under the amended subparts.
    EPA generally seeks comment on the conclusion that it is 
appropriate to implement these amendments and incorporate the 
requirements in the data reported to EPA by March 31, 2011. Further, we 
seek comment on whether there are specific subparts for example, 
subpart MM, where this timeline may not be feasible or appropriate due 
to the nature of the proposed changes or the way in which data have 
been collected thus far in 2010. We request that commenters provide 
specific examples of how the proposed implementation schedule would or 
would not work.

II. Technical Corrections and Other Amendments

    Following promulgation of the 2009 Final MRR, EPA has identified 
errors in the regulatory language that we are now proposing to correct. 
These errors were identified as a result of working with affected 
industries to implement the various subparts of the 2009 Final MRR. We 
have also identified certain rule provisions that should be amended to 
provide greater clarity.
    The amendments we are now proposing 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 affected sources during rule implementation 
and outreach.
    We are seeking public comment only on the issues specifically 
identified in this notice for the identified subparts. We will not 
respond to any comments addressing other aspects of the 2009 Final MRR 
or any other related rulemakings.

A. Mobile Sources

    Manufacturers of highway heavy-duty vehicles, as well as 
manufacturers of highway heavy-duty engines, are subject to GHG 
reporting requirements as proposed (see Section V.QQ.3.d starting on 
page 16589 of the proposed rule preamble), and as stated in the 
preamble for the 2009 Final MRR (see Table IV-1 on page 56353 of the 
final rule preamble). EPA inadvertently omitted the regulatory text 
covering manufacturers of highway heavy-duty vehicles. We are proposing 
to amend 40 CFR part 86 to correct that error by incorporating the 
appropriate language into the regulations at 40 CFR 86.1844-01.

B. Subpart A--General Provisions

    We are proposing to add or change several definitions to subpart A, 
to clarify terms used in other subparts of the 2009 Final MRR. 
Similarly, we are proposing to amend 40 CFR 98.7 (incorporation by 
reference) to accommodate changes in the standard methods that are 
allowed by other subparts of the rule.
    We are proposing to amend the following definitions in 40 CFR 98.6:
     Carbonate-based mineral,
     Carbonate-based mineral mass fraction,
     Carbonate-based raw material,
     Crude oil, and
     Gas collection system or landfill gas collection system.
    We are proposing to amend the definitions of ``carbonate-based 
mineral'', ``carbonate-based mineral mass fraction'' and ``carbonate-
based raw material'' in order to include barium carbonate and potassium 
carbonate. These carbonates were not included in the 2009 Final MRR; 
however, EPA has since learned that these are consumed in the glass 
industry subject to subpart N. Therefore, we are proposing emission 
factors for these carbonates in subpart N and, for consistency, we are 
proposing to concurrently amend these definitions in 40 CFR 98.6.
    We are proposing to amend the definition of ``crude oil'' in 40 CFR 
98.6 to be identical to the definition in the Energy Information 
Administration's (EIA) Definitions of Petroleum Products and Other 
Terms (Revised January 2010).\3\ As indicated by our definition of 
crude oil in the Notice of Proposed Rulemaking (74 FR 16448), our 
intention is to collect information under 40 CFR 98.396(a)(20) on 
certain hydrocarbons from sources that are not liquid while underground 
as well as those that are liquid underground. We changed the definition 
of crude oil after proposal in response to a comment suggesting that 
the proposed definition could be interpreted to include natural gas 
(see comment EPA-HQ-OAR-2008-0508-0631.1, excerpt 36 in Volume 13: 
Subpart A: Definitions, Incorporation by Reference, and Other Subpart A 
Comments). In making this change after proposal, we inadvertently 
limited the definition of crude oil in the 2009 Final MRR to 
hydrocarbons that exist in a liquid phase underground. We are proposing 
to correct this error in today's action. We also expect to increase 
clarity and reduce administrative burden for reporters by proposing to 
use EIA's definition of ``crude oil,'' which many reporters already use 
to track crude oil for EIA's petroleum supply surveys.
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    \3\ http://www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/
psmdefs_2010.pdf.
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    We received several questions as to whether passive vents or flares 
are considered part of a landfill gas collection system at a municipal 
solid waste landfill. To clarify that the passive vents/flares are not 
considered part of a landfill gas collection system for purposes of 
subpart HH, we are proposing to amend the definition of ``gas 
collection system or landfill gas collection system,'' in 40 CFR 98.6 
to state that such a system collects gas by means of a fan or similar 
mechanical, versus passive, draft equipment.
    We are also proposing to amend the definition of ``Mscf'' in 40 CFR 
98.6 to indicate that ``Mscf'' means thousand standard cubic feet, and 
not, as incorrectly stated in the 2009 Final MRR, a million standard 
cubic feet.
    We also are proposing to amend 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, including supplemental fuel 
burned to provide heat or thermal energy. The definition of 
``feedstock'' in 40 CFR 98.6 excludes supplemental fuel burned to 
provide heat or thermal energy. By removing the term ``as a feedstock'' 
from the definition of ``non-crude feedstock'' and adding ``including 
supplemental fuel burned to provide heat or thermal energy,'' the 
proposed amendments align the

[[Page 33954]]

definition to the original intent of the rule.
    Additional amendments to definitions are proposed in the relevant 
subparts.
    Today's proposal would also correct an error in the title of a 
method incorporated by reference in 40 CFR 98.7 for subpart Z, which 
would be updated to reflect the correct title, ``Association of 
Fertilizer and Phosphate Chemists Analytical Methods Manual, 10th 
Edition.'' We are also proposing to incorporate 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.

C. Subpart E--Adipic Acid Production

    We are proposing to amend Equations E-1, Equation E-2 and Equation 
E-3 in 40 CFR 98.53. First, we are proposing to amend 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 proposing to amend the equations so that emissions 
would be 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 sum the emissions for all such units or lines to 
determine the overall N2O emissions for the facility. For 
consistency with these amendments, we are also proposing amendments to 
40 CFR 98.54(a), 98.56(j), and 98.57(c) for monitoring and QA/QC, 
reporting, and recordkeeping, respectively.
    We are also proposing to amend equation E-3 to accommodate 
N2O abatement technology located after the emission test 
(sampling) point, and re-designate it as equation E-3a. We are also 
proposing to add a new equation E-3b for facilities that do not have 
any N2O abatement technology located after the test 
(sampling) point.
    Second, we are proposing to amend 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 proposing to amend the language in 40 CFR 
98.54(a)(1), (e), and (f) concerning the location of the test 
(sampling) point used for the performance test and to clarify when the 
performance test should be conducted. As promulgated, the language can 
be 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 are mandatory according to the facility 
operating permit. The proposed amendments would 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. Finally, we are proposing to 
clarify under 98.57(f) that facilities should retain records of all 
data collected during performance tests, not just the calculated 
emission factor.

D. Subpart H--Cement Production

    We are proposing to amend 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 proposing to amend 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 proposing to amend 40 CFR 98.84(d) to 
allow facilities to use these procedures already used 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 proposing to amend 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.
    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 kiln feed depending on the existing sampling methods 
and raw material storage procedures at the facility. We are proposing 
to amend 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 proposing to correct and clarify the recordkeeping 
requirements under 40 CFR 98.87(a) and (b) for facilities with CEMS and 
for facilities without CEMS. In the 2009 Final MRR, 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).

E. Subpart K--Ferroalloy Production

    We are proposing to amend 40 CFR 98.112(a) to be consistent with 
the requirement described in 40 CFR 98.113(d) and in the preamble of 
the 2009 Final MRR 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. The 2009 Final MRR contained 
calculation and reporting procedures for quantifying process 
CH4 emissions from all ferroalloys listed in Table K-1, but 
CH4 was inadvertantly not included in the GHG's to Report 
section.
    We are also proposing to amend 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 proposing minor amendments to 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 proposing 
to amend 40 CFR 98.116(d) to correct an incorrect cross-reference to 40 
CFR 98.36.

F. Subpart N--Glass Production

    We are proposing to amend subpart N to add CO2 emission 
factors to Table N-

[[Page 33955]]

1 for barium carbonate and potassium carbonate. These raw materials 
were not included in the 2009 Final MRR, but EPA has since learned that 
they are also used by the glass industry. EPA is requesting comment on 
whether the proposed amendments to Table N-1 are sufficient or if other 
raw materials or carbonaceous materials are used in glass manufacturing 
that should be included in the rule in Table N-1 with their associated 
emission factors. EPA has also learned from reporters that there is 
another more commonly used method for determining the carbonate mineral 
mass fraction of raw materials used in glass production. EPA proposes 
to amend the rule in 40 CFR 98.144(b) to allow for another ASTM method. 
Specifically, in addition to ASTM D3682-01, reporters could 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 proposing to amend 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 proposing to amend 40 
CFR 98.146(b)(7) and (9) to correct typographical errors.

G. Subpart O--HCFC-22 Production and HFC-23 Destruction

    We are proposing to amend 40 CFR 98.154(k), the requirement to 
monitor HFC-23 emitted from process vents, to refer to Equation O-7 
rather than the incorrect Equation O-6. In 40 CFR 98.154(k), (l), and 
(o) and in 40 CFR 98.156(b), we are proposing to amend the language so 
that the term ``destruction device'' is used rather than the narrower 
term ``thermal oxidizer.''
    We are proposing to amend 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 would 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 would be required to report only the results of their annual 
measurement of the HFC-23 concentration at the outlet of the 
destruction device. Facilities that conduct the annual measurement of 
the HFC-23 concentration only at the outlet of the destruction device 
would be required to report the results of the annual measurement.
    We are proposing to amend 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 proposed 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 proposed amendments to the reporting requirements 
for HFC-23 destruction facilities would make them consistent with the 
monitoring requirements for these facilities. The proposed due dates 
for the one-time report are consistent with those elsewhere in the 2009 
Final MRR for the source categories that are required to begin 
monitoring in 2010.

H. Subpart P--Hydrogen Production

    We are proposing amendments to clarify the definition of the source 
category in 40 CFR 98.160(c). The original language in the 2009 Final 
MRR indicated that the hydrogen production source category included 
hydrogen production processes located within petroleum refineries. The 
intent of the 2009 Final MRR was that hydrogen production facilities 
located within facilities that are not petroleum refineries were also 
included within the definition of the source category. We are proposing 
to amend 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 proposing to amend 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 proposing to clarify the text in the rule 
by removing references to the term ``process'' from the rule language.
    We are proposing to remove 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 would still be reported 
under 98.162(a) using the procedures in 98.163(a) or 98.163(b).
    We are also proposing to amend language describing the calculation 
of GHG emissions from gaseous, liquid and solid fuels and feedstocks in 
40 CFR 98.163. The clarified language would specify that each gaseous, 
liquid or solid fuel and feedstock would need to be calculated based on 
its respective equations detailed in the rule language. This removes 
the concern that the current language was unclear as to which fuel and 
feedstock stream would be used to calculate CO2 emissions.
    Lastly, we are proposing to amend 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.

I. Subpart Q--Iron and Steel Production

    We are proposing to amend 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 the 2009 Final MRR 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) in the 2009 Final MRR 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, 
proposing to amend the language in 40 CFR 98.172(b) to clarify that for 
subpart Q facilities, flare

[[Page 33956]]

emissions must be estimated only for flares burning blast furnace gas 
or coke oven gas. Similarly, we are proposing to amend 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 
proposing to amend 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 the 2009 Final MRR also referenced incorrect equations 
from subpart Y. We are proposing to amend and correct the references in 
40 CFR 98.172(b) to the subpart Y flare equations. Equations Y-2 and Y-
3 are the correct equations; the promulgated subpart Q incorrectly 
referenced Equation Y-1.
    We are proposing to amend 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 proposing to add paragraphs (g) and (h) to 40 CFR 
98.176. Paragraph (g) would require facilities to report the annual 
amount of coal charged to coke ovens because it is used to estimate 
CO2 emissions from coke pushing. Paragraph (g) would 
incorporate 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 proposing to amend 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 proposing to amend the requirements in the promulgated 
rule to estimate GHG emissions from argon-oxygen decarburization 
vessels to clarify that they also apply to any other type of vessel 
used to remove carbon from molten steel (decarburization) and result in 
the venting of similar GHG. The promulgated rule would have required 
reporting of these alternative vessel emissions as part of flare 
emissions. Because of the proposed clarification noted above to limit 
the flare emission calculations to only those flares burning coke oven 
gas or blast furnace gas, we are proposing to replace the term ``argon-
oxygen decarburization vessels'' with the term ``decarburization 
vessels'' throughout the rule and to replace 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.

J. Subpart S--Lime Manufacturing

    We are proposing to amend 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 proposing to amend 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 proposing amendments to the terminology in the 
subpart to clarify when the calculation and reporting requirements 
apply to lime products that are produced at the facility.

K. Subpart V--Nitric Acid Production

    We are proposing to amend 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 concerns the 
language for 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 are mandatory 
according to the facility operating permit. The proposed amendments 
would clarify that testing can occur before or after N2O 
abatement technology as long as the destruction efficiency is properly 
accounted for.
    We are also proposing to include a new Equation V-3b for facilities 
that do not have N2O abatement technology located after the 
test (sampling) point. Equation V-3 would be redesignated as Equation 
V-3a, and would also be corrected so that the term on the left-hand 
side of the equation would be changed from EFN2Ot 
to EN2Ot.
    In addition we are proposing to clarify 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 are 
being proposed for the monitoring requirements in 40 CFR 98.224 to 
conform to the changes in the calculation methods being proposed in 40 
CFR 98.223. We are proposing to amend 40 CFR 98.224(a)(1) to clarify 
when during a nitric acid production campaign facilities must conduct 
the performance test.
    We are also proposing to amend 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 proposing to amend 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.

L. Subpart Z--Phosphoric Acid Production

    We are proposing to amend subpart Z to correct the title of the 
reference to the standard bulk sampling and analysis method in 40 CFR 
98.6, and 40 CFR 98.264(a) and (b). The reference in the 2009 Final MRR 
currently reads, ``Phosphate Mining States Methods Used and Adopted by 
the Association of Fertilizer and Phosphate Chemists AFPC Manual 10th 
Edition 2009--Version 1.9.'' This reference would be revised to read 
the ``Association of Fertilizer and Phosphate Chemists Analytical 
Methods Manual 10th Edition,'' which reflects the correct title of the 
document.
    We have learned from facilities that the AFPC manual does not 
currently contain a procedure for obtaining a representative grab 
sample of rock for testing, but that it will in the future. We are 
proposing to amend 40 CFR 98.264(a) to allow facilities to use the 
appropriate industry consensus standards currently available, in 
addition to the AFPC manual. We are also proposing to amend 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 proposing to amend 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 proposing to add 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.

M. Subpart CC--Soda Ash Manufacturing

    We are proposing to amend the data reporting requirements in 40 CFR 
98.296(b)(3) to clarify that the annual soda ash production is reported 
for each

[[Page 33957]]

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) would be 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 proposing to amend 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 
proposing to delete 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).

N. Subpart EE--Titanium Dioxide Production

    We are proposing to amend 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 proposing to 
amend 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 proposing to amend 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).

O. Subpart GG--Zinc Production

    We are proposing to amend the definitions of the terms for 
(Electrode)k and (CElectrode)k in 
Equation GG-1 to remove the references to kilns because electrodes are 
only used in electrothermic furnaces and are not used in Waelz kilns. 
We are also proposing to amend 40 CFR 98.336(a) to correct a 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 proposing to amend 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.

P. Subpart HH--Municipal Solid Waste Landfills

    We are proposing 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. Technical 
amendments to the rule are also proposed to address some of the more 
significant questions that were the result of insufficient detail being 
provided in the rule.
    Source Category Definition. We are proposing to amend 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, dedicated construction 
and demolition waste landfills, or industrial waste landfills.'' This 
change would clarify the types of landfills that are not included in 
the MSW landfill source category. We are further proposing to add 
definitions within 40 CFR 98.348 for the terms ``dedicated construction 
and demolition waste landfills'' and ``industrial waste landfills'' to 
further clarify what is meant by these excluded landfill types. These 
definitions are from 40 CFR 257.2 (Criteria for Classification of Solid 
Waste Disposal Facilities and Practices).
    Equation HH-1. We are proposing the following technical amendments 
to Equation HH-1 in 40 CFR 98.343:
     Replace the term L0 (CH4 generating 
potential) with the terms, ``MCF x DOC x DOCF x F x 16/12,'' 
(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 as it no longer appears in the 
equation. This change provide clarity of terms and does not affect the 
way in which the methane generation rate is calculated by equation HH-1 
since the new terms were already contained in the definition of 
L0.
     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,'' for clarity.
     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))'' to 
include the use of measurement data with the other methods specified.
     Revise the definition of ``MCF'' to read ``Methane 
correction factor (fraction). Use the default value of 1,'' to clarify 
that the default factor of 1 must be used.
     Revise the definition of ``DOCf'' to read, ``Fraction of 
DOC dissimilated (fraction). Use the default value of 0.5,'' to clarify 
that the default factor of 0.5 must be used.
     Revise the definition of ``F'' to clarify that F is 
determined on a dry basis as follows: ``Fraction by volume of CH4 in 
landfill gas from measurement data on a dry basis, if available 
(fraction); default is 0.5,'' for clarification.
     Revise the definition of ``k'' to read, ``Rate constant 
from Table HH-1 of this subpart (yr-1). Select the most applicable k 
value for the majority of the past 10 years (or operating life, 
whichever is shorter),'' to clarify that k is not a measured value and 
that the selection of k should be based on precipitation and leachate 
recirculation rates over the past 10 years.
    We are also proposing to amend 40 CFR 98.343(a)(2) to replace ``use 
the bulk waste parameter values for k and L0 in Table HH-1'' with ``use 
the bulk waste parameter values for k and DOC in Table HH-1,'' to be 
consistent with the proposed changes to Equation HH-1.
    Measuring Waste Quantity. We are proposing to amend 40 CFR 
98.343(a) by adding a new paragraph (a)(3) that serves to provide the 
necessary detail and clarification on the requirements for measuring 
the quantity of waste disposed in the landfill beginning with the first 
monitoring year (2010 or later, hereafter referred to as ``monitoring 
years''), and re-designating the existing 40 CFR 98.343(a)(3) as 
(a)(4).
    The proposed waste measurement requirements for the monitoring 
years would 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. Passenger vehicles and light duty pick-up 
trucks contribute only a small fraction of the total waste landfilled, 
but they significantly

[[Page 33958]]

contribute to the total number of vehicles entering and exiting the 
landfill. As such, most landfills do not weigh individual passenger 
vehicles or light duty pick-up trucks. Instead, they commonly charge 
these customers a flat tipping fee. Requiring each of these vehicles to 
be weighed both in and out of the landfill would create a significant 
time and recordkeeping burden on the landfill owner or operator which 
was not included in the cost and economic impact analysis for subpart 
HH. Furthermore, we find that such a requirement is not appropriate 
because the significant increase in labor costs will not significantly 
reduce the uncertainty in the mass of waste landfilled. This is, in 
part, due to the small contribution these loads make on the total 
quantity of waste landfilled and, in part, due to the fact that these 
vehicles often have small loads relative to the vehicle weight so the 
direct measurements have greater uncertainty for small loads than they 
do for larger loads.
    When scales are present at the MSW landfill, they must be used, 
(except for passenger vehicles and light duty pick-up trucks). Two 
options for the use of scales are included in this proposal. 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.
    While we originally assumed that scales would be present at all MSW 
landfills, some reporters indicated that this is not the case. After 
careful review of the 2009 Final MRR and its technical record, it 
appears the intended requirement to use scales is not clearly defined 
in the 2009 Final MRR and no details were provided as to how such 
measurements using scales were to be made. Furthermore, the definition 
of ``WX'' in Equation HH-1 stated that ``WX = 
Quantity of waste disposed in the landfill in year x from tipping fee 
receipts or other company records.'' This definition does not suggest a 
need to perform direct mass measurements. This definition was intended 
to allow use of tipping fee receipts or company records for the years 
prior to the first reporting year, but can also be interpreted to allow 
these same records to be used in the reporting year. While 40 CFR 
98.343(a)(3) in the 2009 Final MRR provided methods for ``years prior 
to reporting for which waste disposal quantities are not readily 
available,'' there were no specific instructions for measurement 
methods for waste disposal quantities in the reporting year.
    For the few landfills that do not have scales, the cost of 
installing scales was evaluated. According to one of the commenters, 
the capital cost of installing scales could be as much as $50,000 per 
scale, with operating and driver time resulting in an estimated 
annualized cost of over $23,000. We also considered the uncertainty 
associated with different waste quantity measuring methods and their 
resulting uncertainty in the overall modeled methane generation. 
Relative to the uncertainty of the other model parameters, requiring 
all landfills to have scales for mass measurements would not 
significantly reduce the overall uncertainty in the modeled methane 
generation. Given the significant additional costs for requiring the 
installation of scales at a landfill and the limited improvement in the 
uncertainty of the reported methane emissions, we are proposing to 
allow the use of ``truck counts and capacities'' as an acceptable 
method of determining waste quantity landfilled.
    In addition, we are proposing to redesignate paragraph (a)(3) of 40 
CFR 98.343 to (a)(4) and to amend that paragraph and the sub-paragraphs 
to clarify that measurement data can be used for historical years when 
the data are available. We are proposing to clarify 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 proposing to amend 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,'' to properly account for 
situations when waste quantity data are available for some, but not 
all, historic years. We are proposing to amend 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,'' to enhance the meaning 
of that sentence.
    In related amendments, we are also proposing to amend 40 CFR 
98.344(a) to clarify the requirements for measurement equipment by 
stating 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 proposing to amend 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 
proposed requirements in 40 CFR 98.343(a)(3)(i) and the waste 
quantities determined using vehicle counts and load capacities. We are 
also proposing to amend 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 proposing the following 
technical amendments to Equation HH-2 in 40 CFR 98.343:
     Replace the term ``WGRX'' with 
``WDRX'' and remove the term ``%SWDS'' to simplify the 
equation since both terms were look-up values and the product can be 
expressed as a single value.
     Replace the definition of the term ``WGRX'' 
with ``WDRX = Average per capita waste disposal rate for 
year x from Table HH-2 of this subpart (metric tons per capita per 
year, wet basis; tons/cap/yr),'' for consistency with the revisions of 
Equation HH-2.
     Delete the definition of the term ``%SWDS'' for 
consistency with the revisions of Equation HH-2.
     Delete the word ``of'' from the definition of 
``POPX'' to correct a grammatical error.
    We are proposing the following technical amendments to Equation HH-
3 in 40 CFR 98.343:

[[Page 33959]]

     Replace the term ``WDRX'' with 
``WX'' for consistency with the same term as expressed in 
Equation HH-1.
     Replace the definition of the term ``WDRX'' 
with ``WX = quantity of waste place in the landfill in year 
x (metric tons/wet basis),'' for consistency with the same term as 
expressed in Equation HH-1.
     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),'' for clarity.
    We are proposing the following technical amendments to Equation HH-
4 and the related 40 CFR 98.343(b):
     Amend Equation HH-4 and the terms in that equation to more 
clearly allow for daily averages (365 or 366 per year) from a 
continuous CH4 monitoring system, or from weekly sampling 
(with 52 measurement periods).
     In 40 CFR 98.343(b)(2), delete ``* * * at least weekly * * 
* '' because the measurement frequency is specified in subsequent 
paragraphs.
     In 40 CFR 98.343(b)(2)(ii) and subparagraphs (A) and (B), 
replace ``no less than weekly'' with ``once each calendar week, with at 
least three days between measurements,'' to clarify what is meant by 
weekly sampling.
     In 40 CFR 98.343(c), replace ``Calculate * * * '' with 
``For all landfills, calculate * * * '' to clarify and provide parallel 
sentence structure.
    Moisture Content Measurement. In addition to the other amendments 
to Equation HH-4 discussed above, we are proposing to amend the 
moisture content measurement requirements in Equation HH-4. We intended 
that Equation HH-4 would be calculated on a daily or weekly average 
basis, but it was not properly codified in the 2009 Final MRR to allow 
for weekly measurements. Specifically, the instructions to use N=52 for 
weekly sampling is incorrect given the fixed unit conversion factor for 
minutes per day. To correct this error, we are proposing to revise the 
definition of (V)n to be the cumulative volume for the 
measurement period (rather than the volumetric flow rate), eliminate 
the 1,440 conversion factor for minutes per day, and revise the 
reference to ``day'' in the definition of equation terms with 
``measurement period.''
    We also received numerous questions regarding the moisture 
correction term in Equation HH-4, suggesting that the instructions to 
replace this term with 1 within the definitions of (V)n and 
(C)n were confusing and incomplete.
    We intended that moisture content would be determined, if 
necessary, through measurement data. To address this issue, we are also 
proposing to amend Equation HH-4 to replace the moisture correction 
term, [1-(fH2O)n], with a moisture correction 
factor, KMC. KMC would be 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-(fH2O)n] if 
(V)n is measured on a dry basis and (C)n is 
measured on a wet basis.

    Equation HH-4 in the 2009 Final MRR did not consider the third 
scenario for KMC. While we do not anticipate that this 
scenario of measurements is likely, the proposed amendment is both 
clearer and more technically correct. We similarly propose to amend 40 
CFR 98.343(b)(2)(iii)(B) to clarify that moisture content is needed 
``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, * * 
*''.
    Additionally, we received numerous inquiries about how reporters 
are to measure for moisture content, and asking whether measurements 
were really necessary because no moisture content measurement 
requirements are in 40 CFR 98.344. To clarfiy how and when reporters 
are to measure for moisture content, we are proposing to amend 40 CFR 
98.344(d) and (e) to include reference to moisture content monitors. 
Specifically, we are proposing to amend 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 proposing to amend 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.'' These 
proposed amendments clarify that the moisture content is to be based on 
measurement values and not assumed moisture content values. We do note 
that moisture content calculated from wet and dry bulb temperature 
measurements are a suitable measure of moisture content, but that 
measurement of dry bulb temperature alone, assuming the gas is 
saturated with water (i.e., 100 percent relative humidity) is not a 
direct measure of moisture content, and is not a suitable measurement 
technique.
    In related amendments, we are proposing to amend 40 CFR 
98.346(i)(3) and (4) to clarify the reporting requirements for 
temperature, pressure, and moisture content measurements. Section 
98.346(i)(4) in the 2009 Final MRR pertained to pressure measurements, 
but inadvertently referenced ``* * * or indication that temperature is 
incorporated into internal calculations * * *'' We are proposing to 
amend 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. Together, the 
proposed amendments to Equation HH-4 and 40 CFR 98.344 and 98.346 would 
clarify that moisture content need only be determined when the 
concentration and flow measurements are made on different basis (one 
wet and one dry) and that, if needed, the moisture content must be 
measured.
    ``Active'' and ``Passive'' Gas Collection Systems. We are proposing 
to clarify the difference between ``active'' gas collection systems and 
``passive'' gas collection systems. Some landfills use ``passive'' vent 
flares to control odor. In these ``passive'' systems, landfill gas 
flows naturally to the surface of the landfill where an opening or pipe 
(vent) is installed to allow for natural gas flow. Because of the low 
and variable flow as well as the number of passive vents that are 
present at a single landfill, requiring flow meters for these systems 
is impractical. Furthermore, these systems do not meet the definition 
of gas collection system in 40 CFR 98.6 because the gas is not 
collected to a single location. However, to clarify our intent to only 
require monitoring of ``active'' gas collection systems, we are 
proposing to amend the definition of ``gas collection system'' in 40 
CFR 98.6 as described in Section II.B. of this preamble. However, we 
are interested in understanding the number of landfills with passive 
vent controls, so we are also proposing to add 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 proposing other technical 
corrections for subpart HH to correct typographical errors, to correct 
equations, and to provide minor clarifications.

[[Page 33960]]

    We are proposing the following technical corrections to 40 CFR 
98.344(b):
     Delete the word ``install'' to clarify that the gas 
composition monitors do not need to be installed to meet this 
requirement and to allow use of portable monitoring devices.
     In 40 CFR 98.344(b)(6)(ii), add ``at the routine sampling 
location'' to clarify the 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'' because the sampling location is previously 
specified and to correct spelling error.
     In 40 CFR 98.344(b)(6)(ii)(B), delete ``that is collected 
and routed to a destruction device (before and teatment equipment)'' 
because the sampling location is previously specified.
     In 40 CFR 98.344(b)(6)(ii)(B), add ``for use in Equation 
HH-4'' to the definition of the term CCH4 as follows ``Methane 
concentration in the landfill gas (volume %) for use in Equation HH-
4,'' for clarity.
    In 40 CFR 98.344(c), we are proposing to revise 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.'' The amended language 
would conform with the general provisions for calibration of gas flow 
meters and with other amendments indicating when moisture corrections 
are necessary.
    We are proposing 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),'' to 
clarify the reporting requirement.
     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,'' to comport with revisions of Equation HH-1.
     Revise 40 CFR 98.346(f)(1) 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.'' This change would 
clarify the reporting requirement and clarify that an average oxidation 
fraction does not need to be calculated because the default oxidation 
fraction must be used.
     Add ``for the reporting year'' to 40 CFR 98.346(i)(1) as 
follows: ``Total volumetric flow of landfill gas collected for 
destruction for the reporting year (cubic feet at 520 [deg]R or 60 
[deg]F and 1 atm),'' to clarify the reporting requirement.
     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),'' to clarify the reporting 
requirement.
     In 40 CFR 98.346(i)(7), replace the parenthetical 
``(manufacture, capacity, number of wells, etc.)'' with 
``(manufacturer, capacity, and number of wells)'' to correct the 
typographical error and to eliminate the open-ended reporting 
requirement implied by the etcetera.
    We are also proposing to include additional definitions of terms 
used in the rule to help clarify the rule requirements. The following 
terms are proposed to be defined within 40 CFR 98.348 of subpart HH: 
``destruction device''; ``solid waste''; and ``working capacity.''
    We are proposing to amend Table HH-1 of 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). In these cases, 
reporters would be required to use the highest decay rate values, even 
though the small or infrequent use of recirculation would not 
significantly alter the landfill's moisture content. Instead of an all 
or nothing approach, the proposed amendments require that recirculation 
be calculated in units of inches/year (effectively representing it as 
an ``additional precipitation rate''). The leachate recirculation rate 
would be calculated as the total volume of leachate recirculated during 
the year divided by the area of the portion of the landfill containing 
waste. This leachate recirculation rate (in inches/year) would be added 
to the precipitation rate and the sum would be used to determine what 
decay rate constant is appropriate.
    We are also proposing to amend Table HH-1 to delete the default 
value for LO as the amended Equation HH-1 would no longer 
use that term. Finally, we are proposing to amend Table HH-1 to include 
default values for DOC and k (decay rate) for inert materials because 
this category of waste is needed to properly account for non-degradable 
wastes that are managed in MSW landfills.
    We are proposing to amend Table HH-2 of 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). These revisions are commensurate with the proposed amendments to 
Equation HH-2. Additionally, we identified an inadvertent error in the 
waste generation rates included in Table HH-2 from 1989 to 2006, so we 
are correcting this error with the values for waste disposal rates in 
the proposed amendments to Table HH-2. Finally, we propose to add waste 
disposal rates for 2007, 2008, and 2009 so that Equation HH-2 can be 
used for projecting historical disposal quantities for these years.
    We are proposing to amend Table HH-3 of subpart HH to delete the 
references to the average depth of waste within an area (H2, H3, H4, 
and H5) as these terms are not used in the calculation for landfill gas 
collection efficiency. We also propose to amend Table HH-3 to clarify 
what is considered a ``final soil cover.'' The description for A5 is 
proposed to read, ``Area with a final soil cover of 3 feet or thicker 
of clay and/or geomembrane cover system and active gas collection.'' In 
the 2009 Final MRR, A5 included areas with both a final soil AND a 
geomembrane cover system. The amendment is needed so the definition of 
area A5 matches the types of cover systems for which the efficiency 
value was assessed. The description for A4 is proposed to read, ``Area 
with an intermediate soil cover, or a final soil cover not meeting the 
criteria for A5 below, and active gas collection.'' This revision is 
needed to clarify what is considered an intermediate soil cover and to 
better describe the types of cover systems for which the efficiency 
value of 0.75 applies.

Q. Subpart LL--Suppliers of Coal-Based Liquid Fuels

    We are proposing to amend 40 CFR 98.386(a)(5) and (6) to clarify 
that fossil-fuel products that enter the facility

[[Page 33961]]

would 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.

R. Subpart MM--Suppliers of Petroleum Products

    We are proposing to add 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. We are proposing to define a 
batch of crude oil as up to a calendar month of volume from a single 
country of origin or, if refiners do not know the country of origin, up 
to a total calendar month of volume. Our intention is to allow refiners 
to use sample data on crude oil American Petroleum Institute (API) 
gravity and sulfur content that they or a third party currently collect 
as part of normal business practices, including sample data refiners 
use to report monthly weighted average API gravity and sulfur content 
to EIA.
    To better align the API gravity and sulfur content reporting 
requirements with normal business practices, we are also proposing to 
amend the recordkeeping requirements in 40 CFR 98.397 so that refiners 
would no longer be required to maintain laboratory reports, 
calculations and worksheets used in the measurement of API gravity and 
sulfur content of crude oil as long as they maintain sufficient records 
to support the information they report to EPA (as required by 40 CFR 
98.397(a) and (b)).
    We are also proposing to amend 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. 
We seek comment on our proposed definition of batch in 40 CFR 98.398 
and the associated amendments in subpart MM.
    We also seek comment on any additional changes to the monitoring 
and QA/QC requirements in 40 CFR 98.394, procedures for estimating 
missing data in 40 CFR 98.395, description of reporting requirements in 
40 CFR 98.396(a)(20), or records that must be retained in 40 CFR 98.397 
related to measuring API gravity and sulfur content of crude oil that 
would better align these provisions with normal business practices.
    We also seek comment on defining a batch of crude oil, 
alternatively, as an annual volume of a specific type of crude oil 
where types of crude oil are characterized by EIA crude stream code 
categories \4\ or other parameters (e.g., ranges of API gravity and 
sulfur content, commonly-used industry names) that refiners use to 
differentiate between types of crude oil as part of normal business 
practices. We seek comment on whether this alternative definition would 
decrease burden for reporters compared to our proposed definition or 
provide better data for purposes of understanding upstream emissions 
associated with the production of crude oil and petroleum products. We 
also seek comment on the relative benefits of using EIA's crude stream 
categories, as opposed to other parameters that refiners use in the 
ordinary course of business, to distinguish between different types of 
crude.
---------------------------------------------------------------------------

    \4\ EIA's foreign stream code categories are listed in Appendix 
A of Form EIA-856 available at http://www.eia.doe.gov/pub/oil_gas/
petroleum/survey_forms/eia856appa.pdf. EIA's domestic stream code 
categories are listed in Form EIA-182 available at http://
www.eia.doe.gov/pub/oil_gas/petroleum/survey_forms/eia182f.pdf.
---------------------------------------------------------------------------

    We also seek comment on limiting the crude oil data reporting 
requirements under 40 CFR 98.396(a)(20) to just the annual volume of 
each EIA crude stream code category (i.e., remove requirements to 
report API gravity, sulfur content, and country of origin of each 
batch), given that each category already reflects country of origin and 
the range of API gravity and sulfur content for each category may be 
sufficiently narrow.
    We are proposing to amend 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 proposing to amend 40 CFR 98.396(a)(5) and 
(6) to clarify that these products are not reported.
    We are proposing to amend the procedure in 40 CFR 98.393(f)(1) for 
calculating emission factors for solid products when using Calculation 
Method 1. The amendments would clarify that reporters should multiply 
the default carbon share factor in column B of Table MM-1 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 proposed amendment is necessary because 
otherwise reporters would calculate the emissions of carbon instead of 
carbon dioxide.
    We are proposing to amend 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 proposing to add 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 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 
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. The optional method we are 
proposing today would allow 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. This amendment is being proposed 
in an attempt to increase flexibility for facilities that receive and 
supply blends, especially at refineries with co-located terminals. This 
amendment would also improve accuracy of the summary calculation of 
total refinery CO2 because it would ensure that the same 
quantities and emission factors are used for blend components coming in 
to the refinery as for blended products going out. We are seeking 
comment on the value of adding this new optional method and on whether 
it would be worthwhile to finalize these proposed rule amendments with 
this method included. We are seeking comment on the occasions in which 
reporters would use this method so that we can ensure that we have 
fully accounted for such occasions in the text. Please be specific in 
your comments. We also seek comment on whether the list of products in 
Table MM-1 is comprehensive of all products contained in blends that 
petroleum product suppliers receive or supply. We seek comment on any 
other alternative methods that would allow reporters to calculate 
CO2 emissions for product blends using information already 
collected by industry in the course of

[[Page 33962]]

normal business or as part of compliance with the mandatory reporting 
rule.
    We are proposing that the optional method would not be available 
for a product that is biomass-based because such biomass-based products 
are subject to paragraph (h) of 40 CFR 98.393. We seek comment on 
whether there would be value in expanding the proposed method to 
include biomass-based blends, and if so how the proposed method could 
be amended to allow for biomass-based blends without contradicting or 
jeopardizing the procedures in paragraph (h) of 40 CFR 98.393. Please 
be specific in your comments.
    To align the existing regulatory text with the proposed optional 
method for blends, we are proposing to amend paragraphs (a)(1) and 
(b)(1) of 40 CFR 98.393 and to add paragraph (d) of 40 CFR 98.396 to 
create new data reporting requirements for blends.
    For additional discussion of the current approach to blends in 
subpart MM, please see the response to comment EPA-HQ-OAR-2008-0508-
0712.1, excerpt 94 in Volume 38 of U.S. EPA's Response to Public 
Comments on the Mandatory Greenhouse Gas Reporting Rule: Subpart MM--
Suppliers of Petroleum Products (EPA-HQ-OAR-2008-0508-2254).
    We are proposing to amend the calculation procedures in 40 CFR 
98.393(h) for blended biomass-based fuels. The 2009 Final MRR 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. To 
address this fact for refineries using Calculation Method 1 for 
petroleum products or non-crude petroleum feedstocks that contain 
denatured ethanol, we are proposing to amend the definition of the term 
``%vol'' to exclude denaturant in equations MM-8 and MM-9, 
respectively.
    To address this fact 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 proposing a new equation 
MM-10a. Proposed equation MM-10a would require 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. Equation MM-10 requires reporters to 
subtract the CO2 emissions that would result from the 
biomass portion of the blended product by multiplying the volume of the 
blended product by both the percent volume of the biomass portion 
(which for ethanol would now include the denaturant) and the default 
emission factor. This new equation is necessary because the default 
factor for ethanol does not account for denaturant. Using equation MM-
10 for a blended product containing denatured ethanol would therefore 
result in inaccurate CO2 emissions because the emission 
factors for 100% ethanol and for denaturant are different. We are 
proposing to split 40 CFR 98.393(h)(3) into paragraphs (i) and (ii) so 
that equation MM-10 remains in (i) for petroleum products blended with 
biomass other than denatured ethanol while the proposed equation MM-10a 
appears in (ii) for petroleum products blended with denatured ethanol. 
We are proposing to amend equation MM-10 so that the definition of the 
term ``%vol'' excludes denaturant.
    Together, these proposed amendments would 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 denatured ethanol that enters the refinery as a 
feedstock always leaves the refinery as a product and is never used on 
site. We are seeking comment on this conclusion.
    We cannot identify a situation 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 proposing to split 40 CFR 98.393(h)(4) into 
paragraphs (i) and (ii) so that equation MM-11 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 proposing 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 proposing to amend equation MM-11 so that 
the definition of the term ``%vol'' excludes denaturant. We seek 
comment on our proposal to have refineries, importers, and exporters 
use Calculation Method 1 in these situations and on the assumption that 
no reporter would be adversely impacted by using Calculation Method 1 
in these situations.
    If a refinery, importer, or exporter would be adversely impacted by 
only using Calculation Method 1 in these situations, we seek comment on 
an alternative approach to correcting the issue of accounting for 
denaturant in products but not in denatured ethanol feedstock, that 
would allow all reporters to use Calculation Method 2 for products and 
non-crude feedstocks containing denatured ethanol. One alternative 
approach, which is not included in the proposed regulatory text, would 
be to amend the emission factor for ethanol to reflect a 2.5 percent 
volume of denaturant and directing reporters to use Equations MM-10 and 
MM-11, respectively. We seek comment on this alternative approach.
    We are proposing amendments to 40 CFR 98.396(a)(3), (a)(7), (b)(3), 
and (c)(3) to align the reporting requirements with the proposed 
amendments to account for denaturant in ethanol.
    We are also seeking comment on the value of editing Table MM-1 so 
that refiners must report on quantities of ``fuel gas'' rather than 
``still gas.'' We seek comment on whether this would increase clarity 
or decrease complexity for reporters as they determine how to 
categorize and report gas products received as non-crude feedstock or 
supplied to the economy.

S. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids

    We are proposing to amend the definition of the term 
``Fuelh'' in Equation NN-1 to clarify that the abbreviation 
``Mscf'' refers to ``thousand standard cubic feet'' in order to avoid 
confusion on whether this abbreviation means ``million standard cubic 
feet''. We are also proposing to add the subscript ``h'' to the terms 
for Fuel and HHV in Equation NN-1.
    We are proposing to amend the definition of the term ``EF'' in 
Equation NN-7 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 proposing to amend Equation NN-8 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 proposing to amend Equation NN-8 to remove the summation signs 
that were unnecessary from this equation for clarification purposes. We 
are also proposing to amend the definition of the term CO2i 
to clarify that

[[Page 33963]]

this term includes NGLs delivered to customers or on behalf of 
customers, recognizing that some customers may not receive the NGLs 
directly.
    We are proposing to amend 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 proposing to amend 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 proposing to amend 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 proposing to amend 40 CFR 98.407(a) to remove the word 
``daily'' because daily meter readings are not specifically required 
under this subpart.
    Finally, we are proposing to update the high heat values (HHVs) and 
default CO2 emission factors in Tables NN-1 and NN-2 to be 
consistent with the emission factors in Tables C-1 and MM-1.

V. 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 (EO)12866 (58 FR 51735, October 4, 1993) and 
is therefore not subject to review under the EO.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
These proposed amendments do not make any substantive changes to the 
reporting requirements in any of the subparts for which amendments are 
being proposed. In many cases, the proposed amendments to the reporting 
requirements could potentially reduce the reporting burden by making 
the reporting requirements conform more closely to current industry 
practices. However, the 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. 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 this proposed rule on 
small entities, small entity is defined as: (1) A small business as 
defined by the Small Business Administration's regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of these proposed 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 proposed rule amendments will not impose any new 
requirement on small entities that are not currently required by the 
rules promulgated on October 30, 2009 (i.e., calculating and reporting 
annual GHG emissions).
    EPA took several steps to reduce the impact of the 2009 Final MRR 
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.
    We continue to be interested in the potential impacts of the 
proposed rule amendments on small entities and welcome comments on 
issues related to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    The UMRA seeks to protect State, local, and Tribal governments from 
the imposition of unfunded Federal mandates. In addition, the Act seeks 
to strengthen the partnership between the Federal government and State, 
local, and Tribal governments and ensure that the Federal government 
covers the costs incurred during compliance with Federal mandates.
    Title II of the UMRA of 1995, Public Law 104-4, establishes 
requirements for Federal agencies to assess the effects of their 
regulatory actions on State, local, and tribal governments and the 
private sector. Under section 202 of UMRA, EPA generally must prepare a 
written statement, including a cost-benefit analysis, for proposed and 
final rules with Federal mandates that may result in expenditures to 
State, local, and Tribal governments, in the aggregate, or to the 
private segment, of $100 million or more in any one year.
    Before promulgating an EPA rule for which a written statement is 
needed, section 205 of UMRA generally requires EPA to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of the rule. The provisions of section 205 do 
not apply when they are inconsistent with applicable law. Moreover, 
section 205 allows EPA to adopt an alternative other than the least 
costly, most cost-effective or least burdensome alternative if the 
Administrator publishes with the final rule an explanation why that 
alternative was not adopted.
    Before EPA establishes any regulatory requirements that may 
significantly or uniquely affect small governments, including Tribal 
governments, it must have developed under section 203 of UMRA a small 
government agency plan. The plan must provide for notifying potentially 
affected small governments, enabling officials of affected small 
governments to have meaningful and timely input in the development of 
EPA regulatory proposals with significant Federal intergovernmental 
mandates, and informing, educating, and advising small governments on 
compliance with the regulatory requirements.
    EPA has determined that these proposed rule amendments do not 
contain a Federal mandate that may result in expenditures of $100 
million or more for State, local, and tribal governments, in the 
aggregate, or the private sector in any one year. Thus, the proposed 
rule amendments are not

[[Page 33964]]

subject to the requirements of section 202 and 205 of the UMRA. In 
addition, EPA determined that the proposed 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 the rules promulgated 
on October 30, 2009 (i.e., calculating and reporting annual GHG 
emissions), and the rule amendments would not unfairly apply to small 
governments. Therefore, this action is not subject to the requirements 
of 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 proposed rule amendments would relate to 
existing State programs, please see Section II of the proposal preamble 
for the Mandatory GHG Reporting Rule (74 FR 16457 to 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 would be affected. This regulation also does not 
limit the power of States or localities to collect GHG data and/or 
regulate GHG emissions. Thus, EO 13132 does not apply to this 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 the 2009 
Final MRR. A summary of EPA's consultations with State and local 
governments is provided in Section VIII.E of the preamble to the 2009 
Final MRR (74 FR 56260, October 30, 2009).
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicits comment on this proposed action 
from State and local officials.

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 proposed 
rule amendments would not result in any changes to the requirements of 
the 2009 Final MRR. 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 in 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 EO 13045 (62 FR 19885, April 23, 1997) as applying 
only to those regulatory actions that concern health or safety risks, 
such that the analysis required under section 5-501 of the EO has the 
potential to influence the regulation. This action is not subject to EO 
13045 because it does not establish an environmental standard intended 
to mitigate health or safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This 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 No. 104-113 (15 U.S.C. 272 note) 
directs EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. NTTAA directs EPA to provide 
Congress, through OMB, explanations when the Agency decides not to use 
available and applicable voluntary consensus standards.
    This proposed rulemaking involves the use of one new voluntary 
consensus standard from ASTM. Specifically, EPA proposes to 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 the 2009 Final MRR. This additional 
voluntary concensus 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 proposed rule.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 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 this proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment because it is a rule addressing information collection and 
reporting procedures.

List of Subjects

40 CFR Part 86

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Reporting and recordkeeping requirements, Motor 
vehicle pollution.

40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and 
recordkeeping requirements.

    Dated: May 27, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons set out in the preamble, title 40, Chapter I, of 
the Code

[[Page 33965]]

of Federal Regulations is proposed to be amended as follows:

PART 86--[AMENDED]

    1. The authority citation for part 86 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

    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 aftertreatment 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]

    3. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

Subpart A--[Amended]

    4. Section 98.6 is amended by:
    a. Removing the definition of ``Argon-oxygen decarburization (AOD) 
vessel.''
    b. Adding a definition for ``Decarburization vessel.''
    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.''

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), and potassium carbonate 
(K2CO3).
    Carbonate-based mineral mass fraction means the following: for 
limestone, the mass fraction of CaCO3 in the limestone; for 
dolomite, the mass fraction of CaMg(CO3)2 in the 
dolomite; for soda ash, the mass fraction of 
Na2CO3 in the soda ash; for barium carbonate, the 
mass fraction of BaCO3 in the barium carbonate; and for 
potassium carbonate, the mass fraction of K2CO3 
in the potassium carbonate.
    Carbonate-based raw material means any of the following materials 
used in the manufacture of glass: limestone, dolomite, soda ash, barium 
carbonate, and potassium 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. Depending upon the characteristics of the crude stream, it 
may also include any of the following:
    (1) Small amounts of hydrocarbons that exist in gaseous phase in 
natural underground reservoirs but are liquid at atmospheric pressure 
after being recovered from oil well (casinghead) 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.
    (2) Small amounts of nonhydrocarbons produced from oil, such as 
sulfur and various metals.
    (3) Drip gases, and liquid hydrocarbons produced from tar sands, 
oil sands, gilsonite, and oil shale. 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 to reduce the carbon content of the steel. This definition 
includes vessels used for argon-oxygen decarburization, vacuum 
degassers, vacuum oxygen degassers, Rheinstahl-Heraus systems, and 
other decarburization vessels.
* * * * *
    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. 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, including supplemental fuel burned to provide heat or thermal 
energy.
* * * * *
    5. Section 98.7 is amended by revising paragraph (a)(1) and by 
adding paragraph (e)(43) to read as follows:

Sec.  98.7   What standardized methods are incorporated by reference 
into this part?

* * * * *
    (a) * * *
    (1) Association of Fertilizer and Phosphate Chemists Analytical 
Methods Manual 10th Edition, incorporation by reference (IBR) approved 
for Sec.  98.264(a) and Sec.  98.264(b).
* * * * *
    (e) * * *
    (43) 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.

Subpart E--[Amended]

    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 (a)(2) of this 
section.
    (1) Use a site-specific emission factor and production data 
according to paragraphs (b) through (h) of this section.

[[Page 33966]]

    (2) Request Administrator approval for an alternative method of 
determining N2O emissions according to paragraphs (a)(2)(i) 
and (a)(2)(ii) of this section.
    (i) You must submit the request within 45 days following 
promulgation of this subpart or within the first 30 days of each 
subsequent reporting year.
    (ii) If the Administrator does not approve your requested 
alternative method within 150 days of the end of the reporting year, 
you must determine the N2O emissions 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 (b)(3) of this section.
    (1) You must conduct the test on the waste gas stream from the 
nitric acid oxidation step of the process, referred to as the test 
point, according to the methods specified in Sec.  98.54(b) through 
(f).
    (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] TP15JN10.001

Where:

EFN2O,N = Average facility-specific N2O 
emission factor for each adipic acid production unit (lb 
N2O generated/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).
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), (d)(2), or (d)(3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an 
additional performance test on the emissions stream following the 
N2O abatement technology.
    (e) If 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] TP15JN10.002

Where:

AFN = Abatement utilization factor of N2O 
abatement technology ``N'' (fraction of annual production that 
abatement technology is operating).
Pa,N = Annual adipic acid production during which 
N2O abatement technology ``N'' was used (ton adipic acid 
produced).

Pa = Total annual adipic acid production (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) or (g)(2) of this section for each adipic acid 
production unit and sum the unit level emissions to determine the 
emissions for the facility.
    (1) If any 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] TP15JN10.003

Where:

N2O = Annual N2O mass emissions from adipic 
acid production (metric tons).
EFN2ON = N2O emissions factor for 
unit(s) on which N2O abatement technology ``N'' is 
operating (lb N2O generated/ton adipic acid produced).
PaN = Annual adipic acid produced by unit(s) for which 
N2O abatement technology ``N'' is operating (tons).
DFN = Destruction efficiency of N2O abatement 
technology ``N'' (percent of N2O removed from air 
stream).
AFN = Abatement utilization factor of N2O 
abatement technology ``N'' (fraction of annual production for which 
N2O abatement technology ``N'' is operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (2) 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-
3b of this section for each adipic acid production unit.

 [GRAPHIC] [TIFF OMITTED] TP15JN10.004

Where:

N2O = Annual N2O mass emissions from adipic 
acid production (metric tons).

[[Page 33967]]

EFN2O = N2O emissions factor (lb 
N2O generated/ton adipic acid produced).
Pa = Annual adipic acid produced (tons).
2205 = Conversion factor (lb/metric ton).

    (h) 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.
    7. Section 98.54 is amended by:
    a. Revising paragraph (a) introductory text.
    b. Adding second and third sentences to paragraph (a)(1).
    c. Revising paragraph (a)(3).
    d. Revising paragraph (c) introductory text.
    e. Revising the first sentence of paragraph (d) introductory text.
    f. Revising paragraphs (e) and (f).

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 (a)(3) of this 
section.
    (1) * * * The test must be conducted at a point during production 
that is representative of the average emissions 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 
and the monthly amount of adipic acid produced during which 
N2O abatement technology, located after the test point, is 
operating according to the methods in paragraphs (c)(1) or (c)(2) of 
this section.
    (f) You must determine the annual amount of adipic acid produced 
and the annual amount of adipic produced during which N2O 
abatement technology located after the test point is operating by 
summing the respective monthly adipic acid production quantities 
determined in paragraph (e) of this section.
    8. Section 98.56 is amended by:
    a. Revising paragraph (c).
    b. Revising paragraph (j) introductory text.
    c. Revising paragraph (j)(1).
    d. Revising paragraph (k) introductory text.

Sec.  98.56  Data reporting requirements.

* * * * *
    (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 (j)(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 (k)(4) of this section for each adipic acid 
production facility.
* * * * *
    9. Section 98.57 is amended by:
    a. Revising paragraph (c).
    b. Revising paragraph (f).

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]

    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.
* * * * *
    11. Section 98.84 is amended by revising paragraphs (b), (c), (d), 
and (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

[[Page 33968]]

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.
* * * * *
    (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.
* * * * *
    12. Section 98.86 is amended by revising paragraphs (b)(12) and 
(b)(13); and by adding paragraph (b)(15) to read as follows:

Sec.  98.86  Data reporting requirements.

    (b) * * *
    (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 amended by:
    a. Revising paragraph (a) introductory text.
    b. Removing and reserving paragraphs (a)(1) and (a)(2).
    c. Adding paragraphs (b)(1), (b)(2), and (b)(3).

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) * * *
    (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]

    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 of this section.
* * * * *
    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 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.
* * * * *
    16. Section 98.116 is amended by revising paragraphs (b), (c), (d) 
introductory text, (d)(1), and (e)(1) to 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]

    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 conducted by a certified laboratory 
using ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major 
and Minor Elements in Combustion Residues from Coal Utilization 
Processes (incorporated by reference, see 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).
* * * * *
    18. Section 98.146 is amended by revising paragraphs (a) 
introductory text, (a)(2), (b)(7), and (b)(9) to 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 (a)(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).
    19. Table N-1 to subpart N is amended by adding entries for 
``Barium carbonate'' and ``Potassium carbonate'' to read as follows:

  Table N-1--To Subpart N--CO2 Emission Factors for Carbonate-Based Raw
                                Materials
------------------------------------------------------------------------
                                                                  CO2
            Carbonate-Based raw material--mineral               emission
                                                               factor\a\
------------------------------------------------------------------------

                                * * * * *
Barium carbonate--BaCO3......................................      0.223

[[Page 33969]]

Potassium carbonate--K2CO3...................................     0.318
------------------------------------------------------------------------
\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]

    20. Section 98.154 is amended by revising the first and second 
sentences of paragraph (k), revising the second sentence of paragraph 
(l) introductory text, and revising paragraph (o) to 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 
and/or destruction device manufacturer specifications.
* * * * *
    21. Section 98.156 is amended by revising paragraphs (b)(1), 
(b)(3), (c), and (d); and revising paragraph (e) introductory text to 
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:
* * * * *
    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]

    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.
    24. Section 98.162 is amended by revising paragraph (a); and by 
removing and reserving paragraph (b) to read as follows:

Sec.  98.162  GHGs to report.

* * * * *
    (a) CO2 emissions from each hydrogen production process 
unit.
* * * * *
    25. Section 98.163 is amended by:
    a. Revising the introductory text.
    b. Revising paragraph (a) and paragraph (b) introductory text.
    c. In paragraph (b)(1), revising the only sentence, and revising 
the definition of ``CO2'' in Equation P-1.
    d. Revising the only sentence of paragraphs (b)(2) and (b)(3).

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 Montoring 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:
* * * * *
    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

[[Page 33970]]

in paragraphs (a) or (b) of this section, as appropriate, and (c) and 
(d):
    (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]

    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 of 
subpart C in Equations Y-2 and Y-3 of subpart Y of this part. 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 of subpart 
C of this part.
    (c) You must report process CO2 emissions from each 
taconite indurating 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.
    28. Section 98.173 is amended by:
    a. Revising the first sentence of the introductory text.
    b. In paragraph (b)(1)(vi), revising the introductory text and the 
definition of ``CO2'' in Equation Q-6.
    c. Revising the first sentence of paragraph (d).

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.* 
* *
    29. Section 98.174 is amended by revising 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.
* * * * *
    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.
* * * * *
    31. Section 98.176 is amended by revising the introductory text and 
paragraphs (c) and (e)(3); and by adding paragraphs (g) and (h) to 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:
* * * * *
    (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.
    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]

    33. Section 98.190 is amended by revising paragraph (a) to read as 
follows:

[[Page 33971]]

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).
* * * * *
    34. Section 98.193 is amended by:
    a. In paragraph (b)(2)(i), revising the second sentence and the 
definition of ``2000/2205'' in Equation S-1.
    b. In paragraph (b)(2)(ii), revising the only sentence and the 
definitions of ``EFLKD,i,n'', ``CaOLKD,i,n'', 
``MgOLKD,i,n'', and ``2000/2205'' in Equation S-2.
    c. In paragraph (b)(2)(iii), revising the only sentence and the 
definitions of ``Ewaste,i'', ``CaOwaste,i'', 
``MgOwaste,i'', ``Mwaste,i'', and ``2000/2205'' 
in Equation S-3.
    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.

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.

* * * * *
    35. Section 98.194 is amended by:
    a. Revising the first sentence of paragraph (a).
    b. Revising paragraph (c) introductory text.
    c. Revising paragraph (d).

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 (c)(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.
* * * * *
    36. Section 98.195 is amended by revising the first sentence of the 
introductory text; and by revising 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.
* * * * *
    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 
(a)(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).

[[Page 33972]]

    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in paragraphs (b)(1) through 
(b)(17) of this section.
    (1) Annual CO2 process emissions from all kilns combined 
(metric tons).
    (2) Monthly emission factors for each lime type 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.
    (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 (b)(17)(ii) of this 
section.
    (i) The annual amount of CO2 captured for use in the on-
site process.
    (ii) The method used to determine the amount of CO2 
captured.

Subpart V--[Amended]

    38. Section 98.223 is amended by:
    a. Revising paragraphs (a)(1), (a)(2)(ii), (b) introductory text, 
(b)(1), (b)(2), (c), (d) introductory text, and (e).
    b. Removing and reserving paragraph (f).
    c. Revising paragraph (g).
    d. Adding paragraph (i).

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 (b)(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).
    (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] TP15JN10.005

Where:

EFN2Ot = Average site-specific N2O emissions 
factor for nitric acid train ``t'' (lb N2O generated/ton 
nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration for each test run 
during the performance test (ppm N2O).
1.14 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] TP15JN10.006

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).
Pa t = 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).

    (f) [Reserved]
    (g) You must calculate N2O emissions for each nitric 
acid train ``t'' according to paragraph (g)(1) or (g)(2) of this 
section.
    (1) If nitric acid train ``t'' exhausts to any 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 33973]]

[GRAPHIC] [TIFF OMITTED] TP15JN10.007

Where:

EN2Ot = N2O mass emissions per year for nitric 
acid train ``t'' (metric tons).
EFN2Ot = Average site-specific N2O emissions 
factor for nitric acid train ''t'' (lb N2O generated/ton 
acid produced, 100 percent acid basis).
Pa t = Annual nitric acid production from the train ``t'' 
(ton acid produced, 100 percent acid basis).
DFt,N = Destruction efficiency of N2O 
abatement technology N that is used on nitric acid train ``t'' 
(percent of N2O removed from air stream).
AFt,N = Abatement utilization factor of N2O 
abatement technology ``N'' for nitric acid train ``t'' (fraction of 
annual production that N2O abatement technology is 
operating).
2204.63 = Conversion factor (lb/metric ton).
z = Number of N2O abatement technologies on nitric acid 
train ``t''.

    (2) 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] TP15JN10.008

Where:

EN2Ot = N2O mass emissions per year for nitric 
acid train ``t'' (metric tons).
EFN2Ot = Average site-specific N2O emissions 
factor for nitric acid train ''t'' (lb N2O generated/ton 
acid produced, 100 percent acid basis).
Pa, t = Annual nitric acid production from 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).
    39. Section 98.224 is amended by:
    a. Revising paragraph (a).
    b. Revising the first sentence in paragraph (d) introductory text.
    c. Revising paragraphs (e) and (f).

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 (a)(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 over the entire campaign. Facilities must document 
the methods used to determine the representative 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 and the monthly amount of nitric acid produced while 
N2O abatement technology (located after the test point) is 
operating from each nitric acid train according to the methods in 
paragraphs (c)(1) or (c)(2) of this section.
    (f) You must determine the annual amount of nitric acid produced 
and the annual amount of nitric acid produced while N2O 
abatement technology (located after the test point) is operating for 
each train by summing the respective monthly nitric acid quantities 
determined in paragraph (e) of this section.
    40. Section 98.226 is amended by revising the introductory text, 
paragraph (g), and paragraphs (m) and (n) introductory text to 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 (o) 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 (m)(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 (n)(4) of this section for each 
nitric acid production facility.
* * * * *

Subpart Z--[Amended]

    41. Section 98.264 is amended by revising paragraphs (a) and (b) to 
read as follows:

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. Conduct the representative bulk sampling using the 
appropriate industry consensus standard or applicable standard method 
in the Association of Fertilizer and Phosphate Chemists Analytical 
Methods Manual 10th Edition (incorporated by reference, see Sec.  
98.7). If phosphate rock is obtained from more than one origin in a 
month, you must obtain a sample from each origin of rock or obtain a 
composite representative sample.
    (b) You must determine the inorganic carbon content of each monthly 
grab sample of phosphate rock (consumed in the production of phosphoric 
acid) using the applicable standard method in the Association of 
Fertilizer and Phosphate Chemists Analytical Methods Manual 10th 
Edition (incorporated by reference, see Sec.  98.7).
* * * * *
    42. Section 98.265 is amended by revising the second sentence of 
paragraph (a) to read as follows:

Sec.  98.265  Procedures for estimating missing data.

* * * * *
    (a) * * * Alternatively, you must determine substitute data value 
by calculating the arithmetic average of the quality-assured values of 
inorganic carbon contents of phosphate rock of origin i from samples 
immediately

[[Page 33974]]

preceding and immediately following the missing data incident. * * *
* * * * *
    43. Section 98.266 is amended by revising the introductory text, 
paragraph (c), and paragraph (f) introductory text; and by adding 
paragraph (f)(9) to 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 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 (f)(9) of this 
section.
* * * * *
    (9) Annual process CO2 emissions from phosphoric acid 
production facility (metric tons).

Subpart CC--[Amended]

    44. 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.* * *
* * * * *
    45. Section 98.296 is amended by revising paragraphs (a)(1), 
(b)(3), (b)(6), and (b)(10); and by removing paragraphs (11)(iv) 
through (11)(vi) to 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]

    46. 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.
* * * * *
    47. 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).
* * * * *

Subpart GG--[Amended]

    48. 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).

* * * * *
    49. 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]

    50. 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, dedicated construction and demolition waste 
landfills, or industrial waste landfills.
* * * * *
    51. Section 98.343 is amended by:
    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.
    b. Revising the last sentence of paragraph (a)(2).
    c. Redesignating paragraph (a)(3) as (a)(4) and revising new 
paragraph (a)(4).
    d. Adding a new paragraph (a)(3).
    e. Revising paragraph (b)(1), and revising paragraph (b)(2) 
introductory text.

[[Page 33975]]

    f. Revising paragraphs (b)(2)(ii), (b)(2)(iii)(A), and 
(b)(2)(iii)(B); and revising paragraph (c) introductory text.

Sec.  98.343  Calculating GHG emissions.

    (a) * * *
    (1) * * * 
    [GRAPHIC] [TIFF OMITTED] TP15JN10.009
    
* * * * *
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
* * * * *
    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 of 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 of this 
subpart for the total quantity of waste disposed in those years.
    (3) Beginning in the first emissions monitoring year (2010 or 
later) 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, other than 
passenger cars or light duty pickup trucks, used to haul waste to the 
landfill. 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. 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 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 monitoring 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 generation, and 
fraction of generated waste disposed of in solid waste disposal sites 
found in Table HH-2 of this subpart, and calculate the waste quantity 
landfilled using Equation HH-2 of this section. 
[GRAPHIC] [TIFF OMITTED] TP15JN10.010

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 of 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] TP15JN10.011

[[Page 33976]]

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] TP15JN10.012

Where:
R = Annual quantity of recovered CH4 (metric tons 
CH4).
N = Total number of measurement periods in a year. Use daily 
averaging periods for continuous monitoring system 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/cf at 520 [deg] R or 60[deg] F 
and 1 atm.
(T)n = Temperature at which flow is measured for the 
measu rement period ([deg] R).
(P)n = 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 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 once each calendar week, with 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 once each calendar week, with 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 once each calendar week, with 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.
* * * * *
    52. Section 98.344 is amended by:
    a. Revising paragraph (a).
    b. Revising the first sentence of paragraph (b).
    c. Revising paragraphs (b)(6)(ii), (b)(6)(ii)(A), and 
(b)(6)(ii)(B).
    d. Revising the definition of ``CCH4'' in Equation HH-9 
of paragraph (b)(6)(iii).
    e. Revising the second and third sentences of paragraph (c).
    f. Revising paragraph (d).
    g. Amending paragraph (e) by revising the first sentence.

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

[[Page 33977]]

collection of a subsequent grab sample, determine the total gaseous 
organic concentration of the landfilll 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.
* * * * *
    (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. * * *
    53. Section 98.346 is amended by revising paragraphs (a), (b), 
(d)(1), (f), (h), (i)(1), (i)(2), (i)(3), (i)(4), (i)(5), and (i)(7) to 
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.
* * * * *
    (d) * * *
    (1) Degradable organic carbon (DOC), methane correction factor 
(MCF), and fraction of DOC dissimilated (DOCF) values used 
in the calculations.
* * * * *
    (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 [deg]F 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, 
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 of 
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.
* * * * *
    54. Section 98.347 is amended by adding a second sentence to the 
introductory text 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.
    55. 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.
    Dedicated construction and demolition landfill means a landfill 
that only receives materials generated from the construction or 
destruction of structures such as buildings, roads, and bridges.
    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 
40 CFR 257.2), commercial solid wastes, or conditionally exempt small 
quantity generator wastes, is placed. An

[[Page 33978]]

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.
    56. Table HH-1 to subpart HH is amended by:
    a. Revising the entries for ``k (precipitation <20 inches/year and 
no leachate recirculation),'' ``k (precipitation 20-40 inches/year and 
no leachate recirculation),'' and ``k (precipitation >40 inches/year or 
for landfill areas with leachate recirculation).''
    b. Adding an entry for ``DOC (bulk waste)'' to follow the revised 
entry for ``k (precipitation plus recirculated leachate\a\ >40 inches/
year).''
    c. Removing the entry for ``L0 (Equivalent to DOC = 
0.2028 when MCF = 1, DOCF = 0.5, and F = 0.5).''
    d. Adding an entry for ``DOC (inerts, e.g. glass, plastics, metal, 
cement)'' to follow the entry for ``DOC (sewage sludge).''
    e. Revising the entries for ``k (food waste),'' ``k (garden),'' ``k 
(paper),'' ``k (wood and straw),'' ``k (textiles),'' ``k (diapers),'' 
and ``k (sewage sludge).''
    f. Adding a new entry for ``k (inerts e.g. glass, plastics, metal, 
cement).''
    g. Redesignating footnote ``a'' as footnote ``b,'' and revising new 
footnote ``b.''
    h. Adding a new footnote ``a.''

                   Table HH-1 to Subpart HH--Emissions Factors, Oxidation Factors and Methods
----------------------------------------------------------------------------------------------------------------
                  Factor                                Default value                           Units
----------------------------------------------------------------------------------------------------------------
                                         Waste Model--Bulk Waste Option
----------------------------------------------------------------------------------------------------------------
k (precipitation plus recirculated         0.02...................................  yr-1.
 leachate \a\ <20 inches/year).
k (precipitation plus recirculated         0.038..................................  yr-1.
 leachate \a\ 20-40 inches/year).
k (precipitation plus recirculated         0.057..................................  yr-1.
 leachate \a\ >40 inches/year).
DOC (bulk waste).........................  0.20...................................  Weight fraction, wet basis.

                                                  * * * * * * *
DOC (inerts, e.g. glass, plastics, metal,  0.00...................................  Weight fraction, wet basis.
 cement).

                                                  * * * * * * *
k (food waste)...........................  \b\ 0.06 to 0.185......................  yr-1.
k (garden)...............................  \b\ 0.05 to 0.10.......................  yr-1.
k (paper)................................  \b\ 0.04 to 0.06.......................  yr-1.
k (wood and straw).......................  \b\ 0.02 to 0.03.......................  yr-1.
k (textiles).............................  \b\ 0.04 to 0.06.......................  yr-1.
k (diapers)..............................  \b\ 0.05 to 0.10.......................  yr-1.
k (sewage sludge)........................  \b\ 0.06 to 0.185......................  yr-1.
k (inerts e.g. glass, plastics, metal,     \b\ 0.00...............................  yr-1.
 cement).

                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of leachate recirculated divided by the area of
  the portion of the landfill containing waste with appropriate unit conversions.
\b\ 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.

    57. Table HH-2 to subpart HH is amended by:
    a. Removing the entries for ``1950'' through ``1959.''
    b. Revising the entries for ``1989'' through ``2006.''
    c. Adding entries for ``2007'' through ``2009.''

     Table HH-2 to Subpart HH--U.S. Per Capita Waste Disposal Rates
------------------------------------------------------------------------
                Year                     Waste per 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
------------------------------------------------------------------------

    58. 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 
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:

[[Page 33979]]

     Table HH-3 to Subpart HH--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        CE3: 60%.
 active gas collection.
A4: Area with an intermediate soil        CE4: 75%.
 cover, or a final soil cover not
 meeting the criteria for A5 below, and
 active gas collection.
A5: Area with a final soil cover of 3     CE5: 95%.
 feet or thicker of clay and/or
 geomembrane cover system and active gas
 collection.

                              * * * * * * *
------------------------------------------------------------------------

Subpart LL--[Amended]

    59. Section 98.386 is amended by adding a third sentence to 
paragraphs (a)(5) and (a)(6) to read as follows:

Sec.  98.386  Data reporting requirements.

* * * * *
    (a) * * *
    (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.
* * * * *

Subpart MM--[Amended]

    60. Section 98.393 is amended by:
    a. In paragraph (a)(1), revising the only sentence and the 
definition of ``Producti'' in Equation MM-1.
    b. Revising the definition of ``Producti'' in Equation 
MM-2 of paragraphs (a)(2).
    c. Revising the only sentence of paragraph (b)(1) and the first 
sentence in paragraph (f)(1).
    d. Revising the definition of ``%Voli'' in Equation MM-8 
in paragraph (h)(1).
    e. Revising Equation MM-9 and the definition of 
``%Volj'' in paragraph (h)(2).
    f. Revising paragraphs (h)(3) and (h)(4).
    g. Adding paragraph (i).

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 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 of this subpart.
* * * * *
    (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 of 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] TP15JN10.013
    
* * * * *
%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 Methodology 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] TP15JN10.014

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 of this subpart that most closely represents the component of 
product ``i'' that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is 
biomass-based,

[[Page 33980]]

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); 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] TP15JN10.015

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] TP15JN10.016

Where:

    CO2j = (Feedstockj * EFj)-
(Feedstockj * EFm * %Volm) (Eq. MM-
11)
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 of this subpart that most closely represents the component of 
petroleum product ``j'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that 
is biomass-based, 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 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.
    (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] TP15JN10.017

Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of a blended product ''i'' 
(metric tons).
Blending Componenti[hellip]n = Annual volume or mass of 
each blending component that is blended (barrels or metric tons).
EFi[hellip]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] TP15JN10.018

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 = CO 2 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.
    61. Section 98.394 is amended by revising paragraphs (d)(1), 
(d)(3), and (d)(4) to read as follows:

[[Page 33981]]

Sec.  98.394   Monitoring and QA/QC requirements.

    (d) * * *
    (1) A representative sample or multiple representative samples of 
each batch of crude oil shall be taken according to an appropriate 
standard method published by a consensus-based standards organization.
* * * * *
    (3) API gravity shall be measured using an appropriate standard 
method published by a consensus-based standards organization. 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 using an appropriate standard 
method published by a consensus-based standards organization. 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.
* * * * *
    62. Section 98.396 is amended by:
    a. Revising paragraph (a)(3).
    b. Amending paragraphs (a)(5) and (a)(6) by adding a third 
sentence.
    c. Revising paragraphs (a)(7), (a)(20)(ii), (a)(20)(iii), (b)(3), 
and (c)(3).
    d. Adding a new 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 (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).
* * * * *
    (20) * * *
    (ii) Weighted average API gravity of the batch at the point of 
entry at the refinery.
    (iii) Weighted average sulfur content of the batch at the point of 
entry at the refinery.
* * * * *
    (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.
    (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.

Sec.  98.397  [Amended]

    63. Section 98.397 is amended by removing paragaph (e); and by 
redesignating paragraphs (f) and (g) as (e) and (f), respectively.
    64. 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 up to a calendar month of crude oil volume from a 
single country of origin or up to a calendar month of crude oil volume 
for which the country of origin is unknown.

Subpart NN--[Amended]

    65. Section 98.403 is amended by:
    a. Revising the definitions of ``Fuel'' and ``HHV'' in Equation NN-
1 of paragraph (a)(1).
    b. Revising the definition of ``Fuel'' in Equation NN-2 of 
paragraph (a)(2).
    c. Revising the definition of ``Fuel1'' in Equation NN-5 
of paragraph (b)(3).
    d. Revising the definition of ``EF'' in Equation NN-7 of paragraph 
(c)(1).
    e. In paragraph (c)(2), revising Equation NN-8 and the definition 
of ``CO2i'' in Equation NN-8.

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] TP15JN10.019
    
* * * * *

[[Page 33982]]

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).

* * * * *
    66. 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:
* * * * *
    67. 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).
* * * * *
    68. Tables NN-1 and NN-2 to Subpart NN are amended to read as 
follows:

 Table NN-1 to Subpart NN--Default Factors for Calculation Methodology 1
                             of This Subpart
------------------------------------------------------------------------
                                 Default high
             Fuel                heating value     Default CO2 emission
                                    factor        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 of Subpart NN--Lookup Default Values for Calculation
                      Methodology 2 of This Subpart
------------------------------------------------------------------------
                                                   Default CO2 emission
             Fuel                    Unit          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. 2010-13361 Filed 6-14-10; 8:45 am]
BILLING CODE 6560-50-P