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[Federal Register: August 11, 2010 (Volume 75, Number 154)]
[Proposed Rules]               
[Page 48743-48814]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr11au10-29]                         

[[Page 48743]]

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Part II

Environmental Protection Agency

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40 CFR Part 98

Mandatory Reporting of Greenhouse Gases; Proposed Rule

[[Page 48744]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2008-0508; FRL-9179-8]
RIN 2060-AQ33

 
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 GHG 
reporting rule to clarify certain provisions, to correct technical and 
editorial errors, and to address certain questions and issues that have 
arisen since promulgation. These proposed changes include providing 
additional information and clarity on existing requirements, allowing 
greater flexibility or simplified calculation methods for certain 
sources in a facility, amending data reporting requirements to provide 
additional clarity on when different types of GHG emissions need to be 
calculated and reported, clarifying terms and definitions in certain 
equations, and technical corrections.

DATES: Comments. Comments must be received on or before September 27, 
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 FOR FURTHER INFORMATION CONTACT section by August 18, 
2010. If requested, the hearing will be conducted August 26, 2010, at 
1310 L St., NW., Washington, DC 20005 starting at 9 a.m., local time. 
EPA will provide further information about the hearing on its Web page 
if a hearing is requested.

ADDRESSES: You may submit your comments, identified by docket ID No. 
EPA-HQ-OAR-2008-0508 by any of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: MRR_Revisions@epa.gov. Include docket ID No. EPA-
HQ-OAR-2008-0508 [and/or RIN number 2060-aq33] 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. EPA-HQ-OAR-2008-0508, 
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-
2008-0508, Revision of Certain GHGMRR Provisions and Other Corrections. 
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 GENERAL INFORMATION CONTACT: Carole Cook, Climate Change 
Division, Office of Atmospheric Programs (MC-6207J), Environmental 
Protection Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; 
telephone number: (202) 343-9263; fax number: (202) 343-2342; e-mail 
address: GHGReportingRule@epa.gov. For technical information 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 and industrial gas suppliers, and direct emitters of GHGs. 
Regulated categories and entities include those listed in Table 1 of 
this preamble:

[[Page 48745]]

                               Table 1--Examples of Affected Entities by Category
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                  Category                           NAICS                Examples of affected facilities
----------------------------------------------------------------------------------------------------------------
General Stationary Fuel Combustion Sources..  ..................  Facilities operating boilers, process heaters,
                                                                   incinerators, turbines, and internal
                                                                   combustion engines.
                                                             211  Extractors of crude petroleum and natural gas.
                                                             321  Manufacturers of lumber and wood products.
                                                             322  Pulp and paper mills.
                                                             325  Chemical manufacturers.
                                                             324  Petroleum refineries and manufacturers of coal
                                                                   products.
                                                   316, 326, 339  Manufacturers of rubber and miscellaneous
                                                                   plastic products.
                                                             331  Steel works, blast furnaces.
                                                             332  Electroplating, plating, polishing, anodizing,
                                                                   and coloring.
                                                             336  Manufacturers of motor vehicle parts and
                                                                   accessories.
                                                             221  Electric, gas, and sanitary services.
                                                             622  Health services.
                                                             611  Educational services.
Electricity Generation......................              221112  Fossil-fuel fired electric generating units,
                                                                   including units owned by Federal and
                                                                   municipal governments and units located in
                                                                   Indian Country.
Adipic Acid Production......................              325199  Adipic acid manufacturing facilities.
Aluminum Production.........................              331312  Primary aluminum production facilities.
Ammonia Manufacturing.......................              325311  Anhydrous and aqueous ammonia production
                                                                   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 production facilities.
Iron and Steel Production...................              331111  Integrated iron and steel mills, steel
                                                                   companies, sinter plants, blast furnaces,
                                                                   basic oxygen process furnace shops.
Lead Production.............................              331419  Primary lead smelting and refining facilities.
                                                          331492  Secondary lead smelting and refining
                                                                   facilities.
Lime Production.............................              327410  Calcium oxide, calcium hydroxide, dolomitic
                                                                   hydrates manufacturing facilities.
Iron and Steel Production...................              331111  Integrated iron and steel mills, steel
                                                                   companies, sinter plants, blast furnaces,
                                                                   basic oxygen process furnace shops.
Lead Production.............................              331419  Primary lead smelting and refining facilities.
Nitric Acid Production......................              325311  Nitric acid production facilities.
Petrochemical Production....................               32511  Ethylene dichloride production facilities.
                                                          325199  Acrylonitrile, ethylene oxide, methanol
                                                                   production facilities.
                                                          325110  Ethylene production facilities.
                                                          325182  Carbon black production facilities.
Petroleum Refineries........................              324110  Petroleum refineries.
Phosphoric Acid Production..................              325312  Phosphoric acid manufacturing facilities.
Pulp and Paper Manufacturing................              322110  Pulp mills.
                                                          322121  Paper mills.
                                                          322130  Paperboard mills.
Silicon Carbide Production..................              327910  Silicon carbide abrasives manufacturing
                                                                   facilities.
Soda Ash Manufacturing......................              325181  Alkalies and chlorine manufacturing
                                                                   facilities.
                                                          212391  Soda ash, natural, mining and/or
                                                                   beneficiation.
Titanium Dioxide Production.................              325188  Titanium dioxide manufacturing facilities.
Zinc Production.............................              331419  Primary zinc refining facilities.
                                                          331492  Zinc dust reclaiming facilities, recovering
                                                                   from scrap and/or alloying purchased metals.
Municipal Solid Waste Landfills.............              562212  Solid waste landfills.
                                                          221320  Sewage treatment facilities.
Manure Management\1\........................              112111  Beef cattle feedlots.
                                                          112120  Dairy cattle and milk production facilities.
                                                          112210  Hog and pig farms.
                                                          112310  Chicken egg production facilities.
                                                          112330  Turkey Production.
                                                          112320  Broilers and other meat type chicken
                                                                   production.
Suppliers of Natural Gas and NGLs...........              221210  Natural gas distribution facilities.
                                                          211112  Natural gas liquid extraction facilities.
Suppliers of Industrial GHGs................              325120  Industrial gas production facilities.
Suppliers of Carbon Dioxide (CO2)...........              325120  Industrial gas production facilities.
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\1\ EPA will not be implementing subpart JJ of Part 98 using funds provided in its FY2010 appropriations due to
  a Congressional restriction prohibiting the expenditure of funds for this purpose.

[[Page 48746]]

    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 potentially be 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 and industrial 
gas suppliers, and direct emitters of GHGs. 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.

ACC American Chemistry Council
AGA American Gas Association
API American Petroleum Institute
ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BAMM best available monitoring method
Btu/scf British thermal unit per standard cubic foot
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CBI confidential business information
cc cubic centimeters
CE calibration error
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CGA Cylinder gas audit
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
CO2e CO2-equivalent
CWPB center worked prebake
EGU electricity generating unit
EIA Energy Information Administration
EO Executive Order
EPA U.S. Environmental Protection Agency
ERC Energy Recovery Council
FGD flue gas desulfurization
FR Federal Register
FTIR fourier transform infrared
GC gas chromatography
GHG greenhouse gas
GPA Gas Processors Association
GWP global warming potential
HCl hydrogen chloride
HHV high heat value
HSS horizontal stud S[oslash]derberg
IPCC Intergovernmental Panel on Climate Change
IR infrared
LDCs local natural gas distribution companies
mmBtu/hr million British thermal units per hour
mscf thousand standard cubic feet
MSW municipal solid waste
mtCO2e metric tons of CO2 equivalents
MVC molar volume conversion factor
MWC municipal waste combustor
NESHAP National Emission Standards for Hazardous Air Pollutants
NIST National Institute of Standards and Technology
NMR nuclear magnetic resonance
NSPS New Source Performance Standards
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
O2 oxygen
O&M operation and maintenance
OMB Office of Management and Budget
PFC perfluorocarbon
psia pounds per square inch absolute
QA quality assurance
QA/QC quality assurance/quality control
RATA relative accuracy test audit
RFA Regulatory Flexibility Act
RFG Refinery fuel gas
RGGI Regional Greenhouse Gas Initiative
scf standard cubic feet
scfm standard cubic feet per minute
SO2 sulfur dioxide
SWPB side worked prebake
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VSS vertical stud S[oslash]derberg

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Background on This Action
    C. Legal Authority
    D. How would these amendments apply to 2011 reports?
II. Revisions and Other Amendments
    A. Subpart A (General Provisions): Best Available Monitoring 
Methods
    B. Subpart A (General Provisions): Calibration Requirements
    C. Subpart A (General Provisions): Reporting of Biogenic 
Emissions
    D. Subpart A (General Provisions): Requirements for Correction 
and Resubmission of Annual Reports
    E. Subpart A (General Provisions): Information To Record for 
Missing Data Events
    F. Subpart A (General Provisions): Other Technical Corrections 
and Amendments
    G. Subpart C (General Stationary Fuel Combustion)
    H. Subpart D (Electricity Generation)
    I. Subpart F (Aluminum Production)
    J. Subpart G (Ammonia Manufacturing)
    K. Subpart P (Hydrogen Production)
    L. Subpart V (Nitric Acid Production)
    M. Subpart X (Petrochemical Production)
    N. Subpart Y (Petroleum Refineries)
    O. Subpart AA (Pulp and Paper Manufacturing)
    P. Subpart NN (Suppliers of Natural Gas and Natural Gas Liquids)
    Q. Subpart OO (Suppliers of Industrial Greenhouse Gases)
    R. Subpart PP (Suppliers of Carbon Dioxide)
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

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 on GHGs.
    The second section of this preamble describes in detail the changes 
that are being proposed to correct technical errors or 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 discusses the various statutory 
and executive order requirements applicable to this proposed 
rulemaking.

B. Background on This Action

    The final Part 98 was signed by EPA Administrator Lisa Jackson on 
September 22, 2009 and published in the Federal Register on October 30, 
2009 (74 FR 56260-56519, October 30, 2009). Part 98, which became 
effective on December 29, 2009, included reporting of GHG information 
from facilities and suppliers, consistent with the 2008 Consolidated 
Appropriations Act. \1\ These source categories capture approximately 
85 percent of U.S. GHG emissions through reporting by direct emitters 
as well as suppliers of fossil fuels and industrial gases.
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    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128.
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    This is the second time that EPA has published a notice proposing 
amendments to Part 98 to, among other things, correct certain technical 
and editorial errors that have been identified since promulgation and 
clarify or

[[Page 48747]]

propose amendments to certain provisions that have been the subject of 
questions from reporting entities. The first proposal was published on 
June 15, 2010 (75 FR 33950). This proposal complements the proposal 
published on June 15, 2010 and is not intended to duplicate or replace 
the proposed amendments published on June 15, 2010. We are seeking 
public comment only on the issues specifically identified in this 
proposal for the identified subparts. We will not respond to any 
comments addressing other aspects of Part 98 or any other related 
rulemakings.

C. Legal Authority

    EPA is proposing these rule amendments under its existing CAA 
authority, specifically authorities provided in section 114 of the CAA.
    As stated in the preamble to the final Part 98 (74 FR 56260, 
October 30, 2009), CAA section 114 provides EPA broad authority to 
require the information proposed to be gathered by Part 98 because such 
data would inform and are relevant to EPA's obligation to carry out a 
wide variety of CAA provisions. As discussed in the preamble to the 
initial proposal (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 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 final rule, and Response to Comments 
Documents.\2\
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    \2\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 
2009). Response to Comments Documents can be found at http://www.epa.gov/climatechange/emissions/responses.html.
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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 Part 98, 
as amended by this and the other revisions package (75 FR 33950), as 
finalized. 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 or flexibility 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 and clarity on existing requirements. For example, we are 
proposing to amend 40 CFR 98.3(c)(5)(i) to clarify that suppliers of 
industrial flourinated GHGs need to calculate and report GHG emissions 
in metric tons of CO2 equivalents (mtCO2e) only 
for those flourinated GHGs that are listed in Table A-1. This proposed 
clarification is consistent with clarifications we have issued in 
response to industry questions and would not change how facilities 
collected data during 2010.
    Some of the proposed amendments provide greater flexibility or 
simplified calculation methods for certain facilities. For example, we 
are proposing to amend subpart C by adding a new equation that would 
enable sources that receive natural gas billing data from their 
suppliers in therms to calculate CO2 mass emissions directly 
from the information on the billing records, without having to request 
or obtain additional data from the fuel suppliers.
    Some proposed amendments are to the data reporting requirements to 
provide additional clarity on when different types of GHG emissions 
need to be calculated and reported. For example, in subpart G, Ammonia 
Manufacturing, we are proposing to eliminate the calculation and 
reporting of CO2 emissions associated with the use of the 
waste recycle stream or ``purge'' as fuel under subpart C because these 
emissions are already accounted for in the calculation of total process 
emissions in subpart G, which includes CO2 emissions 
resulting from the use of purge gas as a fuel. We have 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 already in part 98 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 are proposing 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, or reduce the reporting burden. For example, in 
subparts X (Petrochemical Production) and Y (Petroleum Refineries), 
reporters have requested that allowance be made for alternative 
standard conditions within the molar volume conversion factor (MVC) 
used in various equations. Therefore, we are proposing to amend those 
subparts to include MVCs at standard conditions defined at both 
60[ordm]F or 68[ordm]F, so the facilities will not have to make those 
corrections in their data.
    We are also proposing corrections to terms and definitions in 
certain equations. For example, in subpart Y, Petroleum Refineries, we 
are proposing to clarify in an equation that for coke calcining units 
that recycle the collected coke dust, the mass of coke dust removed 
from the process is the mass of coke dust collected less the mass of 
coke dust recycled to the process. These clarifications do not result 
in additional requirements; therefore, we have concluded that reporters 
can follow Part 98, as amended, in submitting their first reports in 
2011.
    Finally, we are proposing other technical corrections that have no 
impact on facility's data collection efforts in 2010. For example, we 
are proposing to amend subpart C to remove a second copy of Table C-2 
that was inadvertently included in the final Part 98 published on 
October 30, 2009.
    In summary, these amendments would not require any additional 
monitoring or information collection above what was already included in 
Part 98. Therefore, we expect that sources can use the same information 
that they have been collecting under the current version of Part 98 to 
calculate and report GHG emissions for 2010 and submit reports in 2011 
under the amended Part 98.
    We seek 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 of Part 98 for which 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. Revisions and Other Amendments

    Following promulgation of Part 98, we have 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 Part 98. We have also identified 
certain rule provisions that should be amended to provide greater 
clarity. We are also proposing revisions to provide additional

[[Page 48748]]

flexibility for certain requirements based in part on our better 
understanding of various industries. Finally, we are also proposing to 
revise or remove certain applicability thresholds (for example for 
local distribution companies subject to subpart NN (Suppliers of 
Natural Gas and Natural Gas Liquids)) and monitoring thresholds and 
reporting requirements (for example for municipal solid waste 
combusters subject to subpart C (General Stationary Fuel Combustion) 
and for certain small sources subject to subpart X (Petrochemicals) or 
subpart Y (Petroleum Refineries)). 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.
    As mentioned above in section I of this preamble, we published an 
earlier proposed rulemaking proposing technical corrections and other 
amendments to Part 98 on June 15, 2010 (75 FR 33950). This proposal 
complements the notice published on June 15, 2010 and is not intended 
to duplicate or replace the proposed amendments published on June 15, 
2010. 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 Part 98 or any 
other related rulemakings.

A. Subpart A (General Provisions): Best Available Monitoring Methods

    Certain owners and operators in the more complex hydrogen, 
petrochemical, and petroleum refinery industries have expressed 
concerns regarding the timing of the requirements to install meters and 
other measurement devices to comply with Part 98. Specifically, they 
were concerned that the safe installation of required measurement 
devices requires detailed engineering and planning and, therefore, 
stated that EPA should provide sufficient time for designing and safely 
engineering instrumentation installations or upgrades. Further, they 
claimed that in continuously operated plants there is typically not a 
scheduled shutdown for an entire facility and unit maintenance and 
turnarounds are not an annual occurrence for all units. Reporters in 
these industries have asserted that EPA has properly recognized this 
operational reality in the context of instrument calibration by 
allowing calibration to be delayed until the next scheduled shutdown. 
The reporters have noted, however, that parallel requirements have not 
been developed for installation of monitoring devices. Specifically, 
they requested that EPA should provide approval criteria for extending 
the use of ``best available monitoring methods'' (BAMM) beyond December 
31, 2010 for equipment installation.
    These types of concerns were the reason owners and operators were 
given the opportunity in Part 98 to request an extension from EPA to 
use BAMM beyond March 31, 2010 in situations where it was not 
reasonably feasible to acquire, install and operate the required 
monitoring equipment by that date. We recognize, however, that 
instances may occur where facilities subject to Part 98 may not have 
been scheduled to shutdown during 2010, and requiring the facility to 
shutdown solely to install the required measurement devices during 2010 
could impose an unnecessary burden.
    Therefore, we are proposing that a new petition process be 
established in a new paragraph 40 CFR 98.3(j) that would allow use of 
BAMM past December 31, 2010 for owners and operators required to report 
under subpart P (Hydrogen Production), subpart X (Petrochemicals 
Production), or subpart Y (Petroleum Refineries), under limited 
circumstances. We are proposing that owners or operators subject to 
these subparts could petition EPA to extend use of BAMM past December 
31, 2010, if compliance with a specific provision in the regulation 
required measurement device installation, and installing the device(s) 
would necessitate an unscheduled process equipment or unit shutdown or 
could only be installed through a hot tap. If the petition is approved, 
the owner or operator could postpone installation of the measurement 
device until the next scheduled maintenance outage, but initially no 
later than December 31, 2013. If, in 2013, owners or operators still 
determine and certify that a scheduled shutdown will not occur by 
December 31, 2013, they may re-apply to use best available monitoring 
methods for an additional two years.
    The initial process for use of best available monitoring methods in 
Part 98 ended December 31, 2010, because we concluded that it is 
important to establish a date by which all equipment must be installed 
and operating in order to ensure that consistent data are collected by 
all reporters. We maintain that it is important to have consistent 
methods being used by all reporters. However, we also recognize that 
some complex facilities have unique operating circumstances that 
justify additional flexibility. Therefore, although we are proposing to 
initially approve extension requests no later than December 31, 2013, 
owners or operators subject to these subparts would have a one time 
opportunity to re-apply for the extension request for an additional two 
years, with approval being granted no later than December 31, 2015. We 
believe that a date of December 31, 2013, four years after the 
effective date of Part 98, would accommodate the shutdown schedules for 
most, if not all facilities subject to subparts P, X, and/or Y. Because 
we recognize that all such facilities subject to Part 98 may not have a 
planned process equipment or unit shutdown prior to December 31, 2013, 
we have has concluded that it is reasonable to propose that owners or 
operators could re-apply one time for an additional two years. This 
timeline balances the need to gather consistent data, while recognizing 
the operational reality of such facilities.
    Process for Requesting an Extension of Best Available Monitoring 
Methods. We are proposing to add a similar petition process to that 
recently concluded for the use of BAMM for 2010 in the new paragraph 40 
CFR 98.3(j). The process would be available solely for facilties 
subject to subparts P, X and/or Y, and solely for the installation of 
measurement devices that cannot be installed safely except during full 
process equipment or unit shutdown or through installation via a hot 
tap. BAMM would be allowable initially until December 31, 2013. Subpart 
P, X, and/or Y owners or operators requesting to use BAMM beyond 2010 
would be required to electronically notify EPA by January 1, 2011 that 
they intend to apply for BAMM for installation of measurement devices 
and certify that such installation would require a hot tap or 
unscheduled shutdown.
    Owners or operators would be required to submit the full extension 
request for BAMM by February 15, 2011. The full extension requests 
would

[[Page 48749]]

include a description of the measurement devices that could not be 
installed in 2010 without a process equipment or unit shutdown, or 
through a hot tap, a clear explanation of why that activity would not 
be accomplished in 2010 with supporting material, an estimated date for 
the next planned maintenance outage, and a discussion of how emissions 
would be calculated in the interim. More specifically, the full 
extension request would need to identify the specific monitoring 
instrumentation for which the request is being made, indicate the 
locations where each piece of monitoring instrumentation will be 
installed, and note the specific rule requirements (by rule subpart, 
section, and paragraph numbers) for which the instrumentation is 
needed. The extension requests would also be required to include 
supporting documentation demonstrating that it is not practicable to 
isolate the equipment and install the monitoring instrument without a 
full process equipment or unit shutdown, or through a hot tap, as well 
as providing the dates of the three most recent process equipment or 
unit shutdowns, the typical frequency of shutdowns for the respective 
equipment or unit, and the date of the next planned shutdown.
    Once subpart P, X, and/or Y owners or operators have notified EPA 
of their plan to apply for BAMM for measurement device installation, by 
January 1, 2011, and subsequently submitted a full extension request, 
by February 15, 2011, they would automatically be able to use BAMM 
through June 30, 2011. All measurement devices would need to be 
installed by July 1, 2011 unless EPA approves the BAMM request before 
that date.
    Approval of Extension Requests. In an approval of an extension 
request, EPA would approve the extension itself, establish a date by 
which all measurement devices must be installed, and indicate the 
approved alternate method for calculating GHG emissions in the interim.
    If EPA approves an extension request, the owner/operator would have 
until the date approved by EPA to install any remaining meters or other 
measurement devices, however initial approvals would not grant 
extensions beyond December 31, 2013. An owner/operator that already 
received approval from EPA to use BAMM during part or all of 2010 would 
be required to submit a new request for use of BAMM beyond 2010. Unless 
EPA has approved an extension request, all owners or operators that 
submit a timely request under this new proposed process for BAMM would 
be required to install all measurement devices by July 1, 2011.
    We recognize that occasionally a facility may plan a scheduled 
process equipment or unit shutdown and the installation of required 
monitoring equipment, but the date of the scheduled shutdown is 
changed. We are proposing to include a process by which owners or 
operators who had received an extension would have the opportunity to 
extend the use of BAMM beyond the date approved by EPA if they can 
demonstrate to the Administrator's satisfaction that they are making a 
good faith effort to install the required equipment. At a minimum, 
facilities that determine that the date of a scheduled shutdown will be 
moved would be required to notify EPA within 4 weeks of such a 
determination, but no later than 4 weeks before the date of which the 
planned shutdown was scheduled.
    One-time request to extend best available monitoring methods past 
December 31, 2013. If subpart P, X, and/or Y owners or operators 
determine that a scheduled shutdown will not occur by December 31, 
2013, they would be required to re-apply to use best available 
monitoring methods for one additional time period, not to extend beyond 
December 31, 2015. To extend use of best available monitoring methods 
past December 13, 2013, owners or operators would be required to submit 
a new extension request by June 1, 2013 that contains the information 
required in proposed 40 CFR 98.3(j)(4). All owners or operators that 
submit a request under this paragraph to extend use of best available 
monitoring methods for measurement device installation would be 
required to install all measurement devices by December 31, 2013, 
unless the extension request under this paragraph is approved by EPA.
    We seek comment on this approach to extend the deadline for 
installation of measurement devices in cases where such installation 
would require an unscheduled process equipment or unit shutdown at a 
subpart P, X, and/or Y facility. The proposed approach is consistent 
with the language and intent in Part 98 to defer calibration of 
required monitors in order to avoid unnecessary and unplanned 
shutdowns. The proposed approach is also modeled after the provision to 
request EPA to use BAMM during 2010. We considered, but did not 
propose, limiting this provision to only those subpart P, X, and/or Y 
owners and operators who submitted a request for use of BAMM by January 
28, 2010. This option was considered based on an assumption that the 
full universe of reporters that had difficulty installing the necessary 
measurement devices according to the schedule in the rule would have 
already submitted a request for the use of BAMM in 2010. We still 
believe that all owners or operators that required a process equipment 
or unit shutdown to install measurement devices should have submitted 
an extension request to EPA by January 28, 2010. Nevertheless, we also 
recognize that this is a new regulation and facilities subject to Part 
98 are making good faith efforts to understand all requirements. After 
careful consideration we are proposing to initiate a new process for 
BAMM, providing all facilties with units subject to subpart P, subpart 
X or subpart Y the opportunity to apply.
    We are proposing to limit the provision to facilities with units 
subject to one or more of these three subparts because, based on 
questions received during implementation, the concerns raised about 
installation of measurement devices necessitating process equipment or 
unit shutdown have been from facilities subject to these subparts. A 
clear case was not presented by other industries as to any unique 
circumstances in those industries (e.g., safety concerns associated 
with installation of measurement devices, frequency of shutdowns, 
complexities associated with shutting down, etc.) that might 
necessitate extending the deadline for BAMM for these other industries. 
We are seeking comment on this conclusion and whether there are other 
facilities beyond these subparts P, X, and Y that would need a 
shutdown, or a hot tap, in order to install the required measurement 
devices. If providing comments, please provide information on 
additional subparts, if any, that would need this flexibility, and 
include information on why installation could not be done in the 
absence of such a shutdown or why such shutdowns did not or could not 
occur in 2010 without unreasonable burden on the facility.
    We are generally seeking comment on this new petition process for 
BAMM.

B. Subpart A (General Provisions): Calibration Requirements

    Since the rule was published on October 30, 2009, EPA has received 
numerous questions about the intent and extent of the equipment 
calibration requirements specified in 40 CFR 98.3(i). The current rule 
could be interpreted to require all types of measurement equipment that 
provide data for the GHG emissions calculations, including flow meters 
and ``other devices'' such as belt scales, to be

[[Page 48750]]

calibrated to a specified accuracy (i.e., 5.0 percent in most cases).
    The perceived universal nature of the calibration requirements in 
40 CFR 98.3(i) has caused a great deal of concern in the regulated 
community. For example, the appropriateness of a 5.0 percent accuracy 
specification for a wide variety of measurement devices has been 
questioned. Specifically, reporters have recommended that the initial 
and on-going calibration requirements be modified to allow the accuracy 
to be determined within an appropriate error range for each measurement 
technology, based on an applicable standard.
    Also, for small combustion units using the Tier 1 or Tier 2 
CO2 calculation methodologies in 40 CFR 98.33(a), reporters 
were concerned that the calibration requirements and accuracy 
specifications appear to apply to flow meters that are used to quantify 
liquid and gaseous fuel usage. This contradicts the clear statements in 
the nomenclature of Equations C-1 and C-2a of Subpart C that company 
records can be used to measure fuel consumption for Tier 1 and 2 units. 
We note that the definition of ``company records'' in 40 CFR 98.6 is 
quite flexible and it does not require that any particular calibration 
methods be used or that specific accuracy percentages be met.
    In view of these considerations, we are proposing to amend 40 CFR 
98.3(i) as follows, to more clearly define the scope of the calibration 
requirements:
    (a) We are proposing to amend 40 CFR 98.3(i)(1) to specify that the 
calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) would 
be required only for flow meters that measure liquid and gaseous fuel 
feed rates, feedstock flow rates, or process stream flow rates that are 
used in the GHG emissions calculations, and only when the calibration 
accuracy requirement is specified in an applicable subpart of Part 98. 
For instance, the QA/QC requirements in 40 CFR 98.34(b)(1) of Subpart C 
require all flow meters that measure liquid and gaseous fuel flow rates 
for the Tier 3 CO2 calculation methodology to be calibrated 
according to 40 CFR 98.3(i); therefore, the accuracy standards in 40 
CFR 98.3(i)(2) and (i)(3) would continue to apply to these meters. EPA 
has many years of experience with fuel flow meter calibration, for 
example in the Acid Rain and NOX Budget Programs, and the 
Agency is confident that the accuracy requirements specified in 40 CFR 
98.3(i) are both reasonable and achievable for such meters. For more 
information please refer to the Background Technical Support Document 
at EPA-HQ-OAR-2008-0508. We are also proposing to add statements to 40 
CFR 98.3(i) to clarify that the calibration accuracy specifications of 
40 CFR 98.3(i)(2) and (i)(3) do not apply where the use of company 
records or the use of best available information is specified to 
quantify fuel usage or other parameters, nor do they apply to sources 
that use Part 75 methodologies to calculate CO2 mass 
emissions because the Part 75 quality-assurance is sufficient. Although 
calibration accuracy requirements are not applicable for these data 
sources, per the requirements of 98.3(g)(5), reporters are still 
required to explain in their monitoring plan the processes and methods 
used to collect the necessary data for the GHG calculations.
    (b) We are proposing to further amend 40 CFR 98.3(i)(1) to clarify 
that the calibration accuracy specifications in 40 CFR 98.3(i)(2) and 
(i)(3) do not apply to other measurement devices (e.g., weighing 
devices) that provide data for the GHG emissions calculations. Rather, 
these devices would have to be calibrated to meet the accuracy 
requirements of the relevant subpart(s), or, in the absence of such 
requirements, to meet appropriate, technology-based error-limits, such 
as industry consensus standards or manufacturer's accuracy 
specifications. Consistent with 40 CFR 98.3(g)(5)(i)(C), the procedures 
and methods used to quality-assure the data from the measurement 
devices would be documented in the written monitoring plan.
    (c) We are proposing to add a new paragraph 40 CFR 98.3(i)(1)(ii) 
to clarify that flow meters and other measurement devices need to be 
installed and calibrated by the date on which data collection needs to 
begin, if a facility or supplier becomes subject to Part 98 after April 
1, 2010.
    (d) We are proposing to add a new paragraph 40 CFR 98.3(i)(1)(iii) 
to specify the frequency at which subsequent recalibrations of flow 
meters and other measurement devices need to be performed. 
Recalibration would be at the frequency specified in each applicable 
subpart, or at the frequency recommended by the manufacturer or by an 
industry consensus standard practice, if no recalibration frequency was 
specified in an applicable subpart.
    (e) We are proposing to specify the consequences of a failed flow 
meter calibration in a new paragraph 40 CFR 98.3(i)(7). Data would 
become invalid prospectively, beginning at the hour of the failed 
calibration and continuing until a successful calibration is completed. 
Appropriate substitute data values would be used during the period of 
data invalidation.
    (f) In 40 CFR 98.3(i)(2) and (3), we are proposing to add absolute 
value signs to the numerators of Equations A-2 and A-3. These were 
inadvertently omitted in the October 30, 2009 Part 98.
    (g) We are proposing to amend 40 CFR 98.3(i)(3) to increase the 
alternative accuracy specification for orifice, nozzle, and venturi 
flow meters (i.e., the arithmetic sum of the three transmitter 
calibration errors (CE) at each calibration level) from 5.0 percent to 
6.0 percent, since each transmitter is individually allowed an accuracy 
of 2.0 percent. We are also proposing to amend 40 CFR 98.3(i)(3) for 
orifice, nozzle, and venturi flow meters to account for cases where not 
all three transmitters for total pressure, differential pressure, and 
temperature are located in the vicinity of a flow meter's primary 
element. Instead of being required to install additional transmitters, 
reporters would, as described below, conditionally be allowed to use 
assumed values for temperature and/or total pressure based on 
measurements of these parameters at remote locations. If only two of 
the three transmitters are installed and an assumed value is used for 
temperature or total pressure, the maximum allowable calibration error 
would be 4.0 percent. If two assumed values are used and only the 
differential pressure transmitter is calibrated, the maximum allowable 
calibration error would be 2.0 percent. We note that the use of an 
arithmetic sum of the calibration errors is consistent with the 
approach in Part 75, and is designed to introduce flexibility, by 
allowing the results of a calibration to be accepted as valid when the 
calibration error of one (or in some cases, two) of the transmitters 
exceeds 2.0 percent. We did not intend to introduce an uncertainty 
analysis, such as the square root of the sum of the squares, for 
quantifying uncertainty.
    We are also proposing to amend 40 CFR 98.3(i)(3) to add five 
conditions that must be met in order for a source to use assumed values 
for temperature and/or total pressure at the flow meter location, based 
on measurements of these parameters at a remote location (or 
locations).
     The owner or operator would have to demonstrate that the 
remote readings, when corrected, are truly representative of the actual 
temperature and/or total pressure at the flow meter location, under all 
expected ambient conditions. Pressure and temperature surveys could be 
performed to determine the difference between the readings obtained 
with the remote transmitters

[[Page 48751]]

and the actual conditions at the flow meter location.
     All temperature and/or total pressure measurements in the 
demonstration must be made with calibrated gauges, sensors, 
transmitters, or other appropriate measurement devices.
     The methods used for the demonstration, along with the 
data from the demonstration, supporting engineering calculations (if 
any), and the mathematical relationship(s) between the remote readings 
and the actual flow meter conditions derived from the demonstration 
data would have to be documented in the monitoring plan for the unit 
and maintained in a format suitable for auditing and inspection.
     The temperature and/or total pressure at the flow meter 
must be calculated on a daily basis from the remotely measured values, 
and the measured flow rates must then be corrected to standard 
conditions.
     The mathematical correlation(s) between the remote 
readings and actual flow meter conditions must be checked at least once 
a year, and any necessary adjustments must be made to the 
correlation(s) going forward.
    (h) We are proposing to amend 40 CFR 98.3(i)(4) to include an 
additional exemption from the calibration requirements of 40 CFR 
98.3(i) for flow meters that are used exclusively to measure the flow 
rates of fuels used for unit startup or ignition. For instance, a meter 
that is used only to measure the flow rate of startup fuel (e.g., 
natural gas) to a coal-fired unit would be exempted. This proposed 
revision is modeled after a similar calibration exemption in section 
2.1.4.1 of Appendix D to 40 CFR Part 75, for fuel flow meters that 
measure startup and ignition fuels. The amount of fuel used for 
ignition and startup generally provides a very small percentage of the 
annual unit heat input (less than 1 percent in most cases). Therefore, 
rigorous calibration of meters used exclusively for startup and 
ignition fuels is unnecessary. Paragraph 98.3(i)(4) would be further 
amended to clarify that gas billing meters are exempted from the 
monitoring plan and record keeping provisions of 40 CFR 
98.3(g)(5)(i)(c) and (g)(7), which require, respectively, that a 
description of the methods used to quality-assure data from instruments 
used to provide data for the GHG emissions calculations be included in 
the written monitoring plan, and that maintenance records be kept for 
those instruments. We are proposing these changes because operation, 
maintenance, and quality assurance of gas billing meters is the 
responsibility of the fuel supplier, not the consumer.
    (i) We are proposing to amend 40 CFR 98.3(i)(5) to clarify that 
flow meters that were already calibrated according to 40 CFR 98.3(i)(1) 
following a manufacturer's recommended calibration schedule or an 
industry consensus calibration schedule do not need to be recalibrated 
by the date specified in 40 CFR 98.3(i)(1) as long as the flow meter is 
still within the recommended calibration interval. This paragraph would 
also be amended to clarify that the deadline for successive 
calibrations would be according to the a manufacturer's recommended 
calibration schedule or an industry consensus calibration schedule.
    (j) We are proposing to amend 40 CFR 98.3(i)(6) to account for 
units and processes that operate continuously with infrequent outages 
and cannot meet the flow meter calibration deadline without disrupting 
normal process operation. Part 98 currently allows the owner or 
operator to postpone the initial calibration until the next scheduled 
maintenance outage. The rule did not require shutdown for calibration 
of equipment because it was determined to be an unnecessary burden to 
require shutdown for calibration given that all measurement equipment 
required for GHG emissions would be required to be calibrated if they 
did not have an active calibration, necessitating a potentially large 
number of shutdowns.
    Although the rule allows postponement of calibration, it does not 
specify how to report fuel consumption for the entire time period 
extending from January 1, 2010 until the next maintenance outage. 
Section 98.3(d) of subpart A allows sources to use the ``best available 
monitoring methods'' (BAMM) until April 1, 2010, and to petition the 
Administrator to continue using the BAMM through December 31, 2010, but 
not beyond that date.
    In view of this, we are proposing to amend 40 CFR 98.3(i)(6) to 
permit sources to use the best available data from company records to 
quantify fuel usage until the next scheduled maintenance outage. This 
proposed revision would address situations where the next scheduled 
outage is in 2011, or later.

C. Subpart A (General Provisions): Reporting of Biogenic Emissions

    Reporters have noted that in the final Part 98 a new requirement 
was introduced that requires separate reporting of biogenic emissions 
from facilities (40 CFR 98.3(c)). They have noted that had EPA sought 
comment on this requirement in the proposal, they may have commented 
that units subject to subpart D (Electricity Generation) should not be 
required to report biogenic emissions separately, as this is not 
currently required under Part 75, which generally established the 
procedures for measuring data under subpart D. Or, they may have 
recommended specific methods for calculating biogenic emissions from 
Part 75 units. Owners and operators have stated that it is not clear in 
Part 98 which method is required for estimating these emissions from 
units subject to subpart D.
    EPA has subsequently provided guidance that separate reporting of 
biogenic emissions for units subject to subpart D is optional; however, 
in order to provide clarity and remove any potential inconsistencies, 
we are proposing revisions to subpart A and soliciting comment.
    We intended that units subject to subpart D would continue to 
monitor and report CO2 mass emissions as required under 40 
CFR 75.13 or section 2.3 of apppendix G to 40 CFR part 75, and 40 CFR 
75.64. These provisions do not require separate accounting of biogenic 
emissions, and we did not intend to require additional accounting 
methods for these units under Part 98. We intended for the reporting of 
biogenic CO2 emissions to be optional for units subject to 
subpart D. However, the current rule does not consistently affirm this. 
Section 98.3(c)(4) of subpart A requires sources to report facility-
wide GHG emissions, excluding biogenic CO2, and to report 
CO2 emissions for each source category excluding biogenic 
CO2. To meet these reporting requirements, facilities with 
subpart D and/or other Part 75 units on-site would have to separately 
account for the biogenic CO2 emissions (if any) from those 
units.
    To address these concerns, we are proposing to amend the data 
elements in subparts A and C that currently require separate accounting 
and reporting of biogenic CO2 emissions so that it would be 
optional for Part 75 units. All units, except Part 75 units, would 
still be required to calculate and report biogenic CO2 
emissions separately under subpart C. We are proposing to amend the 
following sections of subparts A and C to reflect these changes:
     40 CFR 98.3(c)(4)(i) would be revised to no longer require 
facilities to report annual emissions, excluding biogenic 
CO2; instead, it would require all owners or operators to 
report annual facility-wide emissions, including biogenic 
CO2.

[[Page 48752]]

     40 CFR 98.3(c)(4)(ii) and (c)(4)(iii)(A) would be amended 
to state that separate reporting of biogenic CO2 emissions 
is not required for units using part 75 methodologies to calculate 
CO2 mass emissions.
     40 CFR 98.3(c)(4)(ii)(B) would be revised to no longer 
require reporting of the annual CO2 emissions from subparts 
C through JJ, excluding biogenic CO2; instead, it would 
require reporting of the total annual CO2 emissions for each 
subpart, including biogenic CO2. 40 CFR 98.33(a)(5)(iii)(D) would be redesignated as 40 CFR 
98.33(a)(5)(iv) and amended to state that separate reporting of 
biogenic CO2 emissions is optional for part 75 units that 
qualify for and elect to use the alternative CO2 mass 
emissions reporting options in 40 CFR 98.33(a)(5).
     A statement would be added to 40 CFR 98.33(e) to indicate 
that separate reporting of biogenic CO2 emissions is not 
required for units subject to subpart D of part 98, and for part 75 
units using the alternative CO2 mass emissions reporting 
options in 40 CFR 98.33(a)(5). However, if the owner or operator elects 
to report biogenic CO2 emissions, the methods in Sec.  
98.33(e) would be used.
     Three paragraphs of the data reporting section of subpart 
C, specifically 40 CFR 98.36(d)(1)(ii), (d)(2)(ii)(I), and 
(d)(2)(iii)(I), would be amended to reinforce that separate reporting 
of biogenic CO2 emissions is optional for part 75 units.
    The proposed amendments would not affect the burden for existing 
facilities, as existing non-Part 75 facilities were always required to 
calculate and report biogenic emissions separately. The amendments 
would simply require them to include those biogenic emissions in 
facility-wide and source category (subpart) totals, as opposed to 
subtracting them out. The proposed amendments would also address the 
inconsistency that appeared in Part 98 regarding separate reporting of 
biogenic emissions for electric generating units subject to subpart D 
or other units subject to Part 75, as these facilities would no longer 
be required to report facility emissions excluding biogenic 
CO2, although they retain the option to report biogenic 
CO2 separately.

D. Subpart A (General Provisions): Requirements for Correction and 
Resubmission of Annual Reports

    Subpart A requires that an ``owner or operator shall submit a 
revised report within 45 days of discovering or being notified by EPA 
of errors in an annual GHG report. The revised report must correct all 
identified errors. The owner or operator shall retain documentation for 
3 years to support any revisions made to an annual GHG report.''
    Some owners and operators have asserted that the requirements for 
resubmission of annual reports within 45 days of discovering an error 
or being notified by EPA of an error, and the requirement to correct 
all errors, is overly broad and could trigger a resubmission for 
virtually any error. They were also concerned that these requirements 
are made more burdensome by the fact that the data system is not yet 
developed, and some identified ``errors'' may not in fact be errors, 
but rather software bugs that are most likely to happen in the first 
year of operation of the data system. They have also observed that the 
regulatory requirement is more burdensome than the Acid Rain Program 
(ARP), which has operated for more than 15 years without such a 
requirement in the regulation.
    We included this correction requirement in Part 98 because we 
determined that it is important to ensure that the most accurate data 
are available, in a timely fashion, for developing future GHG policies 
and programs. Generally, adding a requirement to resubmit data is also 
consistent with other EPA reporting programs, such as the ARP and the 
Toxic Release Inventory, as well as State and other GHG programs. While 
it is true that the ARP does not have a specific time requirement for 
resubmission in the regulation, in practice revised data have been 
submitted in less than 45 days after notification or identification of 
an error. While we maintain that it is important to retain a deadline 
for resubmission of the report after an error is identified in order to 
ensure EPA receives timely submission of data, we also recognize that 
certain circumstances may exist in which owners or operators cannot 
correct the identified errors within the 45 days. Therefore, we are 
proposing to amend 40 CFR 98.3(h) to clarify how a resubmission is 
triggered and the process for resubmitting annual GHG reports.
    First, reports would only have to be resubmitted when the owner or 
operator or the Administrator determines that a substantive error 
exists. A substantive error would be defined as one that impacts the 
quantity of GHG emissions reported or otherwise prevents the reported 
data from being validated or verified. This clarification is important 
because some errors are not significant (e.g., an error in the zip 
code) and do not impact emissions. Such ``errors'' would not obligate 
the owner or operator to resubmit the annual report.
    The owner or operator would be required to resubmit the report 
within 45 days of identifying the substantive error, or the 
Administrator notifying them of a substantive error, unless the owner 
or operator provides information demonstrating that the previously 
submitted report does not contain the identified substantive error or 
that the identified error is not a substantive error. This proposed 
change would provide owners or operators the opportunity to demonstrate 
that what the Administrator has deemed to be substantive errors are 
not, in fact, substantive errors.
    Finally, we are also proposing to introduce the opportunity for 
owners or operators to request an extension on the 45-day resubmission 
deadline to address facility-specific circumstances that arise in 
either correcting an error or determining whether or not an identified 
error is, in fact, a substantive error. Owners or operators would be 
required to notify EPA by e-mail at least two business days prior to 
the end of the 45-day resubmission deadline if they seek an extension. 
An automatic 30-day extension would be granted if EPA does not respond 
to the extension request by the end of the 45-day period.
    We are proposing the opportunity to extend the period for 
resubmission in recognition that the data system is still under 
development and we do not yet fully know the full range of errors that 
will be identified, and therefore the time required to address such 
errors. Verification and quality assurance and quality control checks 
are currently under development in the data system. Some flags that the 
data system might generate will not necessarily reflect substantive 
errors, but rather would be flags to alert the owner or operator to 
review the submission carefully to make sure the information provided 
is correct. On the other hand, some flags could identify substantive 
errors that affect the overall GHG emissions reported to EPA. Although 
we have concluded that it is important to provide facilities the 
opportunity to extend this deadline, we believe that the 45-day time 
period is a sufficient time period for the vast majority of facilities.

E. Subpart A (General Provisions): Information To Record for Missing 
Data Events

    Certain reporters have suggested that the recordkeeping 
requirements related to missing data events are overly burdensome. 
Specifically, 40 CFR 98.3(g)(4) of Part 98 specifies that the owner or 
operator must keep records of the cause and duration of each event, the 
actions taken to restore

[[Page 48753]]

malfunctioning monitoring equipment, and actions taken to prevent or 
minimize future occurrences. They have asserted that compared to Part 
98, Part 75 requires only reporting of the cause of the missing data 
event and the corrective actions taken, but does not require separate 
accounting of the duration of the event or the actions taken to 
minimize occurrence in the future. They have further claimed that most 
missing data events associated with the use of continuous emissions 
monitors are due to routine activities or calibration failures for 
which there are no clear measures to avoid similar occurrences in the 
future. Therefore, according to the owners and operators, the final 
recordkeeping requirements are overly burdensome and add little value.
    After reviewing these requirements, we agree with the claims and we 
are proposing to amend 40 CFR 98.3(g)(4) by requiring that records be 
kept of only the cause of each missing data event and the corrective 
actions taken. We have concluded that this information is sufficient 
for operating the program and that making this change will reduce the 
reporting burden for all reporters. This proposed revision would make 
the Part 98 recordkeeping provisions for missing data events consistent 
with those in 40 CFR Part 75 (specifically 40 CFR 75.57(h)). We further 
propose to clarify that the records retained pursuant to 40 CFR 
75.57(h) may be used to meet the recordkeeping requirements under Part 
98 for the same missing data events.

F. Subpart A (General Provisions): Other Technical Corrections and 
Amendments

    We are proposing several amendments to subpart A, as follows. We 
are proposing to amend 40 CFR 98.3(c)(1) by adding a requirement to 
report a facility or supplier ID number. We expect to receive GHG 
emissions data in electronic format from thousands of facilities and 
suppliers. Therefore, a unique ID number must be assigned to each 
facility or supplier, for administrative purposes, to facilitate 
program implementation. This approach has worked well in other EPA 
programs that require electronic data reporting from large numbers of 
facilities (e.g., the Acid Rain and NOX Budget Programs). 
The exact mechanism for assigning the ID numbers has not yet been 
determined. EPA will provide the necessary guidance later this year.
    We are proposing to amend the elements required with a certificate 
of representation under 40 CFR 98.4(i)(2) to include organization name 
(company affiliation-employer). We are also proposing to add the same 
element to the delegation by designated representative and alternate 
designated representative under 40 CFR 98.4(m)(2). This information 
will help EPA and reporting system users to correctly identify persons 
during the designated representative appointment or agent delegation 
process. Part 98 and the proposed amendments would not require the 
designated representative, alternate designated representative or agent 
to be an employee of the reporting entity. When a designated 
representative further delegates their authority to an agent, the agent 
would gain access to all data for that facility or supplier. To 
underline the importance of granting access to the correct person, EPA 
would require the designated representative (or alternate) to confirm 
each agent delegation. Adding organization name to the certificate of 
representation and notice of delegation will add a level of assurance 
to the confirmation process.
    We are proposing to amend 40 CFR 98.3(c)(5)(i) to clarify that for 
the purposes of meeting the requirements of this paragraph, suppliers 
of industrial flourinated GHGs only need to calculate and report GHG 
emissions in mtCO2e for those flourinated GHGs that are 
listed in Table A-1. This amendment is proposed because in order to 
incorporate additional fluorinated GHGs not listed in Table A-1 into 
the supplier's total GHG emissions in mtCO2e, the reporter 
would be required to propose a GWP for the gas or use an established 
factor developed by the Intergovernmental Panel on Climate Change or 
another entity. EPA does not believe it is necessary to require 
reporters to develop a GWP for these gases at this time. Further, it is 
important to note that these gases would still be required to be 
reported under 40 CFR 98.3(c)(5)(ii) (in metric tons of GHG). 
Therefore, EPA could calculate mtCO2e emissions from these 
gases in the future as GWP's become available or are updated.
    Finally, we are proposing to amend 40 CFR Part 98.6 (Definitions) 
and 40 CFR Part 98.7 (What Standardized Methods are Incorporated by 
Reference into this Part?). We are proposing to add or change several 
definitions to Subpart A, which are needed to clarify terms used in 
other subparts of Part 98. 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 40 CFR 98.3(d)(3) to correct the year in 
which reporters that submit an abbreviated report for 2010 must submit 
a full, report from 2011 to 2012. The full report submitted in 2012 
will be for the 2011 reporting year.
    We are proposing to amend 40 CFR 98.3(f) to correct the cross-
reference from ``Sec.  98.3(c)(8)'' to ``Sec.  98.3(c)(9).''
    We are proposing to amend the definitions of several terms in 40 
CFR 98.6:
     Bulk Natural Gas Liquid,
     Distillate fuel oil,
     Fossil fuel,
     Mscf,
     Municipal solid waste or MSW, and
     Natural gas.
    Bulk Natural Gas Liquid. Owners and operators have objected to the 
definition of ``bulk natural gas liquid or NGL.'' Section 98.6 in 
subpart A defines ``bulk natural gas liquid or NGL'' as a product which 
``refers to mixtures of hydrocarbons that have been separated from 
natural gas as liquids through the process of absorption, condensation, 
adsorption, or other methods at lease separators and field 
facilities.'' The owners and operators have requested we remove the 
phrase ``or other methods at lease separators and field facilities'' 
from the above definition. They assert that these processes are not 
simple separation processes, but rather, NGL extraction processes that 
are typically performed at ``gas plants'' and not at ``lease separators 
and field facilities.''
    We agree that the separation processes listed in the definition of 
``bulk natural gas liquid or NGL'' are associated with gas plants, and 
not lease separators and field facilities. It was not EPA's intent to 
require the reporting of emissions associated with these processes at 
lease separators and field facilities. In fact, in 40 CFR 98.400, we 
specifically state that the supplier category consists only of natural 
gas liquids fractionators and local natural gas distribution companies. 
Under 40 CFR 98.400(c), we specify that field gathering and boosting 
stations, as well as natural gas processing plants that ``separate NGLs 
from natural gas * * * but do not fractionate these NGLs into their 
constituent products'' do not meet the source category's definition.
    Therefore, we are proposing to strike ``lease separators and field 
facilities'' from the definition of ``bulk natural gas liquid or NGL,'' 
as well as from the definition of ``natural gas liquids (NGL)'' for 
enhanced clarity. However, we have determined that the words ``or other 
methods'' should remain in the above definition because the list of 
separation processes listed in the definition (absorption, 
condensation, adsorption) is not exhaustive, and other separation/
extraction processes may be employed at some facilities. We do not wish 
to exclude the reporting of emissions

[[Page 48754]]

associated with products separated/extracted by means not explicitly 
stated in the rule.
    Distillate Fuel Oil. We are proposing to expand the definition of 
``Distillate fuel oil'' to include kerosene-type jet fuel.
    Fossil Fuel. Some reporters have noted that the proposed rule set 
forth the same definition of ``fossil fuel'' that applies in the New 
Source Performance Standards program: ``Fossil fuel means natural gas, 
petroleum, coal, or any form of solid, liquid, or gaseous fuel derived 
from such materials for the purpose of creating useful heat'' (74 FR 
16621).
    However, the final Part 98 includes the following definition, 
which, according to certain Parties, has no precedent in Clean Air Act 
(CAA) regulations: ``Fossil fuel means natural gas, petroleum, coal, or 
any form of solid, liquid, or gaseous fuel derived from such material, 
including for example, consumer products that are derived from such 
materials and are combusted.''
    These owners and operators have asserted that the public did not 
have sufficient opportunity to comment on these changes, which 
together, they claimed, re-classify municipal solid waste (MSW) and 
tires as fossil fuel and could set an unintended precedent for other 
CAA programs. Further, they claimed that EPA changed the designation of 
MSW and tires from being classified as ``alternative fuels'' in the 
proposal to being classified as ``fossil fuel-derived fuels (solid)'' 
in the final Part 98.
    We did not intend to ``re-classify'' MSW and tires between the 
proposal and final Part 98 in any meaningful way. Rather, any changes 
made were due to the overall restructuring of the General Stationary 
Fuel Combustion source category in response to comments and were 
intended to expand the use of Tier 1 and Tier 2, and to remove some 
requirements that would subject units to Tier 3. Based on the above 
concerns, however, it has become apparent that stakeholders believe the 
changes had unintended consequences. Therefore, we have reevaluated 
this issue and are proposing amendments to the classification of fuels 
in Table C-1, as well as the definition of fossil fuel. We note that 
overall we do not believe that the changes between the proposed and 
final Part 98, nor the amendments described below, have a substantive 
impact on the calculation requirements or the reporting of emissions 
for MSW or tires under this rule.
    We made several changes from proposal in Part 98 in response to 
comments about use of the Tiers. In subpart C, in order for facilities 
to use Tier 1 or Tier 2, the fuel combusted had to be included in Table 
C-1. MSW and tires were not included in Table C-1; rather they were 
included in the proposed Table C-2, which was generically labeled 
``alternative fuels.'' The restructuring of the Tiers in subpart C 
necessitated moving all fuels for which Tier 1 and Tier 2 were allowed 
into Table C-1. Table C-1 labeled these fuels as ``fossil fuel-
derived'' to reflect the methods used to calculate emissions, noting 
the related provisions for determining the biogenic portions of fuels 
in subpart C.
    In order to address the above concerns raised with subpart C, we 
are now proposing to change the heading for these fuels from ``fossil 
fuel-derived'' to ``Other fuels (solid)'' in Table C-1.
    Further, we are proposing to amend the definition of fossil fuel to 
return to the initial proposed definition. After proposal, we altered 
the definition in subpart A intending to provide clarity to facilities 
subject to Subpart C in the reporting of CO2 emissions per 
the requirements of 40 CFR 98.36, specifically, intending to clarify 
what was meant in the proposed definition by `` * * * solid, liquid, or 
gaseous fuel derived from such materials.'' We also changed the 
definition in subpart A to better align the definition of fossil fuel 
with the definition of the general stationary fuel combustion sources 
in 40 CFR 98.30 (i.e., ``devices that combust solid, liquid, or gaseous 
fuels, generally for the purposes of producing electricity, generating 
steam, or providing useful heat or energy for industrial, commercial, 
or institutional use, or reducing the volume of waste by removing 
combustible materials'').
    We believe that the definition included in subpart A may have not 
added the clarity expected and that the definition of general 
stationary fuel combustion sources provided in subpart C is sufficient. 
We are soliciting comment on the proposed changes in the definition of 
fossil fuel in subpart A in the context of the calculation methods 
provided for these fuels in subpart C, and ask commenters to provide 
additional information if they believe that emissions from combusting 
these fuels should be estimated differently.
    Mscf. We are 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 noted in the final rule, a million standard 
cubic feet.
    Municipal Solid Waste. We have received many questions regarding 
the definition of ``Municipal solid waste or MSW'' in Part 98. 
Specifically, the brevity of the definition makes it difficult to 
determine whether certain types of waste constitute MSW. We are 
proposing to amend the definition to closely match the definition of 
``municipal solid waste'' in Subpart Ea of the NSPS regulations (40 CFR 
60.51a). The amended definition would explain what is meant by 
``household waste,'' ``commercial/retail waste,'' and ``institutional 
waste.'' It would also provide a comprehensive list of materials that 
are excluded from these categories (e.g., industrial process or 
manufacturing wastes and medical waste).
    Natural Gas. We have also received many questions indicating that 
the definition of ``Natural gas'' is too inclusive and in some respects 
counterintuitive. The current definition begins with a statement that 
natural gas is a naturally occurring mixture of hydrocarbon and non-
hydrocarbon gases found beneath the earth's surface. However, it ends 
by equating ``process gas'' and ``fuel gas'' (neither of which is a 
naturally occurring gas mixture) with natural gas. We are proposing to 
amend the definition of ``Natural gas'' in 40 CFR 98.6 to be consistent 
with definitions found in 40 CFR Parts 60 and 75. The amended 
definition would remove the references to process gas and fuel gas, and 
would specify that natural gas must be at least 70 percent methane or 
have a high heat value between 910 and 1150 Btu/scf.
    We are proposing to add definitions of the following terms to 40 
CFR 98.6 due to the large number of questions received requesting 
clarification of the definition of these terms:
     Agricultural byproducts,
     Primary fuel,
     Solid byproducts,
     Waste oil, and
     Wood residuals.
    The terms ``Agricultural byproducts,'' ``Solid byproducts,'' and 
``Wood residuals'' are used to describe three types of solid biomass 
fuels listed in Table C-1 of Subpart C, but they are not defined in 40 
CFR 98.6. The proposed definitions are based on the results of an 
Internet search and IPCC inventory guidelines (see EPA-HQ-OAR-2008-
0508). For the purposes of Part 98, ``Agricultural byproducts'' would 
include the parts of crops that are not ordinarily used for food (e.g., 
corn straw, peanut shells, pomace, etc.). ``Solid byproducts'' would 
include plant matter such as vegetable waste, animal materials/wastes, 
and other solid biomass, except for wood, wood waste and sulphite lyes 
(black liquor). ``Wood residuals'' would include waste wood

[[Page 48755]]

recovered primarily from MSW streams, construction and demolition 
debris, and primary timber processing. Wastewater process sludge 
generated at pulp and paper mills would also be included; however, we 
are soliciting comment on whether the default emission factors for wood 
and wood residuals are appropriate for paper mill wastewater sludge, 
and, if not, what those emission factors should be.
    ``Primary fuel'' would be defined as the fuel that contributes the 
greatest percentage of the annual heat input to a combustion unit. 
``Waste oil,'' which we are proposing to add to Table C-1 as a new fuel 
type, would be defined as oil whose physical properties have changed, 
either through storage, handling, or use, so that the oil can no longer 
be used for its original purpose. Waste oil would include both 
automotive and industrial oils of various types.

G. Subpart C (General Stationary Fuel Combustion)

    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart C for general stationary fuel 
combustion. The issues being addressed by the proposed amendments 
include the following:
     Definition of the source category.
     GHGs to report.
     Calculating GHG emissions.
     Natural gas consumption expressed in therms.
     Use of Equation C-2b to calculate weighted annual average 
HHV.
     Categories of gaseous fuels.
     Use of mass-based gas flow meters.
     Site-specific stack gas moisture content values.
     Determining emissions from an exhaust stream diverted from 
a CEMS monitored stack.
     Biomass combustion in units with CEMS.
     Use of Tier 3.
     Tier 4 requirements for units that combust greater than 
250 tons of MSW per day.
     Applicability of Tier 4 to common stack configurations.
     Starting dates for the use of Tier 4.
     CH4 and N2O calculations.
     CO2 emissions from sorbent.
     Biogenic CO2 emissions from biomass combustion.
     Fuel sampling for coal and fuel oil.
     Tier 3 sampling frequency for gaseous fuels.
     CO2 emissions from blended fuel combustion.
     Use of consensus standard methods.
     CO2 monitor span values.
     CEMS data validation.
     Use of ASTM Methods D7459-08 and D6866-08.
     Electronic data reporting and recordkeeping.
     Common stack reporting option.
     Common fuel supply pipe reporting option.
     Table C-1 default HHV and CO2 emission factors.
     Table C-2 default CH4 and N2O 
emission factors.
    Definition of the source category. We are proposing to add a new 
paragraph 40 CFR 98.30(d), clarifying that the GHG emissions from a 
pilot light need not be included in the emissions totals for the 
facility. Section 98.30(a) of subpart C defines a stationary fuel 
combustion source as a device that combusts `` * * * solid, liquid, or 
gaseous fuel, generally for the purposes of producing electricity, 
generating steam, or providing useful heat or energy for industrial, 
commercial, or institutional use, or reducing the volume of waste by 
removing combustible matter * * * ''. A pilot light is a small 
permanent auxiliary flame that simply ignites the burner of a 
combustion process in a boiler, turbine, or other fuel combustion 
device, and is not used to produce electricity or steam, or to provide 
useful energy to an industrial process, or to reduce waste by removing 
combustible matter. Therefore, we are clarifying that, for the purposes 
of Part 98, a pilot light is not considered to be a stationary fuel 
combustion source and pilot gas consumption would not be required to be 
included in the GHG emissions calculations.
    GHGs to Report. We are proposing to amend 40 CFR 98.32 to clarify 
that CO2, CH4, and N2O mass emissions 
from a stationary fuel combustion unit do not need to be reported under 
subpart C if such an exclusion is indicated elsewhere in subpart C.
    Calculating GHG emissions. We are proposing to amend 40 CFR 
98.33(a) to provide additional detail and clarify who may (or must) use 
the calculation methods in the subsequent paragraphs to calculate and 
report GHG emissions. Specifically, we are proposing to amend this 
paragraph to point out that certain sources may use the methods in 40 
CFR part 75 to calculate CO2 emissions, if they are already 
using Part 75 to report heat input data year-round under another Clean 
Air Act program. Paragraph 98.33(a) would also be amended to clarify 
the reporting of CO2 emissions from biomass combustion when 
a unit combusts both biomass and fossil fuels.
    Natural gas consumption expressed in therms. Subpart C of Part 98 
allows the use of fuel billing records to quantify natural gas 
consumption, for the purposes of calculating CO2 mass 
emissions. On the billing records provided by natural gas suppliers, 
fuel usage is often expressed in units of ``therms,'' rather than 
standard cubic feet (scf). A therm is equal to 100,000 Btu, or 0.1 
mmBtu. Therefore, the equations for calculating CO2 mass 
emissions in Subpart C (e.g., Equation C-1), which require fuel usage 
to be in units of scf, are not suitable when fuel consumption is 
expressed in therms.
    In view of this, we are proposing to amend 40 CFR 98.33(a)(1) by 
adding a new equation, C-1a, to Tier 1. When natural gas consumption is 
expressed in therms, equation C-1a would enable sources to calculate 
CO2 mass emissions directly from the information on the 
billing records, without having to request or obtain additional data 
from the fuel suppliers.
    We are proposing to allow Equation C-1a to be used for units of any 
size when the fuel usage information on natural gas billing records is 
expressed in units of therms. A new paragraph, (b)(1)(v), would be 
added to 40 CFR 98.33 to reflect this. Section 98.36(e)(2)(i) would 
also be amended to allow gaseous fuel consumption to be reported in 
units of therms.
    Use of Equation C-2b. Whenever HHV data are received on a monthly 
or more frequent basis, the Tier 2 CO2 emissions calculation 
methodology requires the owner or operator to use Equation C-2b to 
calculate the annual average HHV, weighted according to monthly fuel 
usage. The fuel-weighted annual average HHV is then substituted into 
Equation C-2a. If HHV data are received less frequently than monthly, 
an arithmetic average HHV is used in the emissions calculations (see 40 
CFR 98.33(a)(2)(ii)).
    However, we have learned that in cases where a facility includes 
part 75 units (i.e., boilers and/or combustion turbines) and small 
combustion sources such as space heaters that share a common natural 
gas or oil supply, the use of Tier 2 may be triggered for the small 
combustion sources when the part 75 units use the appendix D 
methodology to quantify heat input. This is because appendix D of Part 
75 requires periodic sampling of the heating value of fuel oil and 
natural gas. Tier 2 will be triggered for the small combustion units if 
the Part 75 fuel sampling frequency is equal to or greater than the 
minimum frequency specified in Sec.  98.34(a). Further, if the part 75 
fuel sampling frequency is monthly or greater, Equation C-2b would have 
to be used to calculate fuel-weighted annual average HHVs for the small 
combustion sources.
    Requiring small, low-emitting combustion sources to calculate 
CO2

[[Page 48756]]

mass emissions using fuel-weighted annual average HHVs instead of 
arithmetic average values will not significantly enhance data quality. 
In view of this, we are proposing to amend 40 CFR 98.33(a)(2)(ii), to 
require calculation of a weighted HHV only for individual Tier 2 units 
with a maximum rated heat input capacity greater than or equal to 100 
mmBtu/hr, and for groups of units that contain at least one unit of 
that size. For Tier 2 units smaller than 100 mmBtu/hr and for 
aggregated groups of Tier 2 units under Sec.  98.36(c)(1) in which all 
units in the group are smaller than 100 mmBtu/hr, the annual arithmetic 
average HHV, rather than the annual fuel-weighted average HHV, would be 
used in Equation C-2a.
    Categories of Gaseous Fuels. Section 98.34(a)(2)(iii) of subpart C 
requires quarterly HHV sampling for liquid fuels other than fuel oil, 
for fossil fuel-derived gaseous fuels, and for biogas, when the Tier 2 
methodology is used to calculate CO2 mass emissions. The 
term ``fossil fuel-derived gaseous fuels'' has caused considerable 
confusion among regulated sources. The nomenclature and organization of 
Table C-1 of Subpart C makes it hard to determine which fuels are 
included in this category. Currently, only two fuels are listed in 
Table C-1 under the heading of fossil fuel-derived gaseous fuels: blast 
furnace gas and coke oven gas. However, a number of other gaseous fuels 
that are derived from petroleum, such as butane, are not listed there, 
but are listed under a different heading for ``petroleum products.''
    We are proposing to revise 40 CFR 98.33(a)(2)(iii) by replacing the 
term ``fossil fuel-derived gaseous fuels'' with a more inclusive term, 
i.e., ``gaseous fuels other than natural gas.'' Corresponding changes 
would also be made to Table C-1 for consistency, placing blast furnace 
gas, coke oven gas, fuel gas, and propane in a new category, ``Other 
fuels (gaseous).''
    Use of Mass-Based Gas Flow Meters. The Tier 3 CO2 
emissions calculation methodology in 40 CFR 98.33(a)(3) currently 
allows flow meters that measure mass flow rates of liquid fuels to be 
used to quantify fuel consumption, provided that the density of the 
fuel is determined and the measured mass of fuel is converted to units 
of volume (i.e., gallons), for use in Equation C-4. In response to a 
number of requests, we are proposing to amend 40 CFR 98.33(a)(3)(iv), 
to conditionally allow flow meters that measure mass flow rates of 
gaseous fuels to be used for Tier 3 applications. To use mass flow 
meters, the density of the gaseous fuel would have to be measured, 
either with a calibrated density meter or by using a consensus standard 
method or standard industry practice, in order to convert the measured 
mass of fuel to units of standard cubic feet, for use in Equation C-5.
    Site-Specific Stack Gas Moisture Content Values. The Tier 4 
calculation methodology in 40 CFR 98.33(a)(4) requires a CO2 
CEMS to be used together with a stack gas flow rate monitor to measure 
CO2 mass emissions. If the CO2 monitor measures 
on a dry basis, corrections for the stack gas moisture content are 
needed, because the flow monitor measures on a wet basis.
    Part 98 currently requires that the moisture corrections be made 
either by installing a continuous moisture monitoring system or by 
using a default moisture value from 40 CFR Part 75 (specifically 40 CFR 
75.11(b)(1)) in the calculations. However, the default moisture 
constants from Part 75 only apply to various grades of coal, and to 
wood and natural gas.
    Recently, we have received inquiries from a number of sources that 
currently have dry-basis CO2 monitors in place and are 
required to use Tier 4. These sources have requested that EPA allow the 
use of site-specific default moisture values, in cases where no 
applicable default value is specified in Part 75 for the type(s) of 
fuel(s) combusted, or where the Part 75 moisture values are believed to 
be unrepresentative.
    EPA has approved many petitions for site-specific moisture content 
default values under the ARP. Therefore, we believe it is reasonable to 
allow Part 98 sources to develop such default values, using an approach 
similar to the one that has been approved under the ARP.
    In view of this, we are proposing to amend 40 CFR 98.33(a)(4)(iii) 
to allow the use of site-specific moisture constants under the Tier 4 
methodology. The site-specific moisture default value(s) would have to 
represent the fuel(s) or fuel blends that are combusted in the unit 
during normal, stable operation, and would have to account for any 
distinct difference(s) in stack gas moisture content associated with 
different process operating conditions.
    For each site-specific default moisture percentage, at least nine 
runs would be required using EPA Method 4--Determination Of Moisture 
Content In Stack Gases (40 CFR Part 60, Appendix A-3). Moisture data 
from the relative accuracy test audit (RATA) of a CEMS could be used 
for this purpose. Each site-specific default moisture value would be 
calculated by taking the arithmetic average of the Method 4 runs.
    Each site-specific moisture default value would be updated at least 
annually, and whenever the current value is believed to be non-
representative, due to changes in unit or process operation. The 
updated moisture value would be used in the subsequent CO2 
emissions calculations.
    Determining Emissions from an Exhaust Stream Diverted from a CEMS 
Monitored Stack. We are proposing to amend 40 CFR 98.33(a)(4) by adding 
a new paragraph, (a)(4)(viii), to address the determination of 
CO2 mass emissions from a unit subject to the Tier 4 
calculation methodology when a portion of the flue gases generated by 
the unit exhaust through a stack that is not equipped with a CEMS to 
measure CO2 emissions (herein referred to as an 
``unmonitored stack'') The paragraph is intended to address situations 
where a portion of the stack gas generated by the Tier 4 unit is 
diverted for the purpose of drying fuels, recovering heat, or some 
other process-related activity. The provisions of the new paragraph 
would not apply when CO2 is removed or chemically altered in 
a way that significantly changes the CO2 concentration at 
the outlet of the unmonitored stack, compared to the outlet 
CO2 concentration at the stack equipped with a CEMS. The 
owner or operator would be required to use the best available 
information to estimate the hourly stack gas volumetric flow rates 
exhausting through the unmonitored stack. Best available information 
would include, but would not be limited to, correlation of operating 
parameters with flow rate, periodic flow rate measurements made with 
EPA Method 2, engineering analysis, etc. The estimated flow rates of 
the diverted gas stream would be made at the point where the diverted 
stream exits the main flue gas exhaust system. Each hourly volumetric 
flow rate value used in Equation C-6 of Subpart C would be the sum of 
the flow rate measured at the stack equipped with a CEMS and the 
estimated flow rate of the diverted gas stream. All procedures used to 
estimate the volumetric flow rate of the diverted gas stream would be 
documented in the monitoring plan required under 40 CFR 98.3(g)(5).
    Biomass Combustion in Units With CEMS. We are proposing to amend 40 
CFR 98.33(a)(5)(iii)(D) to redesignate it as 40 CFR 98.33(a)(5)(iv). 
This is to correct a paragraph numbering error in subpart C, because 
this paragraph applies to all of 40 CFR 98.33(a)(5) and not just to 40 
CFR 98.33(a)(5)(iii). As discussed above in section II.C of the 
preamble, we are also proposing to amend 40 CFR 98.3(c) in subpart A 
and

[[Page 48757]]

40 CFR 98.33(a)(5) to clarify that the separate reporting of biogenic 
CO2 is optional for units that are not subject to the Acid 
Rain Program, but are using Part 75 methodologies to calculate 
CO2 mass emissions, as described in 40 CFR 98.33(a)(5)(i) 
through (a)(5)(iii). As discussed above, separate reporting of biogenic 
CO2 emissions is also optional for units subject to subpart 
D.
    Use of Tier 3. Section 98.33(b)(3)(iii) of subpart C currently 
requires the use of Tier 3 when a fuel that is not listed in Table C-1 
of Subpart C is combusted in a unit with a maximum rated heat input 
capacity greater than 250 mmBtu/hr, if two conditions are met: (a) The 
use of Tier 4 is not required; and (b) the fuel provides at least 10 
percent of the annual heat input to the unit.
    However, 40 CFR 98.33(b)(3)(iii)(B) refers to the annual heat input 
to a group of units served by a common supply pipe, in addition to the 
heat input to an individual unit. The text of 40 CFR 98.33(b)(3)(iii) 
is not consistent with 40 CFR 98.33(b)(3)(iii)(B) because it does not 
mention common pipe configurations.
    We are proposing to amend 40 CFR 98.33(b)(3)(iii) to clarify that 
the paragraph applies also to common pipe configurations where at least 
one unit served by the common pipe has a heat input capacity greater 
than 250 mmBtu/hr.
    The Agency also proposes to add a new paragraph, (b)(3)(iv), to 40 
CFR 98.33, requiring Tier 3 to be used when specified in another 
subpart of Part 98, regardless of fuel type or unit size. For example, 
Subpart Y requires certain units that combust refinery fuel gas (RFG) 
to use Equation C-5 in Subpart C (which is the Tier 3 equation for 
gaseous fuel combustion) to calculate CO2 mass emissions, 
without regard to unit size.
    Tier 4 Requirements for Units That Combust Greater Than 250 Tons of 
MSW per Day. Owners and operators of units that combust municipal solid 
waste have contended that, because Part 98 requires that units that 
combust MSW must follow Tier 4 if they meet the requirements in 40 CFR 
98.33(b)(4)(ii) or 40 CFR 98.33(b)(4)(iii), it entails a 
disproportionate burden for municipal waste combustors (MWCs). One 
element of their argument was that a threshold of greater than 250 tons 
per day of MSW was a more stringent threshold than the 250 mmbtu/hr 
heat input threshold for other stationary combustion units and, 
therefore, a disproportionate burden for MWCs. Further, they stated 
that the industry did not have the necessary emission monitoring 
equipment in place and would, therefore, be required to install new 
equipment in order to meet the requirements of the rule.
    Part 98 included a threshold of 250 tons of MSW per day because it 
was consistent with the threshold applied in the EPA New Source 
Performance Standards (NSPS). Under that program, units combusting 
greater than 250 tons per day of MSW are considered ``large'' units. We 
did not believe that subpart C applied a disproportionate burden to 
municipal waste combustors because all ``large'' units (whether 250 
tons of MSW per day or with a heat input capacity greater than 250 
mmBtu/hr) would only be subject to Tier 4 if they met the other 
conditions outlined in 40 CFR 98.33(b)(4). We have reevaluated this 
issue based on the fact that while a threshold of 250 tons of MSW may 
be appropriate for the purposes of NSPS, it is not necessarily 
appropriate for a GHG emissions reporting program. We also recognize 
that a large majority of the units may have to install either a flow 
meter or a concentration monitor, and in some cases both, to comply 
with subpart C.
    Based on these concerns, we are proposing to amend 40 CFR 
98.33(b)(4)(ii)(A) to change the 250 tons MSW per day threshold to 600 
tons MSW per day, based on further analysis that this value is 
approximately equivalent to the 250 mmBtu/hr heat input requirements 
for other large stationary combustion units. For more information, 
please refer to the Background Technical Support Document (EPA-HQ-OAR-
2008-0508). Units less than 600 tons MSW per day, that do not meet the 
requirements in 40 CFR 98.33(b)(4)(iii) could use Tier 2. We believe 
that this proposal still meets the desired goal to obtain high quality 
data from larger units, while not applying unnecessary burden. With 
this proposed amendment, MWCs would be subject to comparable monitoring 
thresholds and conditions as other general stationary combustion units.
    Applicability of Tier 4 to Common Stack Configurations. Section 
98.36(c)(2) of Subpart C allows the owner or operator of stationary 
combustion units that share a common stack (or duct) and use the Tier 4 
methodology to calculate CO2 mass emissions to continuously 
monitor and report the combined CO2 mass emissions at the 
common stack (or duct), in lieu of separately monitoring and reporting 
the CO2 emissions from the individual units.
    Several other Subparts of Part 98 either: (1) Allow a particular 
process or manufacturing unit to use Tier 4 to quantify CO2 
mass emissions, as an alternative to using a mass balance approach (for 
instance, Subpart G allows this option for an ammonia manufacturing 
unit--see 40 CFR 98.73(a) and (b)); or (2) require Tier 4 to be used in 
certain instances when a process unit and a stationary combustion unit 
share a common stack (e.g., see 40 CFR 98.63(g) and 98.73(c)).
    Subpart C sets forth the applicability of Tier 4 in 40 CFR 
98.33(b)(4)(ii) and (b)(4)(iii). However, note that 40 CFR 98.33(b)(4) 
focuses exclusively on individual stationary fuel combustion units; no 
mention is made of common stack configurations.
    In view of this, we are proposing to amend 40 CFR 98.33(b)(4) by 
adding provisions to clarify how the Tier 4 criteria apply to common 
stack configurations. Paragraph (b)(4)(i) would be expanded to include 
monitored common stack configurations that consist of stationary 
combustion units, process units, or both types of units. A new 
paragraph, (b)(4)(iv) would also be added, describing the following 
three distinct common stack configurations to which Tier 4 might apply.
    The first, most basic configuration is one in which the combined 
effluent gas streams from two or more stationary fuel combustion units 
are vented through a monitored common stack (or duct). In this case, 
Tier 4 would apply if:
     There is at least one large unit in the configuration that 
has a maximum rated heat input capacity greater than 250 mmBtu/hr or an 
input capacity greater than 600 tons/day of MSW (as applicable);
     At least one large combustion unit in the configuration 
meets the conditions of 40 CFR 98.33(b)(4)(ii)(A) through 
(b)(4)(ii)(C); and
     The CEMS installed at the common stack (or duct) meets all 
of the requirements of 40 CFR 98.33 (b)(4)(ii)(D) through 
(b)(4)(ii)(F).
    Tier 4 would also apply when all of the combustion units in the 
configuration are small (hr or day of MSW), if 
at least one of the units meets the conditions of 40 CFR 
98.33(b)(4)(iii).
    The second configuration is one in which the combined effluent gas 
streams from a stationary combustion unit and a process or 
manufacturing unit are vented through a common stack or duct. Many 
subparts of part 98 describe this situation (see subparts F, G, K, Q, 
Z, BB, EE, and GG). In this case, the use of Tier 4 would be required 
if the stationary combustion unit and the monitors installed at the 
common stack or duct meet the applicability criteria of 40 CFR 
98.33(b)(4)(ii) or 98.33(b)(4)(iii). If multiple stationary combustion 
units

[[Page 48758]]

and a process unit (or units) are vented through a common stack or 
duct, Tier 4 would be required if at least one of the combustion units 
and the monitors installed at the common stack or duct meet the 
conditions of 40 CFR 98.33(b)(4)(ii) or 98.33(b)(4)(iii).
    The third configuration is one in which the combined effluent 
streams from two or more process or manufacturing units are vented 
through a common stack or duct. In this case, if any of these units is 
required to use Tier 4 under an applicable subpart of Part 98, the 
owner or operator could either monitor the CO2 mass 
emissions at the Tier 4 unit(s) before the effluent streams are 
combined together, or monitor the combined CO2 mass 
emissions from all units at the common stack or duct. However, if it is 
not feasible to monitor the individual units, the combined 
CO2 mass emissions would have to be monitored at the common 
stack or duct, using Tier 4.
    Starting Dates for the Use of Tier 4. Section 98.33(b)(5) of 
subpart C currently states that units that are required to use the Tier 
4 methodology must begin using it on January 1, 2010 if all required 
CEMS are in place. Otherwise, use of Tier 4 begins on January 1, 2011, 
and Tier 2 or Tier 3 may be used to report CO2 mass 
emissions in 2010. Recently, a number of sources have asked EPA whether 
Tier 4 may be used prior to January 1, 2011 if the required CEMS are 
certified some time in 2010, or whether Tier 2 or Tier 3 must be used 
for the entire year.
    We believe that it is reasonable for sources to begin reporting 
CO2 emissions data prior to 2011 from CEMS that successfully 
complete certification testing in 2010. Therefore, we are proposing to 
amend 40 CFR 98.33(b)(5) accordingly. Note that changes in methodology 
during a reporting year are allowed by Part 98, and must be documented 
in the annual GHG emissions report (see 40 CFR 98.3(c)(6)).
    The proposed revisions would allow sources to discontinue using 
Tier 2 or 3 and begin reporting their 2010 emissions under Tier 4 as of 
the date on which all required certification tests are passed. CEMS 
data recorded during the certification test period could also be used 
for Part 98 reporting, provided that: (a) All required certification 
tests are passed in sequence, with no test failures; and (b) no 
unscheduled maintenance or repair of the CEMS is required during the 
test period.
    We are also proposing to amend 40 CFR 98.33(b)(5) by adding a new 
paragraph, (b)(5)(iii), to address situations where the owner or 
operator of an affected unit that has been using Tier 1, 2, or 3 to 
calculate CO2 mass emissions makes a change that triggers 
Tier 4 applicability by changing: (1) The primary fuel, (2) the manner 
of unit operation, or (3) the installed continuous monitoring 
equipment. In such cases, the owner or operator would be required to 
begin using Tier 4 no later than 180 days from the date on which the 
change is implemented. This would allow adequate time for the owner or 
operator to obtain and/or certify any of the required Tier 4 continuous 
monitors.
    Methane and Nitrous Oxide Calculations. The equations for 
calculating CH4 and N2O emissions from stationary 
combustion sources are found in 40 CFR 98.33(c). Calculation of these 
emissions is required only for fuels listed in Table C-2 of Subpart C. 
When either the Tier 1 or the Tier 3 methodology is used to determine 
CO2 mass emissions, Equation C-8 is used to calculate 
CH4 and N2O emissions. Equation C-8 includes the 
term ``HHV,'' which is defined as the applicable default high heat 
value (HHV) from Table C-1 for a particular type of fuel. Owners and 
operators have asserted that they should be able to use actual HHV data 
for Tier 3 units, in lieu of using the Table C-1 default values, and 
noted that site-specific values would be more accurate.
    We agree that this would result in more accurate estimates of 
emissions and are proposing to revise the definition of the term 
``HHV'' in the Equation C-8 nomenclature. The proposed amendment would 
allow Tier 3 units to use actual HHV data to calculate CH4 
and N2O emissions. If multiple HHV values are obtained 
during the year, the arithmetic average would be used in Equation C-8.
    Units that monitor heat input year-round according to 40 CFR Part 
75 or that use the Tier 4 CO2 calculation methodology are 
required to use Equation C-10 in Subpart C to calculate CH4 
and N2O emissions. When more than one type of fuel listed in 
Table C-2 is combusted in these units during normal operation, 40 CFR 
98.33(c)(4)(ii) requires Equation C-10 to be used separately for each 
fuel.
    Owners and operators have asked EPA to clarify what is meant by 
``normal operation,'' and whether any fuel(s) should be excluded from 
the emissions calculations. Today's proposed amendments would clarify 
the Agency's intent by removing the term ``normal operation'' from 40 
CFR 98.33(c)(4)(i) and (c)(4)(ii). Therefore, calculation of 
CH4 and N2O emissions would simply be required 
for each Table C-2 fuel combusted in the unit during the reporting 
year.
    We are also proposing to further amend 40 CFR 98.33(c)(4)(ii), to 
allow additional reporting flexibility for certain units that combust 
more than one type of fuel; specifically, for units that report heat 
input data to EPA year-round using part 75 CEMS. For all multi-fuel 
units that use CEMS to comply with Part 98, subpart C requires the 
``best available information'' to be used to determine the percentage 
of the annual unit heat input contributed by each type of fuel, for the 
purposes of calculating CH4 and N2O mass 
emissions.
    For part 75 units that use CEMS to quantify unit heat input, the 
fuel-specific annual heat input values needed for the CH4 
and N2O emissions calculations can, in most cases, be 
determined from information in the part 75 electronic data reports--
specifically, from the ``F-factors'' reported for each unit operating 
hour. These F-factors, which are fuel-specific, are used in the hourly 
heat input calculations. Therefore, it is possible to use the reported 
F-factors to group the annual unit operating hours according to fuel 
type, and to sum the reported hourly heat input values for each group. 
However, if the owner or operator elects to use the reporting option in 
section 3.3.6.5 of part 75, appendix F, the fuel-specific heat input 
values cannot be determined from the emissions reports. This is because 
section 3.3.6.5 of appendix F allows the owner or operator to calculate 
all hourly heat input values using the ``worst-case'' (highest) F-
factor for any fuel combusted in the unit. A situation where this 
reporting option is likely to be implemented is for a coal-fired 
utility boiler that uses small amounts of natural gas for unit startup. 
A second example where the worst-case F-factor option is sometimes used 
is for a unit that combusts a blend of bituminous coal and sub-
bituminous coal, in varying proportions. The F-factors for these two 
grades of coal are nearly the same. For the examples cited, the impact 
on the reported annual unit heat input is generally very small (1 to 2 
percent at most). In view of this, we are proposing to allow part 75 
units that use the worst-case F-factor reporting option to attribute 
100 percent of the unit's annual heat input to the fuel with the 
highest F-factor, as though it were the only fuel combusted during the 
report year.
    For Tier 4 units, the requirement to use the best available 
information to determine the annual heat input from each type of fuel 
is being retained in 40

[[Page 48759]]

CFR 98.33(c)(4)(i), and we are proposing to allow it under 40 CFR 
98.33(c)(4)(ii)(D) as an alternative for part 75 units, in cases where 
fuel-specific heat input values cannot be determined directly from the 
part 75 electronic data reports.
    Carbon Dioxide Emissions from Sorbent. Section 98.33(d) of subpart 
C currently requires the following sources to use Equation C-11 to 
calculate and report CO2 mass emissions from sorbent, except 
where the total CO2 emissions are measured using CEMS: (a) 
Fluidized bed combustion units; (b) units with wet flue gas 
desulfurization (FGD) systems; and (c) units equipped with ``other acid 
gas emission controls with sorbent injection.'' Equation C-11 includes 
the term ``R,'' which is defined as ``1.00, the calcium to sulfur 
stoichiometric ratio.''
    Industry members have noted that some sorbents that reduce acid gas 
emissions do not produce CO2 (for instance, 
Ca(OH)2 does not). Further, the 1.00 value of R in Equation 
C-11 applies only to SO2 removal, indicating that one mole 
of CO2 is produced for every mole of SO2 removed. 
We have also been informed that CO2-producing sorbents such 
as sodium bicarbonate are sometimes injected to remove other acid gas 
species (e.g., HCl).
    In view of these considerations, we are proposing to amend 40 CFR 
98.33(d) by making it more generally applicable to different types of 
CO2-producing sorbents. The term ``R'' would be redefined as 
the number of moles of CO2 released upon capture of one mole 
of acid gas. When the sorbent is CaCO3, the value of R would 
be 1.00. For other CO2-producing sorbents, a specific value 
of R would be determined by the reporting facility from the chemical 
formula of the sorbent and the chemical reaction with the acid gas 
species that is being removed.
    Biogenic CO2 Emissions From Biomass Combustion. In 
response to questions about the methodologies in 40 CFR 98.33(e) for 
calculating biogenic CO2 mass emissions from biomass 
combustion, we are proposing a number of technical corrections and 
clarifications to that section of the rule.
    The title and introductory text of 40 CFR 98.33(e) would be amended 
to more precisely define the requirements for reporting biogenic 
CO2 emissions. In general, biogenic CO2 emissions 
reporting would be required only for the combustion of the biomass 
fuels listed in Table C-1 and for municipal solid waste (which consists 
partly of biomass and partly of fossil fuel derivatives).
    We are also proposing to amend 40 CFR 98.33(e) to describe three 
cases in which units that combust biomass would not need to report 
biogenic CO2 emissions separate from total CO2 
emissions:

    1. If a biomass fuel is not listed in Table C-1, the biogenic 
CO2 emissions would need to be reported separately from 
total CO2 emissions only if:

-- The fuel is combusted in a large unit (greater than 250 mmBtu/hr 
heat input capacity);
--The biomass fuel accounts for 10 percent or more of the annual heat 
input to the unit; and
--The unit does not use CEMS to quantify its annual CO2 mass 
emissions.

    In that case, according to 40 CFR 98.33(b)(3)(iii), Tier 3 would 
have to be used to determine the carbon content of the biomass fuel and 
to calculate the biogenic CO2 emissions.
    2. If a unit is subject to Subpart C or D and uses the 
CO2 mass emissions calculation methodologies in 40 CFR Part 
75 to satisfy the Part 98 reporting requirements, the reporting of 
biogenic CO2 emissions would be optional.
    3. For the combustion of tires, which are also partly biogenic 
(typically 10-20 percent biomass, for car and truck tires), separate 
reporting of the biogenic CO2 emissions would be optional, 
but could be done following provisions in 40 CFR 98.33(e).
    We are proposing to amend 40 CFR 98.33(e)(1) by removing the 
restriction against using Tier 1 to calculate biogenic CO2 
emissions on units that use CEMS to measure the total CO2 
mass emissions. There is no technical basis for this restriction, 
provided that biomass consumption can be accurately quantified. 
However, the use of Tier 1 would not be allowed for combustion of MSW, 
as originally specified in 40 CFR 98.33(e)(1) of subpart C, and would 
also not be allowed for the combustion of tires, if biogenic 
CO2 emissions are calculated for tires.
    We are proposing to amend the methodology in 40 CFR 98.33(e)(2), 
which is specifically for units using a CEMS to measure CO2 
mass emissions, by:
    1. Limiting it to cases where the CO2 emissions measured 
by the CEMS are solely from combustion, i.e., the stack gas contains no 
additional process CO2 or CO2 from sorbent; and
    2. Prohibiting its use if the unit combusts MSW or tires.
    Section 98.33(e)(2) of subpart C currently requires the total 
volume of CO2 produced from fossil fuel combustion (which is 
based on estimated fuel usage, measured HHVs and F-factors) to be 
subtracted from the total volume of CO2 from the combustion 
of all fuels (as determined from the CEMS data). The difference is 
assumed to be the volume of biogenic CO2. However, this 
approach is only viable if all of the CO2 emissions are from 
the combustion of fossil fuels and biomass, and if no fuels (such as 
MSW and tires) that are a mixture of biomass and fossil fuel 
derivatives are combusted in the unit.
    If there are any process CO2 emissions or CO2 
emissions from sorbent in the stack effluent, the volumes of those 
CO2 emissions would have to be subtracted from the total 
volume of CO2 derived from the CEMS data in order to 
determine the biogenic CO2 volume. Further, if any partly 
biogenic fuels (such as MSW and tires) are combusted in the unit, the 
fossil component of each of these fuels would have to be characterized. 
We are not aware of any method that is economically feasible for 
reporting sources to determine the mass percentage of the fossil fuel 
component of fuels such as MSW and tires. In addition, we are not aware 
of any practical method for quantifying CO2 volumes from 
sorbent or from non-combustion industrial processes. For these reasons, 
we are proposing restrictions ``1'' and ``2'' above on the use of the 
methodology in 40 CFR 98.33(e)(2).
    For sources that are combusting MSW, we are proposing to amend 40 
CFR 98.33(e)(3) to require the use of ASTM methods D7459-08 and D6866-
08 quarterly, as described in 40 CFR 98.34(d), when any MSW is 
combusted, either as the primary fuel or as the only fuel with a 
biogenic component. We are proposing to further amend 40 CFR 
98.33(e)(3) to allow the ASTM methods to be used, as described in 40 
CFR 98.34(e), for any unit in which biogenic (or partly biogenic) 
fuels, and non-biogenic fuels are combusted, in any proportions.
    We are also proposing to delete and reserve 40 CFR 98.33(e)(4) and 
the related subparagraphs. Although 40 CFR 98.33(e)(4) allows the ASTM 
methods to be used to determine biogenic CO2 emissions for 
various combinations of biogenic and fossil fuels, we are proposing to 
delete and reserve it because the paragraph also includes an 
unnecessary restriction, i.e., it only applies to units that use CEMS 
to measure total CO2 mass emissions. The proposed amendments 
to 40 CFR 98.33(e)(3) described above would achieve the same intended 
purpose as 40 CFR 98.33(e)(4), without imposing this restriction, so 40 
CFR 98.33(e)(4) is no longer needed.
    Finally, we are proposing to amend 40 CFR 98.33(e)(5) so that it 
would also

[[Page 48760]]

apply to units that are using Tier 2 (Equation C-2a), as well as Tier 1 
(Equation C-1), for calculating biogenic CO2 mass emissions. 
The approach in 40 CFR 98.33(e)(5) for estimating solid biomass fuel 
consumption is equally applicable to units using those two equations to 
calculate biogenic CO2 emissions. Equation C-2a would apply 
when HHV data for a biomass fuel are available at the minimum frequency 
specified in 40 CFR 98.34(a)(2).
    Fuel Sampling for Coal and Fuel Oil. We are proposing to amend 40 
CFR 98.34(a)(2), to clarify the frequency at which the HHV needs to be 
determined for different types of fuels.
    In subpart C, the Tier 2 calculation methodology in 40 CFR 
98.33(a)(2) requires periodic fuel sampling and analysis to determine 
HHVs. Section 98.34(a)(2) specifies the minimum required sampling 
frequency for various fuel types. For coal and fuel oil, at least one 
representative sample must be obtained and analyzed for each fuel lot. 
A ``fuel lot'' is defined as a shipment or delivery of a particular 
type of fuel, and may consist of a ship load, a barge load, a group of 
trucks, or a group of railroad cars.
    Several reporters have noted that some facilities receive fuel 
deliveries by truck, rail or pipeline quite frequently--even daily in 
some cases. The reporters have expressed the concern that, under 
subpart C, daily fuel deliveries appear to trigger a requirement for 
daily sampling and analysis, according to the definition of a fuel lot. 
Reporters have also noted that coal and petroleum derivatives such as 
coke and petroleum coke are often delivered in lots. Further, the 
Agency has received inquiries asking why a commonly-used fuel oil 
sampling strategy is not included in subpart C, i.e., taking a sample 
whenever oil is added to the storage tank.
    It is not our intent to require an excessive amount of HHV sampling 
for coal and fuel oil (or for any other solid or liquid fuel that is 
delivered in lots), or to prohibit the use of viable sampling options. 
Therefore, we are proposing, first, to amend 40 CFR 98.34(a)(2)(ii) to 
expand the list of fuels for which sampling of each fuel lot is 
sufficient to include other solid or liquid fuels that are delivered in 
lots.
    Second, we are proposing to more precisely define the term ``fuel 
lot'' in 40 CFR 98.34(a)(2)(ii), as it pertains to facilities that 
receive multiple deliveries of a particular fuel from the same supply 
source each month, either by truck, rail, or pipeline. The proposed 
amendment would clarify that a fuel lot consists of all of the 
deliveries for a given calendar month. Thus, for these facilities, the 
required HHV sampling frequency would be no greater than once per 
month. We are proposing to add parallel language to 40 CFR 
98.34(b)(3)(ii), the Tier 3 fuel sampling provisions for coal and fuel 
oil, for consistency with the proposed revisions to 40 CFR 
98.34(a)(2)(ii).
    Third, we are proposing to further revise 40 CFR 98.34(a)(2)(ii) 
and 98.34(b)(3)(ii) to allow manual oil samples to be taken after each 
addition of oil to the storage tank. Daily manual sampling, flow-
proportional sampling, and continuous drip sampling would also be 
allowed.
    Tier 3 Sampling Frequency for Gaseous Fuels. Section 
98.34(b)(3)(ii) of subpart C specifies the minimum required frequency 
for determining the carbon content and molecular weight of various 
types of fuel, when using the Tier 3 methodology to calculate 
CO2 mass emissions. For gaseous fuels, daily sampling is 
required if ``the necessary equipment is in place to make these 
measurements.'' Otherwise, weekly sampling is required.
    EPA has received a number of questions from owners and operators 
about the meaning of ``necessary equipment.'' In particular, sources 
have asked whether this refers only to continuous, on-line equipment 
such as gas chromatographs, or whether daily, manual sampling is 
required where such capability exists.
    We are proposing to amend 40 CFR 98.34(b)(3)(ii)(E) to clarify that 
daily sampling of gaseous fuels for carbon content and molecular weight 
is only required where continuous, on-line equipment is in place; 
weekly sampling would be required in all other cases. This has always 
been the Agency's intent.
    CO2 Emissions From Blended Fuel Combustion. One of the 
most frequently asked questions by the regulated community since the 
October 30, 2009 publication of Part 98 is, ``How does one calculate 
CO2 mass emissions from the combustion of blended fuels?'' 
Subpart C provided only limited guidance on this issue. First, 40 CFR 
98.34(a)(3) stated that when different types of fuel are blended (e.g., 
different ranks of coal or different grades of fuel oil), two options 
could be used for determining the HHV for Tier 2 applications: (a) Use 
a weighted HHV in the emissions calculations; or (b) take a 
representative sample of the blend and analyze it for HHV. Second, 40 
CFR 98.34(b)(3)(v) stated that these same two options apply to carbon 
content and molecular weight determinations under Tier 3. Third, for 
Tier 3 common pipe applications, 40 CFR 98.34(b)(1)(vi) required that 
fuels either be metered individually before blending, or that the 
blended fuel and a subset of the individual fuels be metered so that 
the volume of each fuel in the blend can be determined.
    Based on the number of questions received, we have concluded that 
these rule provisions do not adequately address the complexities 
associated with blended fuels. Therefore, we are proposing substantive 
amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v). The 
proposed amendments would make a clear distinction between cases where 
the mass or volume of each fuel in the blend is accurately measured 
prior to mixing (e.g., using individual flow meters for each component) 
and cases where the exact composition of the blend is not known. In the 
former case, the fact that the fuels are blended is of no consequence; 
because the exact quantity of each fuel in the blend is known, the 
CO2 emissions from combustion of each component would be 
calculated separately. In the latter case, we are proposing that the 
blend be considered to be a distinct ``fuel type,'' and that its mass 
or volume and essential properties (e.g., HHV, carbon content, etc.) be 
measured at a prescribed frequency.
    When the mass or volume of each individual component of a blend is 
not precisely known prior to mixing, the appropriate method used to 
calculate the CO2 mass emissions from combustion of the 
blend would be as follows. For smaller combustion units (heat input 
capacity not more than 250 mmBtu/hr), we are proposing that Tier 2 (or 
possibly Tier 1) be used when all components of the blend are listed in 
Table C-1 of Subpart C. In order to perform these CO2 
emissions calculations for the blend, a reasonable estimate of the 
percentage composition of the blend would be required, using the best 
available information (e.g., from the typical or expected range of 
values of each component). A heat-weighted CO2 emission 
factor would be calculated, using proposed Equation C-16. For Tier 1 
applications, a heat-weighted default HHV would also have to be 
determined, using proposed Equation C-17.
    In cases where a fuel blend consists of a mixture of fuel(s) listed 
in Table C-1 and fuel(s) not listed in Table C-1, calculation of 
CO2 and other GHG emissions from combustion of the blend 
would be required only for the Table C-1 fuel(s), using the best 
available estimate of the mass or volume percentage(s) of the Table C-1 
fuel(s) in the blend. In these cases, the use of Tier 1 would be 
required, with modifications to certain terms in Equations C-17 and

[[Page 48761]]

C-1, to account for the fact that the blend is not composed entirely of 
Table C-1 fuels. An example calculation is provided in proposed 40 CFR 
98.34(a)(3)(iv).
    For larger combustion units (heat input capacity greater than 250 
mmBtu/hr) that do not qualify to use Tier 1 or 2, we are proposing that 
the owner or operator would use Tier 3 to calculate the CO2 
mass emissions from combustion of a blended fuel. The mathematics for 
Tier 3 would be much simpler than for Tiers 1 and 2, since no default 
values are used in the calculations, and an estimate of the percentage 
composition of the blend is not required. To apply Tier 3, the only 
requirements would be to accurately measure the annual consumption of 
the blended fuel and to determine its carbon content and (if necessary) 
molecular weight, at a prescribed frequency. By considering the blended 
fuel to be a distinct ``fuel type,'' in cases where that fuel is not 
listed in Table C-1, GHG emissions reporting would be required in 
accordance with 40 CFR 98.33(b)(3)(iii), if the blended fuel (as 
opposed to each individual component of the blend) provides at least 10 
percent of the annual heat input to a unit or group of units, and if 
the use of Tier 4 is not required.
    To address the calculation of CH4 and N2O 
mass emissions from the combustion of blended fuels, we are proposing 
to add a new paragraph, (c)(6), to 40 CFR 98.33. Calculation of 
CH4 and N2O emissions would be required only for 
components of a blend that are listed in Table C-2 of Subpart C.
    If the mass or volume of each component of a blend is measured 
before the fuels are mixed and combusted, the existing CH4 
and N2O mass emissions calculation procedures in 40 CFR 
98.33(c)(1) through (5) would be followed for each component 
separately. The fact that the fuels are mixed prior to combustion is of 
no consequence in this case.
    If the mass or volume of each individual component is not measured 
prior to mixing, a reasonable estimate of the percentage composition of 
the blend would be required, based on the best available information, 
and the procedures in 40 CFR 98.33(c)(6)(ii) would be followed. First, 
the annual consumption of each component fuel in the blend would be 
calculated by multiplying the total quantity of the blend combusted 
during the reporting year by the estimated mass or volume percentage of 
that component. Next, the annual heat input from the combustion of each 
component would be calculated by multiplying its annual consumption by 
the appropriate HHV (either the default HHV from Table C-1 or, if 
available, the measured annual average value). The annual 
CH4 and N2O mass emissions for each component 
would then be calculated using the applicable equation in 40 CFR 
98.33(c), i.e., Equation C-8, C-9a, or C-10. Finally, the calculated 
CH4 and N2O emissions would be summed across all 
components, and these sums would be reported as the annual 
CH4 and N2O mass emissions for the blend.
    Use of Consensus Standard Methods. Sections 98.34(a)(6), (b)(4), 
and (b)(5) of subpart C specify acceptable methods for determining fuel 
HHV, carbon content, and molecular weight, and methods for calibrating 
fuel flow meters. The methods listed in those sections are from 
consensus standards organizations such as ASTM, ASME, AGA, and GPA. 
Although we attempted to assemble a comprehensive list of methods and 
provide appropriate alternatives, it is possible that other valid 
methods from these organizations and practices have been overlooked, or 
that in some cases, industry consensus standard methods may be more 
appropriate than the methods listed. In view of this, we are proposing 
to remove the specific method lists from 40 CFR 98.34 and to amend 40 
CFR 98.34(a)(6) and (b)(1)(i)(A), delete paragraph (b)(4), redesignate 
paragraph (b)(5) as (b)(4), and amend newly designated paragraph 
(b)(4). These proposed amendments would allow the owner or operator to 
either: (1) Use appropriate methods published by consensus standards 
organizations such as ASTM, ASME, API, AGA, ISO, etc.; or (2) use 
industry standard practice. The methods used would be documented in the 
monitoring plan under 40 CFR 98.3(g)(5).
    CO2 Monitor Span Values. The Tier 4 calculation method 
in 40 CFR 98.33(a)(4) requires a CO2 concentration monitor 
and a stack gas flow rate monitor to measure CO2 mass 
emissions. The CO2 monitor must be certified and quality-
assured according to one of the following: 40 CFR Part 60, 40 CFR Part 
75, or an applicable State CEM program. When the Part 60 option is 
selected, one of the required quality assurance (QA) tests of the 
CO2 monitor is a cylinder gas audit (CGA). The CGA checks 
the response of the CO2 analyzer at two calibration gas 
concentrations, i.e., one between 5 and 8 percent CO2 and 
one between 10 and 14 percent CO2. These CO2 
concentration levels are appropriate for most stationary combustion 
applications. For example, a typical span value for a CO2 
monitor installed on a coal-fired boiler is 20 percent CO2; 
therefore, the CGA concentrations represent 25 to 40 percent of span 
and 50 to 70 percent of span. However, when CO2 emissions 
from an industrial process (e.g., cement manufacturing) are combined 
with combustion CO2 emissions, the resultant CO2 
concentration in the stack gas can be substantially higher than for the 
combustion emissions alone. In such cases, a span value of 30 percent 
CO2 (or higher) may be required.
    When the CO2 span exceeds 20 percent CO2, the 
CGA concentrations specified in Part 60 only evaluate the lower portion 
of the measurement scale and are no longer representative. Therefore, 
we are proposing to amend 40 CFR 98.34(c) by adding a new paragraph 
(c)(6), which would allow the CGAs of a CO2 monitor to be 
performed using calibration gas concentrations of 40 to 60 percent of 
span and 80 to 100 percent of span, when the CO2 span value 
is set higher than 20 percent CO2.
    CEMS Data Validation. The Tier 4 methodology in 40 CFR 98.33(a)(4) 
requires the use of CEMS to measure CO2 mass emissions. For 
each unit operating hour, the CO2 mass emissions are 
determined using either valid CEMS data or appropriate substitute data 
values when monitors malfunction. For a Tier 4 unit, the owner or 
operator has the option to follow the CEMS certification and QA 
provisions of 40 CFR Part 60, 40 CFR Part 75, or an applicable State 
CEM program. This includes the criteria in those regulations pertaining 
to validation of the hourly CEMS data.
    The provisions for hourly CEMS data validation in Part 60 are found 
in 40 CFR 60.13(h)(2)(i) through (h)(2)(vi). For Part 75, hourly data 
validation is addressed in 40 CFR 75.10(d)(1). The CEMS data validation 
criteria in these sections of Parts 60 and 75 are virtually identical. 
The basic requirement to validate an hour is that at least one data 
point must be obtained in each 15-minute quadrant of the hour in which 
the unit operates. There is one notable exception to this. For 
operating hours in which required maintenance or QA testing is 
performed, obtaining a valid data point in two of the four quadrants is 
sufficient.
    In subpart C, 40 CFR 98.34(c) provides the monitoring and QA 
requirements for Tier 4. However, no criteria for hourly CEMS data 
validation are specified. In view of this, we are proposing to add a 
new paragraph, (c)(7), to 40 CFR 98.34(c), which would require hourly 
CEMS data validation to be consistent with the sections of Part 60 or 
Part 75 cited in the preceding paragraph. Alternatively, the hourly

[[Page 48762]]

data validation procedures in an applicable State CEM program could be 
followed.
    Use of ASTM Methods D7459-08 and D6866-08. Sections 98.34(d) and 
(e) of subpart C, respectively, outline procedures for quantifying 
biogenic CO2 emissions for units that combust municipal 
solid waste (MSW) and other units that combust combinations of fossil 
fuels and biomass. As specified in Part 98, flue gas samples are taken 
quarterly using ASTM Method D7459-08 and analyzed using ASTM Method 
D6866-08. We are proposing to amend 40 CFR 98.34(d) and (e), as 
discussed in the following paragraphs.
    The proposed amendments to 40 CFR 98.34(d) would require the ASTM 
methods to be used when MSW is combusted in a unit, either as the 
primary fuel, or as the only fuel with a biogenic component. Quarterly 
sampling with ASTM Method D7459-08 would still be required, for a 
minimum of 24 consecutive operating hours. However, we are proposing to 
add an alternative to allow the owner or operator to collect an 
integrated sample by extracting a small amount of flue gas (1 to 5 
cubic centimeters (cc)) during every unit operating hour in the 
quarter, in order to obtain a more representative sample for analysis. 
This sampling approach is recommended by experts on the use of ASTM 
Methods D7459-08 and D6866-08 when the types of fuel and their 
composition are variable over time, as is the case with MSW combustion. 
For more information please refer to the Background Technical Support 
Document (EPA-HQ-OAR-2008-0508).
    We are proposing to amend 40 CFR 98.34(e) to remove the restriction 
limiting the use of ASTM Methods D7459-08 and D6866-08 to units with 
CEMS. Rather, any unit that combusts combinations of fossil and 
biogenic fuels (or partly biogenic fuels, such as tires), in any 
proportions, would be allowed to determine biogenic CO2 
emissions using the ASTM methods on a quarterly basis. At least 24 
consecutive hours of sampling is currently specified in 40 CFR 
98.34(e). This is appropriate if the types of fuels and their relative 
proportions are consistent throughout the quarter. If the relative 
proportions are not consistent throughout the quarter, it may be more 
appropriate to consider collecting more frequent samples, however this 
is not required. Therefore, we are also amending 40 CFR 98.34(e) to 
recommend that a small (1 to 5 cc) flue gas sample be taken during each 
unit operating hour in the quarter.
    Electronic Data Reporting and Recordkeeping. EPA will rely on 
Agency verification of the electronic data provided in the annual GHG 
emission reports, in lieu of implementing third party verification. In 
order for Agency verification to be effective, sufficient information 
must be included in the electronic reports, at the facility, source 
category, and unit levels, to enable EPA to recalculate the reported 
GHG emissions and to quality-assure the data.
    Section 98.36 of subpart C provides several lists of data elements 
that must be reported for stationary combustion units. These lists are 
specific to the CO2 emissions calculation method employed 
(e.g., one of the four Tiers in 40 CFR 98.33(a) or a method in 40 CFR 
Part 75), and to the type(s) of electronic data report(s) that are 
submitted (e.g., individual unit reports, aggregated group reports, 
common pipe reports, etc).
    EPA has begun developing software to check and verify the 
electronic data in the GHG emissions reports. As this effort has 
progressed, it has come to light that a number of important data 
elements are missing from the lists in 40 CFR 98.36, and that some of 
the data elements on the lists are either not needed or require an 
excessive amount of non-essential data to be reported.
    To address these issues, we are proposing to amend the data element 
lists in 40 CFR 98.36 by adding a number of essential data elements and 
eliminating or modifying others. The most significant revisions to the 
data element lists are discussed in paragraphs (a) through (g), below. 
We are also proposing to add an additional alternative reporting option 
to 40 CFR 98.36(c) to reduce the reporting burden for certain 
facilities. This option is described in paragraph (h), below.
    (a) We are proposing to add the reporting of methodology start and 
end dates in several places throughout 40 CFR 98.36(b), (c), and (d). 
These data elements are needed to accommodate changes in the methods 
used to calculate GHG emissions, when such changes occur during a 
reporting year or from one year to the next.
    (b) We are proposing to amend the data element lists in 40 CFR 
98.36 to be consistent with respect to reporting of emissions by fuel 
type and reporting of biogenic CO2 emissions.
    (c) We are proposing to amend 40 CFR 98.36(b)(10) to remove the 
requirement to report the customer meter number for units that combust 
natural gas.
    (d) We are proposing to amend a number of data elements to reduce 
the reporting burden. For example, when small combustion units are 
aggregated into a group, 40 CFR 98.36(c)(1)(ii) currently requires the 
ID number of each unit in the group to be reported. This requirement is 
unreasonable for facilities that have large numbers of very small 
combustion sources, many of which do not have unique ID numbers. We 
are, therefore, proposing to amend this data element to require that 
only the total number of units in the group be reported, instead of the 
ID number of each unit in the group. As a second example, for the 
common pipe option described in 40 CFR 98.36(c)(3), only the total 
number of units served by the common pipe would be reported, instead of 
reporting an ID number for each unit, and only the highest maximum 
rated heat input capacity of any unit served by the common pipe would 
be reported, rather than reporting the rated heat input capacity of 
each individual unit.
    (e) We are proposing to amend 40 CFR 98.36 to remove the 
requirement to report the combined annual GHG emissions from fossil 
fuel combustion in metric tons of CO2e (i.e., the sum of the 
CO2, CH4, and N2O emissions) from 40 
CFR 98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data 
elements are duplicative of requirements in subpart A.
    (f) We are proposing to amend 40 CFR 98.36(b), (c), and (d) to 
require reporting the fuel-specific annual heat input estimates, for 
the purpose of verifying the reported CH4 and N2O 
emissions. Also, we are proposing to amend 40 CFR 98.36(e)(2)(iv) to 
require reporting of the annual average HHV when measured HHV data are 
used to calculate CH4 and N2O emissions for a 
Tier 3 unit, in lieu of using a default HHV from Table C-1.
    (g) We are proposing to amend 40 CFR 98.36(b) and (d) to make the 
data elements reported under Tiers 1 through 4 consistent for the 
reporting of biogenic CO2 emissions and CO2 from 
fossil fuel combustion. Also, as previously noted in section III.C of 
this preamble, the proposed amendments to 40 CFR 98.36(d) would state 
that reporting of biogenic CO2 emissions is optional for 
units using the CO2 mass emissions calculation methods in 40 
CFR Part 75.
    (h) For units that use the Tier 4 methodology to calculate 
CO2 mass emissions, we are proposing to amend 40 CFR 
98.36(b)(7)(i) and (b)(7)(ii) (redesignated as 40 CFR 98.36(b)(9)(i) 
and (b)(9)(ii), respectively) and 40 CFR 98.36 (c)(2)(vi) (redesignated 
as 40 CFR 98.36 (c)(2)(viii)). The proposed amendments to these 
sections will require the annual ``non-biogenic'' CO2 mass 
emissions to be reported instead of reporting the annual CO2 
mass emissions from fossil fuel combustion.

[[Page 48763]]

These revisions are being proposed because the total annual 
CO2 mass emissions measured by CEMS sometimes includes 
CO2 from sorbent or process CO2 emissions in 
addition to CO2 from fossil fuel combustion. The effect of 
the proposed amendments would be to simplify reporting for Tier 4 units 
that have sorbent or process CO2 emissions in the flue gas 
stream. These units would be required only to report the combined 
annual non-biogenic CO2 mass emissions, rather than having 
to separately account for the fossil CO2 emissions. Tier 4 
units that do not have any sorbent or process CO2 emissions 
in the flue gas would be unaffected by these proposed revisions, 
because their non-biogenic CO2 emissions are entirely from 
fossil fuel.
    (i) We are proposing to add a new alternative reporting option, 
under 40 CFR 98.36(c)(4). This new option would apply to specific 
situations where a common liquid or gaseous fuel supply is shared 
between large combustion units such as boilers or combustion turbines 
(including Acid Rain Program units and other combustion units that use 
the methods in 40 CFR Part 75 to calculate CO2 mass 
emissions), and small combustion sources such as space heaters, hot 
water heaters, etc. In such cases, you could simplify reporting by 
attributing all of the GHG emissions from combustion of the shared fuel 
to the large combustion unit(s), provided that:
     The total quantity of the shared fuel supply that is 
combusted during the report year is measured, either at the ``gate'' to 
the facility or at a point inside the facility, using a fuel flow 
meter, a billing meter or tank drop measurements; and
     On an annual basis, at least 95 percent of the shared fuel 
supply (by mass or volume) is burned in the large combustion unit(s) 
and the remainder of the fuel is fed to the small combustion sources.

Use of company records would be allowed to determine the percentage 
distribution of the shared fuel to the large and small units. 
Facilities using this reporting option would be required to document in 
their monitoring plan which units share the common fuel supply and the 
method used to determine that the reporting option applies. For the 
small combustion sources, a description of the type(s) and approximate 
number of units involved would suffice.
    (j) Finally, we are proposing to simplify the record keeping 
requirements in 40 CFR 98.36(e)(2)(iii), in cases where the results of 
fuel analyses for HHV are provided by the fuel supplier. Parallel 
language would be added in a new paragraph, (e)(2)(v)(E), for the 
results of carbon content and molecular weight analyses received from 
the fuel supplier. In both cases, the owner or operator would be 
required to keep records of only the dates on which the fuel sampling 
results are received, rather than keeping records of the dates on which 
the supplier's fuel samples were taken (which dates may not be readily 
available).
    We believe that these proposed amendments to the recordkeeping and 
reporting requirements of 40 CFR 98.36 are needed for data verification 
purposes. The proposed amendments are not likely to increase the 
reporting burden on industry. In some cases, as previously noted, the 
proposed amendments would actually reduce the amount of information 
that must be collected or reported and the associated burden.
    Common Stack Reporting Option. Section 98.36(c)(2) of subpart C 
currently allows Subpart C stationary fuel combustion units that share 
a common stack or duct to use the Tier 4 Calculation Methodology to 
monitor and report the combined CO2 mass emissions at the 
common stack or duct, in lieu of monitoring each unit individually. 
However, 40 CFR 98.36(c)(2) does not address circumstances where at 
least one of the units sharing the common stack is not a Subpart C 
stationary fuel combustion unit, but is subject to another subpart of 
Part 98. For example, if a Subpart G ammonia manufacturing unit shares 
a common stack with a Subpart C stationary combustion unit, the use of 
Tier 4 may be required (see 40 CFR 98.73(c)).
    In view of this, we are proposing to amend 40 CFR 98.36(c)(2) by 
extending the applicability of the common stack monitoring and 
reporting option to situations where off-gases from multiple process 
units or mixtures of combustion products and process off-gases are 
combined together and vented through a common stack or duct.
    The proposed amendments to 40 CFR 98.36(c)(2) would not only apply 
to ordinary common stack or duct situations where the gas streams from 
multiple units are combined together, but would also apply when process 
and combustion gas streams from a single unit (e.g., from a kiln, 
furnace, or smelter) are combined. To accommodate this variation on the 
traditional concept of a common stack, 40 CFR 98.36(c)(2)(ii) would be 
amended to require sources to report ``1'' as the ``Number of units 
sharing the common stack or duct'' when process and combustion 
emissions from a single unit are combined and vented through the same 
stack or duct.
    Finally, since the concept of maximum rated heat input capacity may 
not be applicable to certain types of process or manufacturing units, 
we are proposing to amend 40 CFR 98.36(c)(2)(iii), to require that the 
``Combined maximum rated heat input capacity of the units sharing the 
common stack or duct'' only be reported when all of the units sharing 
the common stack or duct are stationary fuel combustion units.
    Common Fuel Supply Pipe Reporting Option. Section 98.36(c)(3) of 
subpart C currently allows units that are served by a common fuel 
supply pipe to report the combined CO2 emissions from all of 
the units in lieu of reporting CO2 emissions separately from 
each unit. To use this reporting option, the total amount of fuel 
combusted in the units must be accurately measured with a flow meter 
calibrated according to the requirements in 40 CFR 98.34. Section 
98.36(c)(3) also states that the applicable Tier to use for this 
reporting option is based on the maximum rated heat input of the 
largest unit in the group.
    We are proposing to amend 40 CFR 98.36(c)(3) as follows. First, the 
erroneous citation of ``Sec.  98.34(a)'' would be corrected to read 
``Sec.  98.34(b).'' Second, we are proposing to amend the requirement 
in 40 CFR 98.36(c)(3) to calibrate the fuel flow meter to the accuracy 
required by 40 CFR 98.34(b) (which cross-references the accuracy 
specifications in 40 CFR 98.3(i)), so that this calibration requirement 
would apply only when Tier 3 is the required tier for calculating 
CO2 mass emissions. The Agency believes that this 
clarification is needed, since the common pipe option can apply to Tier 
1, 2, or 3, depending on the rated heat input capacities of the units 
served by the common pipe. Tiers 1 and 2 rely on company records to 
quantify fuel usage. Therefore, as noted in today's proposed amendments 
to 40 CFR 98.3(i), the equipment used to generate company records under 
Tier 1 and 2 is not required to meet the calibration accuracy 
specifications of 40 CFR 98.3(i).
    As previously noted, the applicable measurement Tier for the common 
pipe option, according to subpart C, is based on the rated heat input 
capacity of the largest unit in the group. On the surface, this appears 
to mean that the use of Tiers 1 and 2 is restricted to common pipe 
configurations where the highest rated heat input capacity of any unit 
is

[[Page 48764]]

250 mmBtu/hr or less, and that Tier 3 is required if any unit has a 
maximum rated heat input capacity greater than 250 mmBtu/hr. In 
general, this is true. However, there is one exception in the current 
rule and we are proposing to add a second one. First, 40 CFR 
98.33(b)(2)(ii) allows the use of Tier 2 instead of Tier 3 for the 
combustion of natural gas and/or distillate oil in a unit with a rated 
heat input capacity greater than 250 mmBtu/hr. Second, proposed 40 CFR 
98.33(b)(1)(v) would allow Tier 1 to be used when natural gas 
consumption is determined from billing records, and fuel usage on those 
records is expressed in units of therms. Therefore, we are also 
proposing to amend 40 CFR 98.36(c)(3) to reflect these two exceptions 
for common pipe configurations that include a unit with a maximum rated 
heat input capacity greater than 250 mmBtu/hr.
    Finally, we are proposing to amend the provision in 40 CFR 
98.36(c)(3) regarding the partial diversion of a fuel stream such as 
natural gas that is measured ``at the gate'' to a facility, (e.g., 
using a calibrated flow meter or a gas billing meter). Subpart C 
specifies that when part of a fuel stream is diverted to a chemical or 
industrial process where it is used but not combusted, and the 
remainder of the fuel is sent to a group of combustion units, you may 
subtract the diverted portion of the fuel stream from the total 
quantity of the fuel measured at the gate before applying the common 
pipe methodology to the combustion units. We are proposing to expand 
this provision to include cases where the diverted portion of the fuel 
stream is sent either to a flare or to another stationary combustion 
unit (or units) on-site, including units that use Part 75 methodologies 
to calculate annual CO2 mass emissions (e.g., Acid Rain 
Program units). Provided that the GHG emissions from the flare and/or 
other combustion unit(s) are properly accounted for according to the 
applicable subpart(s) of Part 98, you would be allowed to subtract the 
diverted portion of the fuel stream from the total quantity of the fuel 
measured at the gate, and then apply the common pipe reporting option 
to the group of combustion units served by the common pipe, using the 
Tier 1, Tier 2, or Tier 3 calculation methodology (as applicable).
    Table C-1. Table C-1 of Subpart C provides default HHV values and 
default CO2 emission factors for various types of fuel. 
These default values are needed to calculate CO2 mass 
emissions when the Tier 1 and Tier 2 methodologies in 40 CFR 98.33(a) 
are used. The fuels listed in Table C-1 are grouped into general 
categories (e.g., coal and coke, petroleum products, biomass fuels). 
Some distinctions are made within these categories, based on the state 
of matter (e.g., biomass fuels--liquid, fossil fuel-derived fuels 
(solid), etc.).
    Since publication of the final Part 98, EPA has received many 
questions about the content and structure of Table C-1. Owners and 
operators in various industries have raised a number of issues 
concerning the way that fuels are categorized, the description of 
certain fuels, the units of measure of some of the default HHV values, 
and the absence of some fuels that were listed in Table C-2 of the 
April 10, 2009 proposed rule. In particular:
    (a) The categories ``fossil fuel-derived fuels (solid)'' and 
``fossil fuel-derived fuels (gaseous)'' did not appear in the April 10, 
2009 proposed rule and have been the source of some confusion. For 
instance, only two fuels, MSW and tires, are listed under ``fossil 
fuel-derived fuels (solid),'' and neither of these is derived entirely 
from fossil fuels. Both of these fuels have a biogenic component. There 
are also only two fuels, blast furnace gas and coke oven gas, listed in 
the ``fossil fuel-derived fuels (gaseous)'' category. Several other 
fuels that are derived from petroleum and qualify as fossil fuel-
derived gaseous fuels (e.g., still gas) are listed in a different 
category, ``petroleum products.''
    (b) Questions have arisen about the revised description of 
``natural gas'' in Table C-1. The word ``pipeline,'' which was not in 
the April 10, 2009 proposed rule, was added in the final subpart C.
    (c) The Agency has received questions about the meaning of the 
terms ``wood residuals,'' ``solid byproducts,'' and ``agricultural 
byproducts,'' none of which appeared in the April 10, 2009 proposed 
rule.
    (d) Questions have been asked why certain fuels that were listed in 
Table C-2 of the April 10, 2009 proposed rule do not appear in Table C-
1. These include waste oil and plastics.
    (e) Owners and operators have questioned the appropriateness of the 
units of measure for still gas listed under ``petroleum products.'' The 
HHV for still gas, which is in the gaseous state at ambient 
temperatures, is given in mmBtu per gallon, as though it were in the 
liquid state.
    (f) Some industry questions indicate that reporters believe that 
the footnote beneath Table C-1 appears to prohibit MWC units that 
produce steam from using the default CO2 emission factor in 
the Table. This emission factor is needed to apply the Tier 2 
CO2 emissions calculation methodology (specifically, 
Equation C-2c) to those units.
    (g) EPA has received questions regarding the significance of 
indicating one hundred percent for ethanol and biodiesel, as well as 
questions regarding which emission factors to use for petroleum-derived 
ethanol.
    In view of these considerations, we are proposing the following 
revisions to Table C-1:
     The categories ``fossil fuel-derived fuels (solid)'' and 
``fossil fuel-derived fuels (gaseous)'' would be replaced with more 
inclusive terms, i.e., ``other fuels (solid)'' and ``other fuels 
(gaseous).'' The ``other fuels (solid)'' category would include four 
fuels: Plastics, municipal solid waste, tires, and petroleum coke. The 
``other fuels (gaseous)'' category would include blast furnace gas, 
coke oven gas, propane gas, and fuel gas.
     The word ``pipeline'' would be removed from the 
description of natural gas.
     The following fuels: ``wood residuals,'' ``agricultural 
byproducts,'' and ``solid byproducts'' would be retained, but 
definitions of these terms would be added to 40 CFR 98.6.
     ``Waste oil'' would be added to the list of petroleum 
products, and a definition would be added to 40 CFR 98.6.
     Still gas would be removed from the list of petroleum 
products.
     The footnote regarding MWC units would be revised to make 
it clear that MWC units that produce steam are only prohibited from 
using the default HHV for MSW in Table C-1; MWC units that produce 
steam can still use the default CO2 emission factor for MSW.
     The qualifier of one hundred percent for ethanol and 
biodiesel would be removed since these fuel types should be treated in 
the same way as other fuel types included in Table C-1. Removing this 
qualifier would clarify this without affecting any other provisions the 
rule.
     A default CO2 emission factor and a default 
high heat value would be added to the Table for petroleum-derived 
ethanol. These would be the same as the default values for biomass-
derived ethanol.
    We are soliciting comment on these proposed amendments to Table C-
1. Specifically, we request comment on: (1) The new and revised fuel 
categories; (2) the appropriateness of the HHVs and CO2 
emission factors for the fuels listed in these categories; and (3) 
whether additional fuels should be included in Table C-1, and if so, 
what the HHVs and CO2 emission factors for those fuels 
should be.

[[Page 48765]]

    Table C-2. In the October 30, 2009 publication of Part 98, two 
essentially identical iterations of Table C-2 of Subpart C were 
printed. The first iteration of Table C-2 was a printing error. We are 
proposing to remove the first iteration of the Table and to make minor 
corrections to the second one. The proposed amendments consist of 
correcting the exponents of the emission factors. The powers of ten in 
the right-hand column of the Table currently have an ``underscore'' 
character where there should be a minus sign, and one of the exponents 
is missing a zero.
    Miscellaneous Proposed Revisions. In addition to the more 
substantive proposed amendments to Subpart C, we are proposing to 
correct a number of typographical errors, and to re-word the rule text 
in a few places for added clarity. We are also proposing to amend 40 
CFR 98.34(c) by adding the citations from 40 CFR Part 75 that pertain 
to the initial certification of Tier 4 moisture monitoring systems. 
Although these rule citations were inadvertently omitted from the 
October 30, 2009 publication of Part 98, we believe that Tier 4 sources 
understand that all required CEMS, including moisture monitoring 
systems, must be initially certified.
    How Would These Amendments to Subpart C Apply to the 2011 GHG 
Emissions Reports? EPA plans to address the comments on the proposed 
amendments to Subpart C and to publish the final amendments before the 
end of 2010. Therefore, reporters would be expected to use provisions 
of Part 98, as amended, to collect the relevant data and to calculate 
GHG emissions for the reports that are submitted in 2011. We believe it 
is feasible for the sources to use the proposed changes to Subpart C 
for the 2010 reporting year, because the proposed revisions, to a great 
extent, simply clarify existing regulatory requirements. Further, the 
proposed amendments do not substantially affect the type of information 
that must be collected or how emissions are calculated.
    The following are examples of how the proposed amendments to 
Subpart C would clarify existing regulatory requirements. The 
amendments would clarify:
     That reporting of biogenic CO2 emissions is 
optional for units using the CO2 mass emissions calculation 
methodologies in 40 CFR Part 75.
     How CH4 and N2O emissions are 
calculated for multi-fuel units that use the Tier 4 CO2 mass 
emissions calculation methodology.
     How to determine whether Tier 4 applies to various common 
stack configurations.
     How to determine which Tier (i.e., 1, 2, or 3) applies to 
common pipe configurations.
     How to calculate biogenic emissions for various types of 
units and fuels. Unnecessary restrictions on the use of certain 
calculation methods would be removed.
     How to apply the definition of a ``fuel lot'' at 
facilities that receive frequent deliveries of coal or fuel oil.
     How to calculate CO2, CH4, and 
N2O emissions for blended fuels.
    The proposed amendments to 40 CFR 98.36, the data reporting section 
of Subpart C, would achieve two main purposes: (1) To ensure that 
enough data are provided to enable the Agency to recalculate and verify 
the emissions data; and (2) to reduce burden, by removing the 
requirement to report certain non-essential data elements and by 
modifying other data elements.
    For example, the proposed amendments would:
     Require methodology start and end dates to be reported. 
This will enable us to track changes in emissions calculation 
methodologies (e.g., switching from a lower Tier to a higher Tier).
     Generally require reporting of fuel-specific 
CH4 and N2O emissions. This requirement was 
inconsistently applied in Part 98.
     Eliminate the need to report individual unit ID numbers 
and unit heat input capacities for groups of aggregated units, common 
pipe configurations, and common stack configurations.
     Remove the unnecessary requirement to report unit-level 
combined CO2, CH4, and N2O emissions 
from fossil fuel combustion.
     Remove the requirement for natural gas users to report 
their customer meter ID numbers.
     Emphasize that biogenic CO2 emissions reporting 
is optional for Part 75 units.
    EPA believes that amendments such as these can be implemented for 
the reports submitted to EPA in 2011 because the proposed changes are 
either consistent with or have no significant effect upon the 
calculation methodologies in Part 98. Since owners or operators are not 
required to report until March 2011, which is several months after we 
expect this proposal to be finalized, sources should have sufficient 
time to adjust to the revisions.
    Several other proposed amendments to Subpart C address issues 
identified as a result of working with the affected sources during rule 
implementation. These proposed amendments would add flexibility to the 
rule. Owners or operators would be free to implement these new rule 
provisions once they are finalized. The following are examples of how 
today's proposed Subpart C amendments would make the rule more 
flexible. The proposed amendments would:
     Allow fuel flow meters that measure on a mass basis to be 
used for gaseous fuels as well as liquid fuels, provided that the flow 
rate measurements are corrected for density.
     Allow the span of CO2 monitors to be set higher 
than 20 percent CO2 if necessary, when process 
CO2 and combustion CO2 emissions exit to the 
atmosphere through a common stack.
     Allow the use of site-specific default moisture values for 
Tier 4 units that measure CO2 concentration on a dry basis.
     Provide a new Tier 1 equation for calculating 
CO2 mass emissions when fuel usage data obtained from gas 
billing records is expressed in units of therms.
     Allow smaller Tier 2 units (less than 100 mmBtu/hr) that 
receive monthly (or more frequent) HHV data to use an arithmetic 
average annual HHV in the emissions calculations instead of a fuel-
weighted average HHV.
     Allow Tier 4 units to use an alternative (non-CEMS) method 
to account for the volumetric flow rate of a slip stream, when a 
portion of the flue gas is diverted and exhausts through a separate 
stack.
     Allow fuel oil sampling to be performed upon each addition 
of oil to the storage tank, as an alternative to sampling each fuel 
lot.
     Remove the lists of specific methods for determining HHV 
and carbon content and for fuel flow meter calibration, and specify 
instead that sources must either use appropriate methods from consensus 
standards organizations if such methods exist, or standard industry 
practice.
     Add a new reporting option for configurations in which a 
common supply of gaseous or liquid fuel is shared between large 
combustion units and a group of smaller units such as space heaters, 
hot water heaters, etc. If at least 95 percent of the shared fuel is 
used by the large units, 100 percent of the GHG emissions from 
combustion of that fuel may be attributed to the large units.
    In some cases, facilities may have been following their current 
data collection practices during 2010, as well as using the methods 
required by Part 98. If a facility's current practice provides the 
necessary data to implement the new options described immediately 
above, or if such data could be obtained and processed prior

[[Page 48766]]

to the March 31, 2011 reporting deadline, the new options could be used 
for the reports submitted to EPA in 2011.
    Finally, the proposed amendments would make minor corrections to 
terms and definitions in certain Subpart C equations, and other 
technical corrections that would have no impact on facility's data 
collection efforts in 2010.
    In summary, EPA believes that, in general, the proposed amendments 
to Subpart C would not require monitoring or information collection 
above what is already required by Part 98. Therefore, we expect that 
sources will be able to use the same information that they have been 
collecting under Part 98 to calculate and report GHG emissions for 
2010.
    EPA seeks comment on its conclusion that the amendments to Subpart 
C can be implemented and incorporated into the initial GHG emissions 
reports by the due date of March 31, 2011. Specifically, we seek 
comment on whether this timeline is feasible or appropriate, 
considering the nature of the proposed changes and the way in which 
data have been collected thus far in 2010. We request that commenters 
provide specific reasons why they believe that the proposed 
implementation schedule would or would not be feasible.

H. Subpart D (Electricity Generation)

    We are proposing to amend 40 CFR 98.40(a) by adding the word 
``mass'' between the words ``CO2'' and ``emissions'' to make 
it clear that Subpart D applies only to units in two categories: (a) 
ARP units; and (b) non-ARP electricity generating units (EGUs) that are 
required to report CO2 mass emissions data to EPA year-
round. At present, category ``(b)'' includes only non-ARP units that 
are subject to the Regional Greenhouse Gas Initiative (RGGI) in the 
northeastern United States.
    Many non-ARP EGUs that are not in the RGGI are subject to the Clean 
Air Interstate Rule (CAIR). Some of these CAIR units report 
CO2 concentration data to EPA year-round, for the purposes 
of calculating NOX emission rates in lb/mmBtu and/or heat 
input rates in mmBtu/hr. However, they do not report CO2 
mass emissions data to the Agency. Therefore, they are subject to 
Subpart C of Part 98, not Subpart D.
    Data Reporting Requirements. Section 98.46 of subpart D currently 
specifies that the owner or operator of a Subpart D unit must comply 
with the data reporting requirements of 40 CFR 98.36(b) and, if 
applicable, 40 CFR 98.36(c)(2) or (c)(3). These section citations are 
incorrect. Subpart D units all use the CO2 mass emissions 
calculation methodologies in 40 CFR Part 75. Therefore, the applicable 
data reporting section for these units is 40 CFR 98.36(d), not 40 CFR 
98.36(b), 40 CFR 98.36(c)(2), or 40 CFR 98.36(c)(3). We are proposing 
to amend 40 CFR 98.46 to correct this error.
    Recordkeeping. We are proposing to amend 40 CFR 98.47 to state that 
the records kept under 40 CFR 75.57(h) for missing data events satisfy 
the recordkeeping requirements of 40 CFR 98.3(g)(4) for those same 
events. We believe that, as a practical matter, the missing data 
records required to be kept under 40 CFR 75.57(h) are substantially 
equivalent to the records required under 40 CFR 98.3(g)(4).

I. Subpart F (Aluminum Production)

    Throughout Subpart F we are proposing corrections as needed for 
typographical errors and alphanumeric sequencing. We are proposing to 
amend 40 CFR 98.63, Calculating GHG Emissions, to clarify that each 
perfluorocarbon (PFC) compound (CF4, 
C2F6) must be quantified and reported and to 
clarify in 40 CFR 98.63(c) that reporters must use CEMS if the process 
CO2 emissions from anode consumption during electrolysis or 
anode baking of prebake cells are vented through the same stack as a 
combustion unit required to use CEMS. This requirement existed in the 
final rule, however, the cross-reference was omitted from the 
introductory language of 40 CFR 98.63(c).
    We are proposing to amend 40 CFR 98.64, Monitoring and QA/QC, to 
clarify the type of parameters that must be measured in accordance with 
the recommendations of the EPA/IAI Protocol for Measurement of 
Tetrafluoromethane (CF4) and Hexafluoroethane 
(C2F6) Emissions from Primary Aluminum Production 
(2008), and the frequency of monitoring for those parameters which are 
not measured annually, but are instead measured on a more or less 
frequent basis. We are proposing a modification to Table F-2 to clarify 
that default CO2 emissions from pitch volatiles combustion 
are relevant only for center work pre-bake (CWPB) and side work pre-
bake (SWPB) technologies.
    We are also proposing to amend Table F-1 to spell out the acronyms 
for the technologies covered by that table; i.e., CWPB, side worked 
prebake (SWPB), vertical stud S[oslash]derberg (VSS), and horizontal 
stud S[oslash]derberg (HSS).

J. Subpart G (Ammonia Manufacturing)

    We are proposing to amend subpart G to remove reporting of the 
waste recycle stream or purge, and to make subpart G conform to the 
proposed amendments to the calibration requirements in Subpart A. With 
respect to the waste recycle stream, we are proposing to eliminate the 
calculation, monitoring and reporting of the emissions associated with 
the waste recycle stream or purge currently required by Equation G-6 
from 40 CFR 98.73, 98.74, 98.75, and 98.76. Carbon dioxide emissions 
from waste recycle stream or purge gas used as fuel will still be 
accounted for accurately using Equation G-5 in Subpart G. Because total 
process emissions, calculated using Equation G-5, will also account for 
emissions associated with use of the purge gas as a fuel, we are 
proposing to amend 40 CFR 98.72(b) so that subpart C does not apply to 
CO2 emissions resulting from the use of purge gas as a fuel.
    With respect to calibration requirements, we are proposing to 
clarify the calibration requirements for gas and oil flow meters used 
in the ammonia manufacturing process. Section 98.74(d) of subpart G 
currently states that all oil and gas flow meters except for gas 
billing meters must be calibrated according to the requirements for the 
Tier 3 methodology in 40 CFR 98.34(b). The Agency believes that the 
words ``all oil and gas flow meters'' in this subpart G provision are 
too inclusive and subject to misinterpretation. Therefore, we are 
proposing to amend 40 CFR 98.74(d) to limit the flow meter calibration 
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to only meters 
that are used to measure liquid and gaseous feedstock volumes. In 
accordance with 40 CFR 98.3(i)(1), each measurement device that is not 
used to measure liquid and gaseous feedstock volumes, but is used to 
provide data for the GHG emissions calculations would have to be 
calibrated to an accuracy within the appropriate error range for the 
specific measurement technology, based on an applicable operating 
standard, such as the manufacturer's specifications.
    We are proposing to note through parentheticals in a number of 
places that the CO2 emissions estimates may include 
CO2 that is later consumed on-site for urea production and 
therefore not released to the atmosphere from the ammonia manufacturing 
process unit. This proposed change does not impact the total 
CO2 emissions that are quantified and reported to EPA under 
the calculation equations in 40 CFR 98.73. The clarification is 
proposed so

[[Page 48767]]

that it is transparent for stakeholders who ultimately use these data 
that some CO2 process emissions reported by the ammonia 
manufacturing process unit under this subpart may not be released from 
ammonia manufacturing, but at the point of urea application. To further 
enhance this transparency, EPA is also proposing to require reporting 
under 40 CFR 98.76 of the CO2 from the ammonia manufacturing 
process unit that is then used to produce urea and the method used to 
determine that quantity of CO2 consumed.
    In addition, we are proposing to amend Subpart G to correct several 
typographical errors and an incorrect cross-reference to another 
subpart in Part 98. We are proposing to correct the terms and 
definitions for annual CO2 emissions arising from gaseous, 
liquid, and solid fuel feedstock consumption in Equations G-1, G-2, and 
G-3, respectively, in 40 CFR 98.73. We are proposing to correct 40 CFR 
98.76(a) by changing the cross-reference from ``Sec.  98.37(e)(2)(vi)'' 
to ``Sec.  98.37.''
    We are proposing to amend the data reporting requirements in 40 CFR 
98.76(b)(6) and (15) for consistency with the calculation procedures in 
40 CFR 98.73(b)(6). We are proposing to amend 40 CFR 98.76(b)(6) to 
change ``petroleum coke'' to ``feedstock'' because petroleum coke is 
the incorrect term, and to amend 40 CFR 98.76(b)(15) to specify that 
the carbon content analysis method being reported is for each month.
    We are proposing to remove 40 CFR 98.76(b)(17) for the reporting of 
urea produced, if known. EPA finalized reporting of this information to 
help improve methodologies for calculating emissions from ammonia 
manufacturing, urea production and urea consumption. Reporters stated 
that these data are already reported periodically to EPA under the 
Toxic Substances Control Act (TSCA) Inventory Update Rule (IUR). 
Although the TSCA IUR does not provide the full range of information 
that may ultimately be useful for informing future policy, EPA believes 
that the TSCA IUR provides adequate information at this time and, 
therefore, we are proposing to delete that requirement.
    Finally, 40 CFR part 98, subpart G (Ammonia Manufacturing) and 
subpart V (Nitric Acid Production) require that facilities report total 
pounds of synthetic fertilizer and total nitrogen contained in that 
fertilizer. After considering additional information provided by 
stakeholders, as well as other available information, we are proposing 
to remove the requirement from both subparts. EPA's rationale for 
removing the requirement is as follows
    (i) The data that would be reported under these subparts do not 
provide directly applicable information with which to determine 
N2O emissions from application of fertilizer because the 
data are incomplete. Domestic producers of synthetic nitrogen-based 
fertilizer make up less than one-half of the total amount of synthetic 
nitrogen-based fertilizer used in the United States. The remaining 
share is made up by synthetic nitrogen-based fertilizer imports, as 
well as fertilizer produced domestically outside of the Nitric Acid and 
Ammonia production industries using imported ammonia and nitric acid.
    (ii) EPA has information on the total supply and use of synthetic 
nitrogen-based fertilizer from other data sources that addresses near-
term analytical needs, particularly for calculating national emissions 
of N2O. We obtain current sales data from Association of 
American Plant Food Control Officials (AAPFCO). The sales data is 
equivalent to fertilizer application since the sales are from the last 
licensed dealer.
    EPA remains very interested in obtaining better data on 
N2O emissions. Nitrous oxide emissions from agricultural 
soils are an important source of greenhouse gas emissions in the United 
States (approximately 3 percent in 2008), and the application to soils 
of synthetic nitrogen-based fertilizer represents 26 percent of total 
N2O emissions from this source.
    EPA will continue to assess the need for a fertilizer reporting 
requirement from domestic producers in the future in light of new 
information or identification of policy or program needs. Further, EPA 
recognizes that States play an important role in collecting the data 
EPA currently uses, and the AAPFCO has indicated in a published article 
that recent stresses on state budgets potentially threaten the 
continued availability of these data.\3\ If data collection is 
compromised further due to reduced state funding or other 
circumstances, EPA will need to initiate a fertilizer reporting 
requirement.
---------------------------------------------------------------------------

    \3\ D. Terry, 2006. ``Fertilizer Tonnage Reporting in the U.S.--
Basis and Current Need.'' Better Crops. 90(4). pp 14-17.
---------------------------------------------------------------------------

    EPA will also assess the need for information on the total supply 
of synthetic nitrogen-based fertilizer, including imports, production 
of fertilizer using imported feedstock, domestically-produced 
fertilizer that is not in the agriculture sector, and fertilizer 
exports.
    Additionally, EPA will also assess the need for other types of 
information (i.e., not related to fertilizer supply) relevant to 
determining emissions and assessing mitigation opportunities for 
N2O emissions from agricultural soils, consistent with the 
Clean Air Act. Examples of other types of information that is relevant 
to N2O oxide emissions from agricultural soils can be found 
in the ``Technical Support Document for Biologic Process Sources 
Excluded from this Rule,'' and include elements such as fertilizer 
application rates, timing of application, and the use of slow-release 
fertilizers and nitrification/urease inhibitors (Docket ID No. EPA-HQ-
OAR-2008-0508).
    If EPA were to decide in the future to add a requirement to report 
fertilizer production under the Mandatory GHG Reporting Rule, or any 
other new requirement related to N2O emissions from 
agricultural soils, it would initiate a new rulemaking process.

K. Subpart P (Hydrogen Production)

    We are proposing several conforming amendments to be consistent 
with the proposed amendments to the calibration requirements of 40 CFR 
98.3(i). Section 98.164(b)(1) of subpart P currently specifies that all 
oil and gas flow meters (except for gas billing meters), solids 
weighing equipment, and oil tank drop measurements must be calibrated 
according to 40 CFR 98.3(i). We are proposing to amend 40 CFR 
98.164(b)(1) to make it consistent with today's proposed amendments to 
40 CFR 98.3(i). First, we would limit the flow meter calibration 
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to meters that 
are used to measure liquid and gaseous feedstock volumes. In accordance 
with 40 CFR 98.3(i)(1), all other measurement device that are used to 
provide data for the GHG emissions calculations would have to be 
calibrated to an accuracy within the appropriate error range for the 
specific measurement technology, based on an applicable operating 
standard, such as the manufacturer's specifications. Second, we would 
remove the requirements for solids weighing equipment and oil tank drop 
measurements to be calibrated according to 40 CFR 98.3(i), because the 
provisions of 40 CFR 98.3(i) would apply only to gas and liquid flow 
meters. For oil tank drop measurements, the QA requirements of 40 CFR 
98.34(b)(2) would apply.

L. Subpart V (Nitric Acid Production)

    We are proposing to amend 40 CFR 98.226 to remove the synthetic 
fertilizer and total nitrogen reporting requirement in 40 CFR 
98.226(o). The detailed rationale for this proposed amendment is 
provided in section II.K of this preamble.

[[Page 48768]]

M. Subpart X (Petrochemical Production)

    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart X for petrochemical production 
facilities. The issues being addressed by the proposed amendments 
include the following:
     Distillation and recycling of waste solvent.
     Process vent emissions monitored by CEMS.
     Process off-gas combustion in flares.
     CH4 and N2O emissions from 
combustion of process off-gas.
     Molar volume conversion (MVC) factors.
     Methodology for small ethylene off-gas streams.
     Monitoring and QA/QC requirements.
     Reporting requirements under the CEMS compliance option.
     Reporting requirements for the ethylene-specific option.
     Reporting measurement device calibrations.
    Distillation and Recycling of Waste Solvent. We are proposing to 
add a new paragraph 40 CFR 98.240(g) to specify that a process that 
distills or recycles waste solvent that contains a petrochemical is not 
part of the petrochemical production source category. Some processes 
that distill or recycle waste solvents may produce products that 
contain methanol or another petrochemical. Under the current subpart X, 
such processes might be considered part of the petrochemical source 
category because 40 CFR 98.240(a) specifies that all processes that 
produce a petrochemical are part of the source category unless 
specifically excluded. Although not specifically excluded in subpart X, 
we did not intend to include waste solvent purification processes in 
the petrochemical source category for the following reasons. First, in 
processes subject to subpart X, the petrochemical is formed from other 
chemicals, whereas in waste solvent purification processes the 
petrochemical is not formed because it is present in the feedstock. 
Second, processes that are in the source category generate significant 
amounts of process-based GHG emissions as byproducts of reaction and/or 
from the combustion of process off-gas for energy recovery. In 
contrast, the only process-based GHG emissions, if any, from waste 
solvent purification processes are from combustion of organic compounds 
in process vent emissions that are routed to a combustion-based air 
pollution control device.
    Process vent emissions monitored by CEMS. We are proposing to add a 
sentence to 40 CFR 98.242(a)(1) that specifies CO2 emissions 
from process vents routed to stacks that are not associated with 
stationary combustion units must be reported under subpart X when you 
comply with the CEMS option in 40 CFR 98.243(b). Section 98.242(a)(1) 
in the current subpart X specified that GHG emissions from stationary 
combustion sources and flares that burn any amount of petrochemical 
off-gas are to be reported under subpart X. However, we neglected to 
specify reporting requirements under the CEMS option for process 
emissions that are not associated with combustion units. The proposed 
amendment would correct this oversight.
    Process off-gas combustion in flares. We are proposing to amend 40 
CFR 98.242(b) by removing the reference to flares. Section 98.242(b) in 
subpart X specifies that CO2, CH4, and 
N2O combustion emissions from stationary combustion units 
and flares must be reported. However, the intent of 40 CFR 98.242(b) is 
to identify only the GHGs from the combustion of supplemental fuels 
that are to be reported under subpart C. Emissions from the combustion 
of petrochemical process off-gas in a flare are process-based emissions 
that are to be reported under subpart X as specified in 40 CFR 
98.242(a). Therefore, the reference to flares in 40 CFR 98.242(b) is 
incorrect and should be removed.
    CH4 and N2O Emissions From Combustion Of 
Process Off-Gas. We are proposing to amend 40 CFR 98.243(b) to clarify 
procedures for calculating CH4 and N2O emissions 
from combustion units that burn petrochemical process off-gas and are 
monitored with a CO2 CEMS. Section 98.243(b) in subpart X 
specifies that CH4 and N2O emissions from the 
non-flare combustion of petrochemical process off-gas are to be 
calculated using the Tier 3 procedures in subpart C, with the default 
emission factors for ``Petroleum'' in Table C-2 of subpart C. This 
procedure requires the use of equation C-8 to calculate the emissions. 
One of the inputs for this equation is the default HHV of the fuel, and 
default values for various fuels are listed in Table C-1 of subpart C. 
As discussed in section II.H of this preamble, we have added a default 
HHV for fuel gas in Table C-1, and we have revised the definition of 
HHV for equation C-8 to allow the use of a site-specific calculated HHV 
as an alternative to using a default value from Table C-1. Using either 
a default HHV or a site-specific calculated value is also acceptable 
when calculating CH4 and N2O emissions from the 
combustion of fuel gas that contains petrochemical process off-gas. 
Therefore, to clarify this point, we are proposing to add language to 
40 CFR 98.243(b) specifying that either the default HHV for fuel gas in 
Table C-1 or a site-specific calculated HHV is to be used in equation 
C-8 when calculating CH4 and N2O emissions.
    For the ethylene-specific option, 40 CFR 98.243(d) in subpart X 
specifies the same procedures for calculating CH4 and 
N2O emissions from non-flare combustion of process off-gas 
as in 40 CFR 98.243(b). Therefore, we are proposing the same change to 
40 CFR 98.243(d) as noted above for 40 CFR 98.243(b) to clarify that 
either the default HHV for fuel gas or a site-specific calculated HHV 
should be used for Tier 3 calculations.
    Molar volume conversion (MVC) factors. Owners and operators have 
requested that allowance be made for alternative standard conditions 
within the molar volume conversion factor (MVC) used in Equation X-1 in 
40 CFR 98.243(c). Equation X-1 of subpart X specified using an MVC of 
849.5 scf/kgmole, which converts the volumetric flow from standard 
cubic feet to kgmoles assuming the standard volume was determined at 68 
[deg]F. Exhaust stack volumes are generally corrected using 68 [deg]F 
as the standard temperature, and some petrochemical producers may also 
use 68 [deg]F when expressing process volumes at standard conditions. 
However, we recognize that the oil and gas industry and other 
hydrocarbon processing facilities commonly express gaseous volumes 
using 60 [deg]F as the standard temperature. Thus, many existing flow 
monitors for gaseous feedstocks and products at petrochemical 
facilities may be programmed to output volumes at standard conditions 
of 60 [deg]F. It is impractical and unnecessary to either reprogram 
these monitors to provide volumes corrected to standard conditions at 
68 [deg]F or to require reporters to convert the output volumes from 
one set of standard conditions to another before using Equation X-1 
because an alternative MVC can be provided to yield the identical mass 
emissions from the calculation.
    Consequently, we are proposing to amend Equation X-1 to provide two 
alternative values of MVC that correspond to the two most common 
standard conditions output by the flow monitors. Additionally, the 
reporting requirements related to this equation would be amended to 
include reporting of the standard temperature at which the gaseous 
feedstock and product volumes were determined (either 60 [deg]F or 68 
[deg]F) and to afford verification of the reported emissions.

[[Page 48769]]

    Methodology for small ethylene off-gas streams. Owners and 
operators have suggested that EPA should allow the use of alternative 
calculation methods for small emission sources. Specifically, they have 
asserted that units subject to only subpart C are allowed to use Tier 1 
or Tier 2 for units less than or equal to 250 mmbtu/hr heat input. 
However, if those same units are at a petrochemical production facility 
and combusting ethylene process off-gas, they are required to use Tier 
3 or Tier 4.
    We still believe that it is important to use Tier 3 or Tier 4 for 
most units that burn ethylene process off-gas because combustion of 
process off-gas is the primary source of GHG process emissions for 
ethylene processes, the carbon content may vary among facilities 
depending on the type of feedstock to the ethylene process units, and 
the ratio of ethylene process off-gas to other fuels may vary in each 
fuel gas system.
    However, we recognize that some ethylene process off gas that is 
burned in process heaters or boilers may not enter the fuel gas system 
and that the lines conveying these off-gas streams may not have flow 
monitors. For example, 40 CFR part 63, subpart YY, requires control of 
process vent emissions from ethylene production process units; these 
streams may be controlled by venting to a process heater or boiler, but 
subpart YY does not require monitoring of the vent stream flow rate. It 
was not our intent to require the installation of flow meters on these 
ancillary gas streams that do not significantly contribute to the 
overall heat input of the stationary combustion unit. In addition, we 
recognize that facilities may only meter the primary fuel flow at 
relatively large combustion units that are subject to emission 
limitations that are related to the heat input rate. About one-third of 
the ethylene production capacity is at petroleum refineries, and much 
of the rest is at large integrated chemical manufacturing facilities. 
Based on an analysis of process heaters at petroleum refineries (see 
section II.O of this preamble), it appears that process heaters less 
than 30 mmBtu/hr are often not subject to emission limitations and, 
therefore, may not have metered flow. Furthermore, such combustion 
units appear to represent only a small percentage of the total fuel use 
at refineries. Given the large size of most other chemical 
manufacturing facilities that make ethylene, it is likely that such 
combustion units represent only a small percentage of total fuel use at 
these facilities as well. Thus, easing the Tier 3 monitoring 
requirements for these small combustion units would reduce the 
compliance burden without significantly impacting the accuracy of the 
nationwide GHG emission inventories for ethylene production.
    Notwithstanding the above discussion, if a flow meter is installed 
in the fuel gas line, including any common pipe, then we consider that 
the Tier 3 monitoring requirements are reasonable and justified. In 
such cases there will not be a significant burden to use the Tier 3 
method, and the reported GHG emissions will be more accurate.
    Therefore, we are proposing to amend 40 CFR 98.243(d) to allow the 
use of Tier 1 or Tier 2 methods for small flows (in cases where a flow 
meter is not already installed). Specifically, we are proposing that 
Tier 1 or Tier 2 methods may be used for ethylene process off-gas 
streams that meet either of the following conditions:
    (1) The annual average flow rate of fuel gas (that contains 
ethylene process off-gas) in the fuel gas line to the combustion unit, 
prior to any split to individual burners or ports, does not exceed 345 
scfm at 60 [deg]F and 14.7 pounds per square inch absolute, psia, and a 
flow meter is not installed at any point in the line supplying fuel gas 
or an upstream common pipe; or
    (2) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr, and a flow meter is not installed at any point 
in the line supplying fuel gas (that contains ethylene process off-gas) 
or an upstream common pipe.
    This amendment would also specify how to calculate the annual 
average flow rate under the first condition. Specifically, the total 
flow obtained from company records is to be evenly distributed over 
525,600 minutes per year. We are also proposing a number of editorial 
changes to 40 CFR 98.243(d) to clearly integrate the proposed option 
with the existing requirements. Finally, we are proposing to amend 40 
CFR 98.246(c)(2) and 98.247(c) to add reporting and recordkeeping 
requirements that are related to the proposed amendments in 40 CFR 
98.243(d)(2).
    Monitoring Methods for Determining Carbon Content and Composition. 
Owners and operators have suggested that EPA should not limit the use 
of gas chromatograph methods for determining the carbon content, 
composition, and the average molecular weight of feedstocks and 
products to those methods listed in 40 CFR 98.244(b)(4). We are 
proposing to add the method, ``ASTM D2593-93 (Reapproved 2009) Standard 
Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas 
Chromatography,'' to 40 CFR 98.244(b)(4). Butadiene is a by-product of 
the ethylene production process, and after reviewing the method, we 
have determined that it is an acceptable method for determining the 
carbon content of that stream. We will consider including additional 
methods in the final amendments after reviewing comments on this issue. 
In order to evaluate this issue, we seek comments providing copies of 
calibration procedures that gas chromatograph manufacturers supply with 
their equipment, calibration procedures in any published or unpublished 
industry consensus (or site-specific) methods not currently listed in 
40 CFR 98.244(b)(4), and an assessment of how such procedures compare 
to the currently specified methods and why they are applicable for 
instruments used to measure petrochemical feedstocks and products.
    We are proposing to further amend 40 CFR 98.244(b)(4) by adding a 
new paragraph that would allow the use of industry consensus standard 
methods to determine the carbon content or composition of carbon black 
feedstock oils and carbon black products. Carbon black manufacturers 
have reported that none of the listed methods are specific to carbon 
black materials, and they have stated that such methods will provide 
less accurate results than modified versions of some of the methods. 
For example, the industry has reported that when they need to determine 
the carbon content of their feedstocks or products they often use 
modified versions of ASTM D5291-02. One difference is that the modified 
methods use carbon or carbon/sulfur analyzers instead of the carbon, 
hydrogen, and nitrogen analyzer that is specified in ASTM D5291-02. 
These modified methods have been submitted to ASTM for review. If ASTM 
publishes methods before the proposed amendments are finalized, we will 
consider including them in the final amendments. The industry has also 
reported that they often use other published methods to determine the 
sulfur, ash, and water content of the material and then calculate the 
carbon content as the difference between the mass of these compounds 
and the total mass of the sample. This approach would also be allowed 
under the proposed change to 40 CFR 98.244(b)(4). We seek comment on 
the need for the proposed option. In particular, we are interested in 
data that compare specified methods such as ASTM D5291-02 with industry 
consensus methods. We are also interested in

[[Page 48770]]

obtaining copies of industry consensus standard methods.
    We are also proposing to amend 40 CFR 98.244(b)(4) to provide 
facilities the option of, under certain circumstances, the use of 
alternative analytical methods in addition to the methods listed in 40 
CFR 98.244(b)(4)(i) through (b)(4)(xi) for determining the carbon 
content or composition of feedstocks or products. We recognize that the 
applicability of the methods listed in 40 CFR 98.244(b)(4)(i) through 
(b)(4)(xi) may be restricted for certain process streams due to the 
analytical limitations of those methods and/or the instrumentation. As 
a result, we are proposing to allow a facility to use an alternative 
analytical method in cases where the methods listed in 40 CFR 
98.244(b)(4)(i) through (b)(4)(xi) are not appropriate because the 
relevant compounds cannot be detected, the quality control requirements 
are not technically feasible, or use of the method would be unsafe.
    We are proposing to amend the reporting requirements in 40 CFR 
98.246(a)(11) so that if an alternative method is used, facilities 
would include in the annual report the name or title of the method 
used, and the first time it is used, a copy of the method and an 
explanation of why the use of the alternative method is necessary.
    We solicit comment on whether the flexibility provided by this 
option is needed. If commenters believe that to be the case, please 
provide information on the specific need for flexibility, why the 
existing listed analytical methods are not sufficient, and whether the 
proposed flexibility meets the needs identified.
    We are proposing to make the amendments to 40 CFR 98.244(b)(4) as 
described above retroactive to January 1, 2010. We have received 
feedback that some reporters are using a method currently allowed in 
Part 98 while concurrently also using a method that would be allowed by 
today's action. Should these amendments be finalized, making these 
amendments effective January 1, 2010 would allow reporters to use the 
results from the methods included in today's amendments for the entire 
year of 2010.
    QA/QC Requirements. As mentioned in Section II.B of this preamble, 
owners and operators have raised several issues regarding the 
calibration requirements in Part 98, and we are proposing a number of 
changes to 40 CFR 98.3(i) of subpart A to address those issues. To 
maintain consistency with the proposed amendments to 40 CFR 98.3(i), we 
are also proposing amendments to the QA/QC provisions for weighing 
devices, flow meters, and tank level measurement devices in paragraphs 
(b)(1), (b)(2), and (b)(3) of 40 CFR 98.244. Other proposed amendments 
to these paragraphs are editorial in nature and intended to clarify the 
requirements. Specific changes are as follows:
    In 40 CFR 98.244(b), each of the three subparagraphs incorrectly 
required compliance with calibration requirements in 40 CFR 98.3(i), or 
with any of the following: procedures specified by equipment 
manufacturers, industry consensus standard procedures, or procedures in 
listed methods. We are proposing to amend these subparagraphs such that 
the procedures in 40 CFR 98.3(i) would apply in addition to the other 
required procedures.
    We are proposing to amend 40 CFR 98.244(b)(1) to allow 
recalibration at the interval specified by the industry consensus 
standard practice used in addition to either biennially or at the 
minimum frequency specified by the manufacturer. Note that the 
requirements of 40 CFR 98.3(i) for other measurement devices would 
apply as well.
    Section 98.244(b)(2) in subpart X specifies that flow meters are to 
be operated and maintained using the procedures in 40 CFR 98.3(i) and 
either any one of several listed methods, a method published by a 
consensus-based standards organization, or procedures specified by the 
flow meter manufacturer. Although 40 CFR 98.244(b)(2) references 40 CFR 
98.3(i), it does not explicitly specify calibration requirements, and 
this reference incorrectly implies that 40 CFR 98.3(i) specifies 
procedures other than calibration requirements. In addition, the option 
to follow procedures in any of the listed methods is redundant because 
it overlaps with the option to use a method published by a consensus 
standards-based organization. To clarify these requirements we are 
proposing several amendments to 40 CFR 98.244(b)(2). One would specify 
that flow meters are to be operated and maintained according to 
manufacturer's recommended procedures. A second would specify that flow 
meters are to be calibrated following either an industry consensus 
standard practice or procedures specified by the flow meter 
manufacturer, and must meet the accuracy specification in 40 CFR 
98.3(i). Finally, the list of specified methods would be deleted.
    Section 98.244(b)(2) in subpart X specifies that flow meters are to 
be recalibrated either biennially or at the minimum frequency specified 
by the flow meter manufacturer. Since 40 CFR 98.244(b)(2) specifies 
that flow meters may be calibrated following procedures in industry 
consensus standard practices, we are proposing to also allow 
recalibration at the frequency specified in such methods. This would 
also make the recalibration requirements in 40 CFR 98.244(b)(2) 
consistent with the proposed amendment in 40 CFR 98.3(i)(1)(iii)(B).
    Section 98.244(b)(3) in subpart X specifies that tank level 
measurement devices are to be calibrated prior to the effective date of 
the rule. We are proposing to delete this statement because 40 CFR 
98.3(i) specifies the date by which initial calibration must be 
completed. Note that the requirements for other measurement devices in 
40 CFR 98.3(i) apply as well.
    Reporting Requirements Under The CEMS Compliance Option. We are 
proposing a number of changes in 40 CFR 98.246(b)(1) through (b)(5) to 
clarify the reporting requirements under the CEMS compliance option.
    First, we are proposing to move the requirement for reporting of 
the petrochemical process ID from 40 CFR 98.246(b)(3) to 40 CFR 
98.246(b)(1) to be consistent with the structure in other reporting 
sections, and we are renumbering the existing paragraphs (b)(1) and 
(b)(2).
    Second, we are proposing to add a statement in the renumbered 
paragraph 40 CFR 98.246(b)(2) to specify that the reporting 
requirements in 40 CFR 98.36(b)(9)(iii) (as numbered in today's 
proposed action) for CH4 and N2O do not apply 
under subpart X. This reporting requirement in subpart C is not 
relevant in subpart X because 40 CFR 98.246(b)(5) specifies the 
reporting requirements for CH4 and N2O under 
subpart X.
    Third, in the renumbered 40 CFR 98.246(b)(3), we are proposing to 
delete the requirement to report information required under 40 CFR 
98.36(e)(2)(vii) because the referenced section specifies recordkeeping 
requirements, not reporting requirements; note that you still must keep 
the applicable records because 40 CFR 98.247(a) references 40 CFR 
98.37, which in turn requires you to keep all of the applicable records 
in 40 CFR 98.36(e). We are also proposing to amend the reference to 40 
CFR 98.36(e)(2)(vii) to a more general reference of 40 CFR 98.36. This 
makes the reporting requirements consistent with the methodology for 
calculating emissions in 40 CFR 98.243(b).
    Fourth, we are proposing changes to 40 CFR 98.246(b)(4) to clarify 
our intent. The first sentence in 40 CFR 98.246(b)(4) requires 
reporting of the total CO2 emissions from each stack that

[[Page 48771]]

is monitored with CO2 CEMS; this requirement would be 
unchanged. We are proposing changes to the second sentence in 40 CFR 
98.246(b)(4) to clarify that for each CEMS that monitors a combustion 
unit stack you must estimate the fraction of the total CO2 
emissions that is from combustion of the petrochemical process off-gas 
in the fuel gas. This estimate will give an indication of the total 
petrochemical process emissions, whereas the CEMS data alone would also 
include emissions from combustion of supplemental fuel (if any).
    Finally, we are proposing several amendments to 40 CFR 
98.246(b)(5). In general, as noted above, the requirements in this 
paragraph are consistent with the requirements in 40 CFR 
98.36(b)(9)(iii) (as numbered in this proposed action). Most of the 
proposed amendments to 40 CFR 98.246(b)(5) restate requirements from 40 
CFR 98.36(b)(9)(iii); for example, the proposed amendments clarify that 
emissions are to be reported in metric tons of each gas and in metric 
tons of CO2e. However, because 40 CFR 98.36(b)(9)(iii) 
allows you to consider petrochemical process off-gas as a part of 
``fuel gas'' rather than as a separate fuel, 40 CFR 98.246(b)(5) also 
would require you to estimate the fraction of total CH4 and 
N2O emissions in the exhaust from each stack that is from 
combustion of the petrochemical process off-gas. In addition, because 
40 CFR 98.243(b) requires you to determine CH4 and 
N2O emissions using Equation C-8 in subpart C (rather than 
Equation C-10), the amendments to 40 CFR 98.246(b)(5) would require 
reporting of the HHV that you use in Equation C-8. This change also 
would delete the erroneous reference to Equation C-10 that was included 
in 40 CFR 98.246(b)(5).
    Reporting Requirements for the Ethylene-Specific Option. We are 
proposing several changes to clarify the reporting requirements in 40 
CFR 98.246(c) for the ethylene-specific option. First, we are proposing 
to add a requirement to report each ethylene process ID to allow 
identification of the applicable process units at facilities with more 
than one ethylene process unit. Second, we are proposing editorial 
changes to clarify that you must estimate the fraction of total 
combustion emissions that is due to combustion of ethylene process off-
gas, consistent with the requirements described above for combustion 
units that are monitored with CEMS. Third, because ethylene is the only 
petrochemical product for process units that can comply with the 
ethylene-specific option, we are proposing to replace the requirement 
to report the ``annual quantity of each type of petrochemical produced 
from each process unit'' with a requirement to report the ``annual 
quantity of ethylene produced from each process unit.''
    Reporting Measurement Device Calibrations. In 40 CFR 98.246(a)(7) 
we are proposing to delete the requirement for reporting of the dates 
and summarized results of calibrations of each measurement device under 
the mass balance option. We have determined that maintaining records of 
this information will be sufficient. Thus, we are also proposing to add 
40 CFR 98.247(b)(4) to require retention of these records.

N. Subpart Y (Petroleum Refineries)

    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart Y for petroleum refineries. The 
issues being addressed by the proposed amendments include the 
following:
     GHG emissions from flares.
     GHG emissions to report from combustion of fuel gas.
     GHG emissions to report from non-merchant hydrogen 
production process units.
     Calculating GHG emissions from fuel gas combustion.
     Calculating combustion GHG emissions from flares and 
thermal oxidizers.
     Molar volume conversion factors.
     Combined stacks monitored by CEMS.
     Nitrogen concentration monitoring to determine exhaust gas 
flow rate.
     Calculating CO2 emissions from catalytic 
reforming units.
     Calculating GHG emissions from sulfur recovery plants.
     Calculating CO2 emissions from coke calcining 
units.
     Calculating CO2 emissions from process vents.
     Reactor vessels using methane as a blanket or purge gas.
     Monitoring and QA/QC requirements.
     Reporting requirements.
    GHG Emissions From Flares. We are proposing several corrections to 
40 CFR 98.252(a) (GHGs to report) to clarify the required emissions 
methods for flares. From the first sentence in 40 CFR 98.252(a), it is 
clear that CO2, CH4, and N2O 
combustion emissions are to be calculated for stationary combustion 
units and for each flare. However, the second sentence suggests that 
petroleum refinery owners or operators are to ``[c]alculate and report 
these emissions under subpart C * * *'' (emphasis added). After the 
first sentence, the remainder of 40 CFR 98.252(a) specifically 
addresses how petroleum refinery owners or operators are to calculate 
and report stationary combustion unit emissions. Flare emissions are to 
be calculated using the methods provided in subpart Y, not the methods 
provided in subpart C. Consequently, we are proposing to amend the 
second sentence in 40 CFR 98.252(a) to correctly require reporters to 
``Calculate and report the emissions from stationary combustion units 
under subpart C * * *'' and we are proposing to add an additional 
sentence at the end of this section to clarify that reports must 
``Calculate and report the emissions from flares under this subpart.''
    GHG Emissions to Report From Combustion of Fuel Gas. We are 
proposing to amend 40 CFR 98.252(a) to clarify that reporting of 
CH4 and N2O emissions is required for the 
stationary combustion units fired with fuel gas. It was always our 
intent that the emissions of these pollutants be reported for 
stationary combustion sources that used fuel gas. However, as no 
default factors for fuel gas were previously included in Table C-1 of 
subpart C, it could be interpreted that these emissions were not 
required to be reported, even though the first sentence clearly 
indicates that emissions of all three pollutants were to be reported 
for stationary combustion units and flares. While the proposed 
amendment to Table C-1 to include default factors for ``fuel gas'' is 
expected to correct this misinterpretation, we are also proposing to 
add the following sentence to 40 CFR 98.252(a) to clarify these 
reporting requirements: ``For CH4 and N2O 
emissions from combustion of fuel gas, use the applicable procedures in 
40 CFR 98.33(c) for the same tier methodology that was used for 
calculating CO2 emissions (use the default CH4 
and N2O emission factors for ``Petroleum (All fuel types in 
Table C-1)'' in table C-2 of subpart C of this part and for Tier 3, 
either the default high heat value for fuel gas in Table C-1 of subpart 
C of this part or a calculated HHV, as allowed in Equation C-8 of 
subpart C of this part.''.
    GHG Emissions To Report From Non-Merchant Hydrogen Production 
Process Units. We are also proposing to amend 40 CFR 98.252(i) to 
clarify that reporting of only CO2 emissions from non-
merchant hydrogen production process units is required. The inclusion 
of ``and CH4'' emissions was an inadvertent error. We are 
also proposing to amend 40 CFR 98.252(i) to clarify that catalytic 
reforming units (although they produce hydrogen as an important by-
product) are not considered hydrogen production

[[Page 48772]]

process units that are required to report under 40 CFR 98.252(i).
    Calculating GHG Emissions From Fuel Gas Combustion. Owners and 
operators have suggested that EPA should allow the use of alternative 
calculation methods for small emission sources from the combustion of 
fuel gas. Specifically, they have asserted that units subject to only 
subpart C may use Tier 1 or Tier 2 if the units are less than or equal 
to 250 mmbtu/hr heat input. However, if those same units are at a 
petroleum refinery and combusting fuel gas, they are required to use 
Tier 3 or Tier 4. We still believe that it is important to use Tier 3 
or Tier 4 for most units at a petroleum refinery because of the 
variability in carbon content in fuel gas (both between different 
refineries and at different times within the same refinery). However, 
we recognize that some flows of fuel gas to process heaters or boilers 
may not necessarily enter the refinery's fuel gas system and that these 
fuel gas lines may not have flow monitors. For example, 40 CFR part 63 
subpart UUU requires the control of purging operations associated with 
the catalytic reforming unit. Among the control options for these 
emissions are provisions to vent these gases to a boiler or process 
heater. If the stationary combustion source has a design capacity of 44 
MW or greater or if the gases are introduced into the flame zone of the 
unit, then direct monitoring of these gas streams is not required under 
subpart UUU. Similar provisions that may pertain to petroleum 
refineries are in other rules (e.g., 40 CFR part 60, subparts III and 
NNN; 40 CFR part 63, subparts G and CC). It is not our intent to 
require direct flow monitoring of these ancillary gas streams, 
particularly if they do not significantly contribute to the overall 
heat input of the stationary combustion unit.
    In addition, while we anticipate that most refineries can use a 
common-pipe monitoring approach for stationary combustion sources 
supplied by the refinery's fuel gas system(s), we recognize that some 
refineries may meter fuel usage at the stationary combustion sources 
and, in some cases, only meter fuel usage at the larger units. Based on 
a review of consent decrees and permits pertaining to process heaters, 
it appears that process heaters less than 30 mmBtu/hr are often not 
subject to emission limitations, and therefore may not have metered 
flow. We performed an analysis of fuel use requirements by process 
unit. From this analysis, we project that more than 95 percent of 
nationwide fuel gas consumption at petroleum refineries would occur in 
process heaters with a rated heat capacity of 30 mmBtu/hr or greater. 
For additional detail on the consent decree review as well as the 
analysis of fuel use requirements, please see the Background Technical 
Support Document (EPA-HQ-OAR-2008-0508). While these small process 
heaters represent only a small percentage of the fuel use on a national 
level, most process heaters at petroleum refineries with capacities 
under 25,000 barrels per day (which represents about 20 percent of the 
refineries, but only 2 percent of the refining capacity) are expected 
to have rated heat capacity of less than 30 mmBtu/hr. Thus, easing the 
Tier 3 monitoring requirements for these smaller process heaters would 
significantly ease the burden for small refineries without 
significantly impacting the accuracy of the nationwide GHG inventories 
for petroleum refineries.
    If flow meters are in place at the process heater or at a common 
pipe location, we consider that the Tier 3 monitoring requirements are 
reasonable and justified. There will not be a significant burden to use 
the Tier 3 method and the reported GHG emissions will be more accurate 
given the fluctuations expected in fuel gas compositions.
    Therefore, we are proposing to amend 40 CFR 98.252(a) so that 
petroleum refineries subject to subpart Y could use the Tier 1 or 2 
methodologies for combustion of fuel gas when either of the following 
conditions exists:
    (1) The annual average fuel gas flow rate in the fuel gas line to 
the combustion unit, prior to any split to individual burners or ports, 
does not exceed 345 scfm at 60[deg]F and 14.7 psia and either of the 
following conditions exist:
     A flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe; or
     The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
    (2) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr and either of the following conditions exist:
     A flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe; or
     The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
    These amendments, combined with the revisions to Table C-1 of 
subpart C, reflect our original intent to require Tier 3 or 4 
monitoring and calculation methods for large fuel gas streams such as 
those anticipated in the refinery's fuel gas system(s), but to allow 
Tier 1 or 2 monitoring methods for smaller fuel gas streams that are 
segregated from the fuel gas system or for small combustion sources at 
refineries where flow monitors are installed at the majority of 
individual combustion sources, but not at the smaller combustion 
sources or the common pipe (i.e., fuel gas system).
    Calculating Combustion GHG Emissions From Flares And Thermal 
Oxidizers. It has been brought to our attention that it is 
inappropriate to apply the 98 percent combustion efficiency to the 
carbon as CO2 that already exists in the gas stream in 
Equations Y-1 and Y-16 in 40 CFR 98.253. While the correction is 
expected to be minor in most cases, we agree that all of the 
CO2 that already exists in the gas stream will be emitted as 
CO2 from these sources. However, we are concerned that, 
depending on the method used to determine the carbon content, some 
facilities may not have collected the specific CO2 data 
needed to implement the revised equations. Therefore, we are proposing 
to amend 40 CFR 98.253 by retaining the existing Equations Y-1 and Y-
16, re-numbering them as Equations Y-1a and Y-16a, and to add the more 
detailed equations that specifically consider the CO2 that 
already exists in the gas stream prior to the flare or thermal 
combustion device as Equations Y-1b and Y-16b. Facilities that were 
required to or elected to use Equation Y-1 to report flare emissions 
would be able to choose to report these emissions using either Equation 
Y-1a or Y-1b, as proposed in today's amendments. Similarly, we are 
proposing to allow facilities required to report CO2 
emissions from asphalt blowing operations controlled by a thermal 
oxidizer or flare to use either Equation Y-16a or Y-16b. We are 
proposing corresponding amendments in 40 CFR 98.256 to require 
reporting of which equation was used and, if the new equations are 
used, reporting of the additional equation parameters.
    We request comment on the need to retain the previously promulgated 
equations. As gas composition data are expected to be determined using 
gas chromatographic methods, the required CO2 data may 
already be collected. Thus, we are particularly interested to determine 
if there are facilities that cannot implement the new equations based 
on the measurement data already

[[Page 48773]]

collected for these sources during the 2010 reporting year.
    Molar volume conversion factors. Owners and operators have 
suggested that allowance be made for alternative ``standard 
conditions'' within the MVC factor used in several of the equations in 
40 CFR 98.253. We recognize that natural gas and fuel gas volumes are 
commonly determined using 60[deg]F as the standard temperature whereas 
exhaust stack volumes are commonly determined using 68[deg]F as the 
standard temperature. Both of these volume measurements are specified 
in subpart Y. It is impractical and unnecessary for existing fuel gas 
monitors, most of which have been installed to correct volumes to 
standard conditions at 60[deg]F, to be reprogrammed to output these 
volumes corrected to standard conditions at 68[deg]F when an 
alternative MVC can be provided to yield the identical mass emissions 
from the calculation. Consequently, we are proposing to amend equations 
Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y-20, and Y-23 in subpart Y to provide 
two alternative values of MVC depending on the standard conditions 
output by the flow monitors. Additionally, the reporting requirements 
related to each of these equations would be amended to include 
reporting of the value of MVC used to support the calculations and to 
afford verification of the reported emissions.
    Combined Stacks Monitored By CEMS. We received several questions 
regarding whether or not discharges through a combined stack are 
allowable when CEMS are used, particularly for the catalytic cracking 
unit. We never intended to limit the use of combined stacks and CEMS at 
the refinery. In fact, we specifically attempted to address this issue 
in subpart Y with respect to the combined catalytic cracking unit and 
CO boiler emissions in 40 CFR 98.253(c)(1)(ii). However, we have 
determined that the current language in 40 CFR 98.253(c)(1)(ii) may 
inadvertently be interpreted to exclude other CO2 emission 
sources that may be mixed with the catalytic cracking unit process 
(e.g., coke burn-off) emissions.
    Consequently, we are proposing to amend the language in 40 CFR 
98.253(c)(1)(ii) and also the reporting requirements in 40 CFR 
98.256(f)(6) to generalize the language to include other CO2 
emission sources, not just a CO boiler. The proposed amendments would 
clarify that when a CEMS is used to measure the CO2 
emissions from the catalytic cracking unit and these emissions are 
combined with ``other CO2 emissions,'' the owner or operator 
must calculate the ``other CO2 emissions'' using the 
applicable methods for the applicable subpart (e.g., subpart C of this 
part in the case of a CO boiler), and determine the process emissions 
from the catalytic cracking unit (or fluid coking unit) as the 
difference in the CO2 CEMS measurements and the calculated 
emissions associated with the ``other CO2 emissions.''
    Nitrogen Concentration Monitoring To Determine Exhaust Gas Flow 
Rate. We also received questions regarding the use of nitrogen 
(N2) concentration monitoring for Equation Y-7 in 40 CFR 
98.253(c)(2)(ii). Equation Y-7 uses an inert balance to calculate the 
exhaust gas flow rate, and a similar calculation can be performed using 
a nitrogen balance. We agree that the nitrogen monitoring approach 
would provide an equivalent measure of the exhaust gas flow rate as 
Equation Y-7. We promulgated Equation Y-7 because we anticipated 
several facilities used this monitoring approach as this equation is 
provided in the 40 CFR part 63 subpart UUU (see Equation 2 of 40 CFR 
63.1573). However, we note that 40 CFR 63.1573 also allows facilities 
to request alternative monitoring methods. There are no similar 
provisions in subpart A or subpart Y of part 98, so this monitoring 
alternative could not be used without amending the rule. As we find the 
N2 concentration monitoring approach to be equivalent to 
Equation Y-7, we are proposing to amend 40 CFR 98.253(c)(2)(ii) to 
renumber Equation Y-7 as Equation Y-7a and adding an Equation Y-7b to 
provide this N2 concentration monitoring approach. We are 
also proposing to add reporting requirements in 40 CFR 98.256(f) to 
report the input parameters for Equation Y-7b if it is used.
    Calculating CO2 Emissions from Catalytic Reforming 
Units. We are proposing to revise the definition of the coke burn-off 
quantity, CBQ, the term ``n'' in Equation Y-11 in 40 CFR 
98.253(e)(3) to clarify the application of Equation Y-11 to 
continuously regenerated catalytic reforming units. Continuously 
regenerated catalytic reforming units do not have specific cycles, so 
the reference to ``regeneration cycle'' in the definition of these 
terms was ambiguous or meaningless for continuously regenerated 
catalytic reforming units. We are proposing to replace the phrase 
``regeneration cycle'' with ``regeneration cycle or measurement 
period'' in the definition of the coke burn-off quantity and to revise 
the definition of ``n'' to be the ``Number of regeneration cycles or 
measurement periods in the calendar year.'' A measurement period may be 
a day, week, month, or other time interval over which process 
measurements are made on the unit by which the coke burn-off rate is 
determined. We are similarly proposing to clarify 40 CFR 98.256(f)(13) 
(formerly designated 40 CFR 98.256(f)(12)) to require reporting of ``* 
* * the number of regeneration cycles or measurement periods during the 
reporting year, the average coke burn-off quantity per cycle or 
measurement period, and the average carbon content of the coke'' when 
Equation Y-11 is used.
    Calculating GHG Emissions From Sulfur Recovery Plants. With respect 
to requirements for sour gas sent off-site for sulfur recovery and for 
on-site sulfur recovery plants, we intended these requirements to be 
identical and that the petroleum refinery would report these emissions 
regardless of whether the sour gas feed is used at an on-site sulfur 
recovery plant within the refinery facility or the sour gas feed is 
sent to an off-site facility. However, we do note that the requirements 
were developed considering Claus sulfur recovery plants and that the 
methods in 40 CFR 98.253(f) may not be appropriate for all other types 
of sulfur recovery plants. To clarify the requirements for sulfur 
recovery plants, we are proposing to amend 40 CFR 98.253(f) to add 
``and for sour gas sent off-site for sulfur recovery'' to clarify that 
this calculation methodology applies ``For on-site sulfur recovery 
plants and for sour gas sent off-site for sulfur recovery, * * *'' and 
to allow non-Claus sulfur recovery plants to alternatively follow the 
requirements in 40 CFR 98.253(j) for process vents. We also are 
proposing to amend the reporting requirements in 40 CFR 98.256(h) to 
include the type of sulfur recovery plant and an indication of the 
method used to calculate CO2 emissions as well as reporting 
requirements for non-Claus sulfur recovery plants that elect to follow 
the requirements in 40 CFR 98.253(j) for process vents. While we 
believe the calculation methodology needs no further regulatory text 
amendments, we do clarify in this preamble that the phrase ``the sulfur 
recovery plant'' in 40 CFR 98.253(f) refers to either the on-site or 
off-site sulfur recovery plant, as applicable. We further clarify in 
this preamble that the sour gas flow and carbon content measurements 
for sour gas sent off-site for sulfur recovery may be made at either 
the refinery or the off-site sulfur recovery plant provided these 
measurements are representative of the flow and carbon content of the 
sour gas sent off-site for sulfur recovery.
    Calculating CO2 Emissions From Coke Calcining Units. We 
are proposing to amend the definition of Mdust (the mass

[[Page 48774]]

of dust collected in the dust collection system) in Equation Y-13 in 40 
CFR 98.253(g). It was brought to our attention that dust collected by 
the control systems may be recycled back to the coke calciner, raising 
the issue of how Mdust should be determined in this 
situation: Is it the mass of dust collected in the dust collection 
system or is it the mass of dust that is discarded from the system? The 
mass balance represented by Equation Y-13 should be applied external to 
this recycle loop, so that Mdust is the quantity of dust 
removed from the overall process, which would be the mass of the dust 
collected in the control system minus the mass of dust recycled. We 
are, therefore, proposing to amend the definition of Mdust 
in Equation Y-13 to clarify this interpretation of Mdust 
when all or a portion of the collected dust is recycled back to the 
coke calciner. We also are proposing to amend 40 CFR 98.256(i)(5) to 
require facilities that use Equation Y-13 to indicate whether or not 
the collected dust is recycled to the coke calciner.
    Calculating CO2 Emissions From Process Vents. We are 
proposing to amend the process vent requirements in 40 CFR 98.253(j) 
due to the additional sources that may elect to use Equation Y-19, 
specifically non-Claus sulfur recovery units (as previously described) 
and uncontrolled blowdown vents (inadvertently not referenced). This 
amendment clarifies that the emissions from the sources that elect to 
use the process vent method in 40 CFR 98.253(j), must use Equation Y-19 
to calculate the emissions for the pollutants required to be reported 
under the cross-referencing section, regardless of whether the 
concentration thresholds in 40 CFR 98.253(j) are exceeded. We are also 
proposing to amend the definition of Equation Y-19's parameters of VR 
(the volumetric flow rate) and MFx (the mole fraction of the 
GHG in the vent). For these parameters we are proposing to clarify that 
these values are to be determined ``from measurement data, process 
knowledge, or engineering estimates.'' We are also proposing to amend 
the reporting requirements for process vents to clarify that the 
requirements apply to each process vent as well as to provide an 
indication of the measurement of estimation method.
    Finally, we are proposing to amend 40 CFR 98.253(n) to delete the 
words ``equilibrium'' and ``product-specific'' to clarify that the true 
vapor phase of the loading operation system should be used when 
determining whether the vapor-phase concentration of methane is 0.5 
volume percent or more. We affirm that process knowledge may be used to 
determine which loading operations have a vapor-phase concentration of 
methane of 0.5 volume percent, but this determination must be made 
considering both the material being loaded and the conditions of the 
loading operations. Equilibrium vapor-phase concentrations can be used 
as process knowledge to determine if the concentration of methane is 
0.5 volume percent or more.
    Monitoring and QA/QC Requirements. In subpart Y, 40 CFR 98.254 
currently specifies QA/QC requirements for fuel flow meters, gas 
composition monitors, and heating value monitors that provide data for 
the GHG emissions calculations. A distinction is made in paragraphs (a) 
and (b) between measurement devices associated with stationary 
combustion sources, which are required to follow the QA/QC procedures 
in 40 CFR 98.34, and devices associated with other GHG emissions 
sources at the refinery, which are to be quality-assured according to 
40 CFR 98.254(c) through (e). Paragraphs (f), (g), and (h) of 40 CFR 
98.254 QA/QC requirements for:
     Stack gas flow rate monitors that are used to comply with 
the requirements of 40 CFR 98.253(c)(2)(ii);
     CO2/CO/O2 composition monitors used 
to comply with 40 CFR 98.253(c)(2); and
     Weighing devices that are used to measure the mass of 
petroleum coke when CO2 emissions from a coke calcining unit 
are calculated using Equation Y-13.
    In subpart Y, 40 CFR 98.254(l) provides QA/QC requirements for 
CO2 CEMS and flow monitors used for direct measurement of 
CO2 emissions following the Tier 4 methodology in subpart C.
    We are proposing to amend 40 CFR 98.254(a) through (h), and (l) as 
follows, to make them consistent with today's proposed revisions to 40 
CFR 98.3(i), and to make some necessary technical corrections and 
clarifications:
    Paragraph (a) of 40 CFR 98.254 would be amended to also include the 
phrase ``sources that use a CEMS to measure CO2 emissions 
according to subpart C of this part * * *'' to further separate these 
sources from those that are covered by 40 CFR 98.254(b). Although the 
CEMS monitoring requirements are specified in 40 CFR 98.254(l), these 
requirements are more clearly specified by the proposed amendments to 
40 CFR 98.254(a) so that all sources required to meet the methods 
provided in subpart C are identified in a single paragraph. We also are 
proposing to re-word the phrase ``follow the monitoring and QA/QC 
requirements in 40 CFR 98.34'' with ``meet the applicable monitoring 
and QA/QC requirements in 40 CFR 98.34'' to clarify that the monitors 
must meet the requirements for the specific Tier for which monitoring 
was required (Tier 3 sources would comply with the Tier 3 requirements; 
Tier 4 sources would comply with the Tier 4 requirements; etc.).
    Because the QA/QC requirements for CO2 CEMS that were 
formerly included in 40 CFR 98.254(l) would be included in the amended 
paragraph 40 CFR 98.254(a), we are proposing to delete 40 CFR 
98.254(l).
    Paragraph (b) of 40 CFR 98.254 would be amended to clarify that 
these requirements apply to gas flow meters, gas composition monitors, 
and heating value monitors other than those subject to 40 CFR 
98.254(a). We would correct the reference to ``paragraphs (c) through 
(e)'' to correctly reference ``paragraphs (c) through (g)'' as gas 
monitoring system requirements are specified in 40 CFR 98.254(c) 
through (g). We would also clarify that the calibration requirements in 
40 CFR 98.3(i) only apply to gas flow meters and to allow recalibration 
of gas flow meters biennially (every two years), at the minimum 
frequency specified by the manufacturer, or at the interval specified 
by the industry consensus standard practice used. Paragraph (b) of 40 
CFR 98.254 would also be amended to clarify that gas composition and 
heating value monitors must be recalibrated either annually, at the 
minimum frequency specified by the manufacturer, or at the interval 
specified by the industry consensus standard practice used.
    Paragraph (c) of 40 CFR 98.254 would be amended to clarify that the 
flare or sour gas flow meters must be calibrated (in addition to 
operated and maintained) using either a method published by a 
consensus-based standards organization (e.g., ASTM, API, etc.) or the 
procedures specified by the flow meter manufacturer. The  5 
percent accuracy specification would be removed from 40 CFR 98.254(c), 
because the accuracy requirement for these flow meters is stated in the 
general provisions at 40 CFR 98.3(i) and is referenced in 40 CFR 
98.254(b). We are also proposing to amend 40 CFR 98.254(c) by removing 
the list of methods as this is redundant with the existing phrase, ``a 
method published by a consensus-based standards organization.''
    Paragraphs (d) and (e) of 40 CFR 98.254 would be amended to allow 
the use of any chromatographic analysis to determine flare gas 
composition and high heat value, as an alternative to the methods 
listed in 40 CFR 98.254(d) and

[[Page 48775]]

(e) provided that the gas chromatograph is operated, maintained, and 
calibrated according to the manufacturer's instructions; and the 
methods used for operation, maintenance, and calibration of the GC are 
documented in the written monitoring plan for the unit under 40 CFR 
98.3(g)(5). Paragraph (d) in 40 CFR 98.254 would also be amended to 
apply to all gas composition monitors, other than those included in 40 
CFR 98.254(g), and not just flare gas composition monitors. This is 
needed to address gas composition monitors that may already be in place 
on process vents subject to reporting under 40 CFR 98.253(j), so that 
these monitors can use alternatives to the methods in 40 CFR 98.254(d).
    We are also proposing to amend 40 CFR 98.254(d) to specify that the 
methods in this paragraph are also to be used for determining average 
molecular weight of the gas, which is needed in Equations Y-1a and Y-3. 
We are also proposing to add an additional method (ASTM D2503-92) to 
this section for determining average molecular weight. Methods for 
determining average molecular weight were inadvertently omitted from 
this section.
    We are proposing a number of amendments to 40 CFR 98.254(f). First, 
the applicability of this paragraph would be expanded to include all 
gas flow meters on process vents subject to reporting under 40 CFR 
98.253(j). The term ``exhaust gas flow meter'' would be replaced with 
the term ``gas flow meter,'' because not all process vents that would 
report under 40 CFR 98.253(j) are combustion (``exhaust'') related gas 
streams.
    Subpart Y currently allows an option to follow 40 CFR 63.1572(c) 
(in the NESHAP for Petroleum Refineries) for installation, operation, 
and calibration of the stack gas flow rate monitor or the requirements 
in 40 CFR 98.254(f)(1) through (f)(4). In our review of these 
requirements, we found that 40 CFR 98.254(f)(1) and (f)(3) were 
important requirements that were not delineated in 40 CFR 63.1572(c). 
However, 40 CFR 98.254(f)(2) is not appropriate (accuracy requirements 
for these flow meters are already provided in the general provisions in 
40 CFR 98.3(i) and are referenced in 40 CFR 98.254(b)), and 40 CFR 
98.254(f)(4) is duplicative of the requirements in 40 CFR 63.1572(c).
    We are proposing to retain portions of 40 CFR 98.254(f)(1) and (3), 
but only as general, supplementary guidelines for flow monitor 
installation and operation. Thus, we are proposing that these stack 
flow monitors must:
     Install, operate, calibrate, and maintain each stack gas 
flow meter according to the requirements in 40 CFR 63.1572(c);
     Locate the flow monitor at a site that provides 
representative flow rates (avoiding locations where there is swirling 
flow or abnormal velocity distributions); and
     Use a monitoring system capable of correcting for the 
temperature, pressure, and moisture content to output flow in dry 
standard cubic feet (standard conditions as defined in 40 CFR 98.6).
    We are proposing to make a technical correction to 40 CFR 
98.254(g). Subpart Y currently requires the CO2/CO/
O2 composition monitors that are used to comply with the 
requirements of 40 CFR 98.253(c)(2) be installed, operated, maintained, 
and calibrated according to either 40 CFR 60.105a(b)(2) (in the NSPS 
for Petroleum Refineries) or 40 CFR 63.1572(a), or according to the 
manufacturer's specifications and requirements. The reference to 40 CFR 
63.1572(a) was in error and should be 40 CFR 63.1572(c). In the NESHAP 
for Petroleum Refineries (40 CFR part 63 subpart UUU), these monitors 
are used to calculate coke burn-off rates, which are monitored to 
ensure the control device is operated within specified limits. Thus, 
these monitors are subject to 40 CFR 63.1572(c) within the NESHAP for 
Petroleum Refineries, and this is the level of QA that these monitoring 
systems are expected to be currently following. We note that 
CO2 monitors that are certified and calibrated as CEMS (with 
the appropriate flow monitoring system) would be subject to the 
requirements in 40 CFR 98.253(c)(1), not 40 CFR 98.253(c)(2). 
Consequently, we specifically refer to the monitors within this 40 CFR 
98.254(g) as ``CO2/CO/O2 composition monitors'' 
rather than CEMS to avoid confusion that these monitors must be 
operated according to CEMS requirements. In developing Part 98, we 
required CO2/CO/O2 composition monitors for 
catalytic cracking units and fluid coking units with rated capacities 
greater than 10,000 barrels per stream day because these monitors were 
expected to be in-place to comply with the NESHAP for Petroleum 
Refineries. We did not include additional costs to upgrade the existing 
CO2/CO/O2 composition monitors in our impact 
analysis because we intended to use the same monitoring requirements as 
in the NESHAP for Petroleum Refineries. Therefore, we are proposing to 
amend 40 CFR 98.254(g) to refer to 40 CFR 63.1572(c), rather than 
63.1572(a), for these O2/CO/O2 composition 
monitors.
    Paragraph (h) of 40 CFR 98.254 specifies calibration procedures for 
weighing devices that are used to determine the mass of petroleum coke 
fed to the coke calcining unit, as required by Equation Y-13. Subpart Y 
currently provides three calibration options: (1) Follow the procedures 
in NIST Handbook 44; (2) follow the manufacturer's recommended 
procedures; or (3) follow the procedures in 40 CFR 98.3(i). We are 
proposing to amend 40 CFR 98.254(h) to require calibration according to 
the procedures specified by NIST Handbook 44 or the procedures 
specified by the manufacturer. Note that the requirements of 40 CFR 
98.3(i) for other measurement devices would apply as well.
    Reporting Requirements. This section covers reporting requirements 
that have not been described in previous sections of this preamble.
    We are proposing to amend the reporting requirements for Equation 
Y-1 (renumbered to Y-1a) and Y-2 to require reporting of whether daily 
or weekly measurement periods are used, for verification purposes.
    In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 CFR 
98.256(i)(6), we are proposing to amend the references to 40 CFR 
98.36(e)(2)(vi) to reference 40 CFR 98.36 more generally. This would 
make the references consistent with the associated requirements in 40 
CFR 98.253.
    In our review of the reporting requirements in 40 CFR 98.256(f), we 
noted an inadvertent error in 40 CFR 98.256(f)(10) and (11) [which 
would be redesignated 40 CFR 98.256(f)(11) and (12) due to the proposed 
reporting requirement associated with Equation Y-7b]. In subpart Y, 
facility owners and operators are required to report information about 
unit-specific emission factors for CH4 and N2O, 
but not necessarily report the unit-specific emission factor itself. We 
are proposing to correct this inadvertent error and require direct 
reporting of the unit-specific emission factor for CH4 and 
N2O, if used, in the newly designated 40 CFR 98.256(f)(11) 
and (12), respectively.
    We are proposing to amend 40 CFR 98.256(i)(8) to make it consistent 
with the information collected in 40 CFR 98.245(i)(7).
    We are also proposing to amend 40 CFR 98.256(j)(2) to clarify that 
the reporting requirements for asphalt blowing apply at the unit level.
    We are also proposing to re-organize the reporting requirements in 
40 CFR 98.256(o) to clarify, for example, that the reporting 
requirement in 40 CFR 98.256(o)(7) of Part 98 pertains specifically to 
tanks processing unstabilized crude oil.

[[Page 48776]]

O. Subpart AA (Pulp and Paper Manufacturing)

    We are proposing to amend subpart AA in response to questions EPA 
received since Part 98 was published on October 30, 2009. These 
amendments are intended to provide clarification and ensure consistency 
with other parts of the rule.
    EPA received questions regarding the methods specified in 40 CFR 
98.273 to calculate fossil-fuel based CO2 emissions from 
chemical recovery furnaces, chemical recovery combustion units, and 
pulp mill lime kilns. Specifically, clarification was requested as to 
whether an owner or operator can choose to use a tier other than Tier 1 
from 40 CFR 98.33 to calculate fossil-fuel based CO2 
emissions. While it was our intent to provide this flexibility, the 
rule text indicated that only Tier 1 could be used. Therefore, we are 
proposing to amend 40 CFR 98.273(a)(1), (b)(1) and (c)(1) to clarify 
that owners and operators may use a higher tier. This flexibility in 
selecting tiers is consistent with 40 CFR 98.34. The option to use a 
higher tier to calculate fossil-fuel based emissions provides 
flexibility to reporters and it only affects the reporting requirements 
if an owner or operator chooses to use a higher tier. EPA also received 
questions regarding the prescribed emission factors to calculate 
fossil-fuel based CO2 emissions from lime kilns. 
Specifically, 40 CFR 98.273(c)(1) directed owners and operators to use 
emission factors in Table AA-2 to calculate CO2 emissions 
from lime kilns, but EPA has received requests to use the emission 
factors provided in Table C-1.
    The emission factors in Table AA-2 were taken from ``Calculation 
Tools for Estimating Greenhouse Gas Emissions from Pulp and Paper 
Mills'', Version 1.1, July 8, 2005, which was prepared by the National 
Council for Air and Stream Improvement (NCASI) for the National Council 
of Forest and Paper Associations (ICFPA). Part 98 incorporated these 
factors in Table AA-2 because they were developed specifically for pulp 
and paper lime kilns, which operate at different conditions than other 
general stationary combustion units.
    Upon further consideration, we have determined that the emission 
factors provided in Table AA-2 are uniquely suited for calculating 
CH4 and N2O emissions from lime kilns given these 
emissions are significantly influenced by the operating conditions. 
However, EPA has found that the same rationale does not support having 
unique emission factors to calculate CO2 emissions from lime 
kilns. Therefore, EPA has removed the CO2 emission factors 
from Table AA-2 and, in 40 CFR 98.273(c)(1), has directed owners and 
operators to use the CO2 emission factors from Table C-1 of 
subpart C to calculate CO2 emissions from lime kilns. 
Modifications to Table AA-2 would affect the emissions reported in 
2010, but would not affect the data that are collected to report 
emissions in 2010.
    Related to the calculation of CH4 and N2O 
emissions described above, and consistent with the proposal to allow 
use of higher Tiers than Tier 1 for units subject to subpart AA, EPA is 
proposing to allow reporters to also use site-specific high heating 
values, as opposed to default values, when claculating CH4 
and N2O emissions.
    EPA has also received questions from owners and operators about 
whether pulp and paper mills are required to calculate emissions from 
the combustion of their wastewater treatment sludge. Specifically, they 
asked for clarification of whether this type of sludge was included in 
Table C-1 and, if not, should they account for emissions from the 
combustion of this material. In our efforts to address this question, 
we have not been able to identify emission factors developed 
specifically for sludge from a pulp and paper mill wastewater facility. 
However, our research indicates that the content of this sludge falls 
within the definition of ``Wood and Wood Residuals'' included in Table 
C-1.
    Therefore, per 40 CFR 98.33(b)(1)(iii), emissions from the 
combustion of this type of sludge may be determined using Tier 1 in 
subpart C. In order to further clarify this, we are proposing to add 
the definition of ``Wood and Wood Residuals'' to 40 CFR 98.6 and to 
include wastewater process sludge from paper mills in this definition. 
Clarifying that emissions from the combustion of sludge from pulp and 
paper mill wastewater treatment facilities may be calculated using Tier 
1 would require that owners and operators estimate the volume of sludge 
combusted using company records. Given the broad definition of company 
records, owners and operators should be able to develop estimates to 
report these emissions in 2011. Presuming these changes are finalized 
as proposed, they would be incorporated into annual GHG reports due in 
March 2011.
    Finally, EPA received questions regarding which emission factors to 
apply when a pulp and paper mill combusts solid petroleum coke given 
this fuel type was not included in Table C-1 and Table AA-2. In 
response, we are proposing to add this fuel type to both tables. 
However, it is noted that emission factors for petroleum coke specific 
to kraft calciners were not available. EPA does not believe that any 
kraft calciners are combusting petroleum coke, so we have concluded 
that it is not necessary to have emission factors for this fuel in 
Table AA-2. EPA seeks comment on this conclusion. Further, if 
information is provided that petroleum coke is combusted at kraft 
calciners, please also include any information on default 
CH4 and N2O emission factors.

P. Subpart NN (Suppliers of Natural Gas and Natural Gas Liquids)

    Threshold for natural gas local distribution companies. The 
applicability provision in subpart A at 40 CFR 98.2(a)(4)(iii)(B) 
requires all natural gas local distribution companies (LDCs), 
regardless of size, to report the GHG emissions that would result from 
the complete combustion or oxidation of the annual volumes of natural 
gas provided to end users on their distribution systems. Owners and 
operators of LDCs potentially subject to subpart NN have asserted that 
this provision results in an unfair burden on many small LDCs.
    They have stated that requiring all LDCs to report did not 
adequately balance rule coverage of GHGs reported, while excluding 
small entities. For example, they highlighted data from the Energy 
Information Administration that indicated that 82 percent of facilities 
are estimated to deliver less than 460,000 mscf per year of natural 
gas, which is equivalent to approximately 25,000 mtCO2e. 
They further noted that EPA's own estimates suggest that these 
facilities would be responsible for less than 1 percent of the reported 
GHG emissions associated with LDC supply. The owners and operators 
concluded that this is a disproportionate burden for LDCs, particularly 
if one considers that across the rule, applying a 25,000 
mtCO2e threshold would exclude approximately 10 to 15 
percent of GHG emissions, a much larger percentage of emissions than 
would be excluded under LDCs by applying that same 25,000 
mtCO2e threshold.
    The owners and operators noted that inclusion of all LDCs in the 
rule would also impose numerous reporting and recordkeeping 
requirements, even though most of these facilities would actually be 
eligible to stop reporting in three or five years, after they could 
prove to EPA that emissions from their supply were less than 15,000 
mtCO2e or 25,000 mtCO2e per year, respectively.
    We note that the threshold requirements for LDCs did not change

[[Page 48777]]

between the initial proposal in April 2009 and Part 98 promulgated on 
October 30, 2009. Further, EPA did not receive any comments opposed to 
the ``all in'' designation for LDCs during the public comment period on 
the proposed Part 98 and, in fact, received two comments supporting the 
lack of a threshold of any kind. Therefore, EPA retained in Part 98 the 
provision to require all LDCs to report the CO2 emissions 
associated with their supply. EPA retained the provision in order to 
maximize coverage of the GHG emissions from natural gas supplies, and 
also to be consistent with other suppliers of fossil fuels and 
industrial gases covered by Part 98. An ``all in'' threshold was 
applied to all of these supplier categories.
    Although we believe that the public had ample opportunity to 
comment on the threshold for LDCs, we have reevaluated this issue in 
light of the information received. We are proposing to amend 40 CFR 
98.2(a)(4)(iii)(B) in subpart A to require all LDCs that deliver 
460,000 mscf or more of natural gas per year to report. We are 
proposing this capacity-based threshold because a capacity-based 
threshold would be more familiar to LDCs. Owners and operators of LDCs 
know how much natural gas they deliver to their customers and it would, 
therefore, be easier for facilities to determine if they are subject to 
the rule than if the threshold were emissions-based. The proposed 
annual threshold is approximately equivalent to 25,000 
mtCO2e.
    After further consideration, we have concluded that although a 
threshold would result in a loss of emissions information to EPA, the 
emissions coverage lost is less than 1 percent. It is also true that 
most of these facilities 460,000 mscf would be able to stop reporting 
to EPA in three or five years, raising the question of whether the 
burden associated with instituting a reporting program that includes 
the smaller facilities is necessary. We have determined that EPA and 
other stakeholders would be able to use data from external sources 
(e.g., the Energy Information Administration) to estimate the less than 
1 percent of GHG emissions that would no longer be reported to EPA if a 
460,000 mscf annual threshold were applied. This would minimize any 
concerns that the loss of emissions coverage would inhibit the use of 
the data for future policy making. Finally, we have concluded that LDCs 
are unique among suppliers in that a large majority of facilities would 
be under a 460,000 mscf threshold, and collectively these facilities 
are responsible for a relatively low percentage of emissions from the 
industry.

Q. Subpart OO (Suppliers of Industrial Greenhouse Gases)

    We are proposing several changes to subpart OO to (1) respond to 
concerns raised by producers of fluorinated GHGs regarding the scope of 
the monitoring and reporting requirements, and (2) clarify the scope 
and due dates for certain reporting and recordkeeping requirements.
    Producers of fluorinated GHGs requested that EPA clarify that 
subpart OO does not apply to fluorinated GHGs that (1) are either 
emitted or destroyed at the facility before the fluorinated GHG product 
is packaged for sale or for shipment to another facility for 
destruction, (2) are produced and transformed at the same facility, or 
(3) occur as low-concentration constituents (impurities) in fluorinated 
GHG products. The producers also requested that EPA amend the rule to 
account for the fact that some fluorinated GHGs do not have global 
warming potential values (GWPs) listed in Table A-1 of subpart A. For 
fluorinated GHGs without GWPs in Table A-1, facilities cannot calculate 
CO2-equivalent production as required by subpart A, and 
importers and exporters cannot take advantage of the reporting 
exemptions for small shipments under 40 CFR 98.416(c) and (d), which 
are expressed in CO2-equivalents.
    Regarding fluorinated GHGs that are emitted or destroyed before the 
product is packaged for sale, the producers specifically requested that 
EPA amend subpart OO to remove the requirements of 40 CFR 98.414(j) and 
98.416(a)(4) to monitor and report the destruction of fluorinated GHGs 
that are not included in the calculation of the mass produced in 40 CFR 
98.413(a) because they are removed from the production process as 
byproducts or wastes.
    They noted that measuring the flow of such fluorinated GHGs into 
the destruction device to the precision required (1 percent) posed 
significant technical challenges and that such measurement was outside 
the scope of subpart OO. They further stated that subpart OO was 
intended to address the quantities of fluorinated GHGs exiting 
production units and entering commerce, where commerce includes the 
packaging and marketing or import and export of fluorinated GHGs. They 
stated that the proposed subpart L was the more appropriate vehicle for 
the monitoring and reporting of emissions and destruction of 
fluorinated GHGs still within the production process.
    However, the producers noted that it was practical and appropriate 
under subpart OO to measure the quantities of fluorinated GHGs that are 
returned to the production facility for destruction after entering into 
commerce (e.g., because they have become irretrievably contaminated).
    Regarding fluorinated GHGs that are produced and transformed at the 
same facility, the fluorinated GHG producers noted that these 
fluorinated GHGs never enter the U.S. supply of fluorinated GHGs 
because they never leave the facility where they are produced. Thus, it 
is not necessary to track them under subpart OO.
    Regarding fluorinated GHGs that occur as low-concentration 
constituents of fluorinated GHG products, the producers observed that 
such low-concentration constituents generally consist of by-products 
that are packaged along with the main constituent of the product. They 
noted that exempting the production, import, and export of these low-
concentration constituents from monitoring and reporting requirements 
would be consistent with the exemption of ``trace'' concentrations from 
other monitoring requirements in subpart OO, such as 40 CFR 98.414(f) 
and (h).
    In response to the concern regarding fluorinated GHGs that are 
emitted or destroyed before the product is packaged for sale, we are 
proposing (1) to modify the definition of ``produce a fluorinated GHG'' 
at 40 CFR 98.410(b) to explicitly exclude the ``creation of fluorinated 
GHGs that are released or destroyed at the production facility before 
the production measurement at Sec.  98.414(a);'' (2) to remove the 
requirements at 40 CFR 98.414(j) and 98.416(a)(4) to monitor and report 
the destruction of fluorinated GHGs ``that are not included in the 
calculation of the mass produced in 40 CFR 98.413(a) because they are 
removed from the production process as byproducts or wastes;'' and (3) 
to modify the requirements at 40 CFR 98.414(h) and 98.416(a)(3) to 
limit them to ``the mass of each fluorinated GHGs that is fed into the 
destruction device and that was previously produced as defined at Sec.  
98.410(b).''
    These proposed amendments would clarify that the scope of subpart 
OO is that which EPA has always intended, and they would modify the 
destruction monitoring and reporting requirements to be fully 
consistent with that scope. As noted in the preamble to the final Part 
98 (74 FR 56259), and in the response to comments document, the intent 
of subpart OO is to track the quantities of fluorinated GHGs entering 
and leaving the U.S. supply of

[[Page 48778]]

fluorinated GHGs. Specifically, subpart OO is intended to address 
production of fluorinated GHGs, not emissions or destruction of 
fluorinated GHGs that occur during the production process. To clarify 
this in the regulatory text, we are proposing to amend the definition 
of ``produce a fluorinated GHG'' at 40 CFR 98.410(b) to exclude the 
``creation of fluorinated GHGS that are released or destroyed at the 
production facility before the production measurement at Sec.  
98.414(a).''
    As noted in the proposed Part 98 (74 FR 16580), the production 
measurement at 40 CFR 98.414(a) could occur wherever it traditionally 
occurs, e.g., at the inlet to the day tank or at the shipping dock, as 
long as the subpart OO monitoring requirements were met (e.g., one-
percent precision and accuracy for the mass produced and for container 
heels, if applicable). As noted above, emissions upstream of the 
production measurement would be subject to proposed subpart L and are 
not part of the subpart OO source category.
    We are also proposing to amend 40 CFR 98.416(a)(3) to limit the 
monitoring and reporting of destroyed fluorinated GHGs to those 
destroyed fluorinated GHGs that were previously ``produced'' under 
today's revised definition.\4\ Such fluorinated GHGs include but are 
not limited to quantities that are shipped to the facility by another 
facility for destruction, and quantities that are returned to the 
facility for reclamation but are found to be irretrievably 
contaminated. While monitoring of some destroyed streams appears to 
pose significant technical challenges,\5\ monitoring of quantities of 
fluorinated GHGs that were previously produced does not. These 
quantities can be weighed and analyzed by the facility upon receipt or 
upon the facility's conclusion that they cannot be brought back to the 
specifications for new or reusable product.
---------------------------------------------------------------------------

    \4\ In Part 98, EPA required the monitoring of all streams being 
destroyed because it was our understanding, based on conversations 
with fluorinated GHG producers, that the mass flow of destroyed 
fluorinated GHG streams was routinely monitored. To arrive at the 
quantities being removed from the supply, EPA required facilities to 
estimate the share of the total quantity of fluorinated GHGs 
destroyed that consisted of fluorinated GHGs that were not included 
in the calculation of the mass produced. This share could then be 
subtracted from the total to arrive at the amounts destroyed that 
were removed from the supply. In other words, monitoring and 
reporting of the destruction of fluorinated GHGs that were not 
included in the mass produced was required in order to estimate the 
destruction of fluorinated GHGs that had been produced.
    \5\ These include (1) low-pressure conditions that make it 
challenging to achieve good accuracies and precisions and under 
which the installation of a flowmeter may lead to low- or no-flow 
conditions, interfering with operations upstream of the meter, (2) 
corrosive conditions that require the use of Tefzel-lined flow 
meters, which are currently available in a limited range of sizes 
and precisions, and (3) variations in stream flow rates and 
compositions that are associated with purging of vessels and columns 
and that make it difficult to select a meter that will measure the 
full range of flows to the required accuracy and precision.
---------------------------------------------------------------------------

    In response to the concern regarding fluorinated GHGs that are 
produced and transformed at the same facility, we are proposing to (1) 
amend the definition of ``produce a fluorinated GHG'' to exclude ``the 
creation of intermediates that are created and transformed in a single 
process with no storage of the intermediates;'' (2) amend the 
definition of ``produce a fluorinated GHG'' to explicitly include ``the 
manufacture of a fluorinated GHG as an isolated intermediate for use in 
a process that will result in its transformation either at or outside 
of the production facility;'' (3) add a definition of ``isolated 
intermediate;'' and (4) add provisions to 40 CFR 98.414, 98.416, and 
98.417 to clarify that isolated intermediates that are produced and 
transformed at the same facility are exempt from subpart OO monitoring, 
reporting, and recordkeeping requirements respectively.
    As noted by the producers, fluorinated GHGs that are produced and 
transformed at the same facility never enter the U.S. supply of 
industrial greenhouse gases; thus, they do not need to be reported 
under subpart OO. This is true both of isolated intermediates and of 
intermediates that are created and transformed in a single process with 
no storage of the intermediate. However, while we are proposing to 
exclude the latter from the definition of ``produce a fluorinated 
GHG,'' we are proposing to include the former in that definition. This 
is because the manufacture of isolated intermediates, which can lead to 
emissions of those intermediates, is of interest under subpart L, and 
we would like to use the same definition of ``produce a fluorinated 
GHG'' for subpart L as for subpart OO for consistency and clarity. 
Thus, instead of excluding the manufacture of isolated intermediates 
that are transformed at the same facility from the definition of 
``produce a fluorinated GHG,'' we are proposing to add provisions to 
exclude it from the subpart OO monitoring, reporting, and recordkeeping 
requirements. We are also proposing to add a definition of ``isolated 
intermediate'' that is the same as that proposed for subpart L (75 FR 
18652, April 12, 2010).
    In response to the concern regarding fluorinated GHGs that occur as 
low-concentration constituents of fluorinated GHG products, we are 
proposing to define and exclude low-concentration constituents from the 
monitoring, reporting, and recordkeeping requirements for fluorinated 
GHG production, exports, and imports. For purposes of production and 
export, we are proposing to define low-concentration constituent as a 
fluorinated GHG constituent of a fluorinated GHG product that occurs in 
the product in concentrations below 0.1 percent by mass. This 
concentration is the same as that used in the definition of ``trace 
concentration'' used elsewhere in subpart OO. It is also consistent 
with industry purity standards for HFC refrigerants (AHRI 700), for 
SF6 used as an insulator in electrical equipment (IEC 
60376), and for perfluorocarbons and other fluorinated GHGs used in 
electronics manufacturing (SEMI C3 series). To meet these standards, 
which set limits that range from less than 0.1 percent to 0.5 percent 
for all fluorinated GHG impurities combined, fluorinated GHG producers 
are likely to have identified and quantified the concentrations of 
impurities at concentrations at or above 0.1 percent for the products 
subject to the standards. Finally, below concentrations of 0.1 percent, 
fluorinated GHG impurities are not likely to have a significant impact 
on the GWP of the product. For example, if a low-concentration 
constituent occurs in concentrations of just under 0.1 percent and has 
a GWP that is ten times as large as the GWP of the main constituent of 
the product, it will increase the weighted GWP of the product by just 
under one percent.
    To ensure that fluorinated GHG production facilities rely on data 
of known and acceptable quality when determining whether or not to 
report a minor fluorinated GHG constituent of a product, we are also 
proposing product sampling and analytical requirements at 40 CFR 
98.414(n) and corresponding calibration requirements at 40 CFR 
98.414(o).
    For purposes of fluorinated GHG import, we are proposing to define 
low-concentration constituent as a fluorinated GHG constituent of a 
fluorinated GHG product that occurs in the product in concentrations 
below 0.5 percent by mass. We are proposing a higher concentration for 
fluorinated GHG imports than for fluorinated GHG production and exports 
because importers are less likely than producers to have detailed 
information on the identities and concentrations of minor fluorinated 
GHG constituents in their products.

[[Page 48779]]

    In response to the concerns regarding fluorinated GHGs that do not 
have GWPs listed in Table A-1, we are proposing (1) to exempt such 
compounds from the general subpart A requirement to report supply flows 
in terms of CO2 equivalents and (2) to recast the reporting 
exemptions for import and export of small shipments in terms of 
kilograms of fluorinated GHGs or N2O rather than tons of 
CO2-equivalents. The amendment to subpart A is discussed in 
more detail in section II.G of this preamble. The exemptions for import 
and export would be applied to shipments of less than 25 kilograms of 
fluorinated GHGs or N2O rather than to shipments of less 
than 250 metric tons of CO2e. This would enable small 
shipments of fluorinated GHGs to be exempt from reporting regardless of 
whether or not the fluorinated GHG had a GWP listed in Table A-1. Our 
analysis of import and export data indicates that this change would 
slightly increase both the number and total mass of the imports and 
exports reported under the rule, but this analysis does not account for 
fluorinated GHGs whose GWPs are not listed in Table A-1. If those 
fluorinated GHGs were accounted for, we believe that the level of 
reporting would increase even less and might even decrease slightly.
    Other Corrections. We are also proposing to amend the reporting and 
recordkeeping provisions in subpart OO to correct internal 
inconsistencies in the subpart and to clarify those requirements.
    We are proposing to amend the reporting requirements in 40 CFR 
98.416(a)(15) and (c)(10) to remove N2O from the list of 
GHGs that must be reported when they are transferred off site for 
destruction, because N2O transferred off site for 
destruction is not required to be monitored.
    We are proposing to amend 40 CFR 98.416(b) and (e) to clarify the 
due dates of the one-time reports required by those paragraphs. The 
proposed due date for the one-time reports is March 31, 2011, or within 
60 days of commencing fluorinated GHG destruction or production (as 
applicable). The due date in 40 CFR 98.416(e) in subpart OO was April 
1, 2011, and there was no provision for commencing fluorinated GHG 
destruction or production after that date. The proposed amendments will 
make the due dates in 40 CFR 98.416(b) and (e) consistent with each 
other, with the due date for a similar report required in subpart O, 
and with the due date for other reporting under the rule.
    We are proposing to amend the recordkeeping requirements in 40 CFR 
98.417(a)(2) to correct and update an internal reference. The correct 
reference is to ``Sec.  98.414(m) and (o),'' instead of ``Sec.  
98.417(j) and (k).'' We are proposing to amend 40 CFR 98.417(b) to 
remove the reference to the ``annual destruction device outlet 
reports'' in 40 CFR 98.416(e) since no such reporting requirement 
exists.
    Finally, we are proposing to amend 40 CFR 98.417(d)(2) to correct a 
typographical error; that paragraph should refer to ``the invoice for 
the export,'' rather than for the ``import.''

R. Subpart PP (Suppliers of Carbon Dioxide)

    In subpart PP, we are proposing to remove the words ``each'' from 
the list of GHGs to report in 40 CFR 98.422. This change would align 
this section with the requirements of the rest of subpart PP, which 
allow for monitoring of an aggregated flow of CO2 if it is 
done at a gathering point downstream of individual production wells or 
production process units.
    We are proposing to allow those suppliers that supply 
CO2 in containers to calculate the annual mass of 
CO2 supplied in containers by using weigh bills, scales, 
load cells, or loaded container volume readings as an alternative to 
flow meters. As a result of many questions received during outreach in 
support of alternative procedures for CO2 supplied in 
containers, we have reevaluated the calculation procedures for 
CO2 suppliers. We have concluded that measurements made with 
weigh bills, scales, load cells, or loaded container volume readings 
will continue to meet the level of data quality and accuracy needed by 
EPA with respect to subpart PP. We have reached this conclusion with 
consideration to minimizing the burden on and maximizing the 
flexibility provided to industry.
    We are proposing multiple amendments to the regulatory text to 
accommodate this proposed provision. First, we are proposing that 40 
CFR 98.423(b) be renumbered to 40 CFR 98.423(c) and that a new 40 CFR 
98.423(b) be added with calculation procedures for CO2 
supplied in containers. Second, we are proposing to amend the first 
sentence of 40 CFR 98.423(a) to allow suppliers that supply 
CO2 in containers to use the alternative procedures in 40 
CFR 98.423(b). Third, we are proposing to add new QA/QC procedures for 
suppliers that supply CO2 in containers to 40 CFR 98.424(a). 
Fourth, we are proposing to add missing data procedures for suppliers 
that supply CO2 in containers to 40 CFR 98.425(d). Finally, 
we are proposing to make multiple amendments to regulatory text in 40 
CFR 98.426 so that all data collected with weigh bills, scales, load 
cells, or loaded container volume readings must be reported just as for 
all data collected with flow meters.
    We note that under the existing requirements, importers and 
exporters that import and export CO2 in containers must 
measure the mass of CO2 in containers using weigh bills, 
scales, or load cells. In this action, we are not proposing that the 
use of loaded container volume readings be allowed for such reporters 
as an alternative to weigh bills, scales, or load cells because we have 
received no questions from importers or exporters suggesting the need 
for such an allowance. We seek comment on whether such an allowance 
should be extended to importers and exporters of CO2 in 
containers, and if so whether the calculation procedures, QA/QC 
procedures, missing data procedures, and reporting requirements for 
loaded container volume readings proposed in this action for suppliers 
should be offered to importers and exporters.
    We are proposing to remove the requirement that CO2 
measurement must be made prior to subsequent purification, processing, 
or compression at 40 CFR 98.423(a)(1), (a)(2), and (b) (which we are 
proposing to redesignate as 40 CFR 98.423(c)). This provision created 
confusion and conflict over where to place a flow meter. For example, 
at least one reporter has indicated that only a portion of a 
CO2 stream is transferred for commercial application while 
the rest is retained for onsite use and emission, and this portion of 
the stream is segregated only after processing. As a result of this and 
other concerns that the requirement to install flow meters prior to 
purification, processing, or compression could result in a requirement 
to install the flow meter at a technically infeasible point, we 
reevaluated the value of such a constraint on the CO2 
calculations. Since the purpose of subpart PP is to collect accurate 
data on CO2 supplied to the economy, we have concluded that 
measurements made after purification, compression, or processing will 
continue to meet the level of data quality and accuracy needed with 
respect to subpart PP, while minimizing the burden on industry and 
providing greater flexibility in measuring CO2 streams.
    To ensure that all reporters account for the appropriate quantity 
of CO2 in situations where a CO2 stream is 
segregated such that only a portion is captured for commercial 
application or

[[Page 48780]]

for injection and where a flow meter is used, we are proposing to add 
language at 40 CFR 98.424(a) requiring the flow meter to be located 
after the point of segregation. We are also proposing to amend existing 
language in 40 CFR 98.424(a) to reference this new requirement.
    Because the proposed amendments would allow flow meters to be 
located after purification, compression, or processing, we are 
proposing to add data reporting requirements in 40 CFR 98.426 to 
collect additional information on flow meter location. Specifically, we 
are proposing that facilities would report information on the placement 
of each flow meter used in relation to the points of CO2 
stream capture, deyhdration, compression, and other processing. Knowing 
where in the production process the flow meter is located will enable 
EPA to effectively compare data across and to learn about the efficacy 
of various CO2 stream capture processes.
    The current subpart PP regulatory text requires that a reporter 
using a volumetric flow meter to measure the flow of a CO2 
stream measure density of that CO2 stream in order to 
calculate the mass of CO2 supplied. As a result of new 
analysis, we have concluded that the mass of CO2 in a stream 
can be adequately determined by converting the volumetric flow of 
CO2 from operating conditions to standard conditions and 
then applying the density value for CO2 at standard 
conditions and the measured concentration of CO2 in the 
flow. This approach may also be less burdensome for reporters than 
directly measuring density with equipment. Therefore, we are proposing 
to amend 40 CFR 98.424(a)(5) by replacing the word ``measure'' with the 
word ``determine.''
    We are also proposing to add a new paragraph 40 CFR 98.424(c) so 
that suppliers will be able to calculate the mass of CO2 in 
a stream from the measured volumetric flow (converted to standard 
conditions) and CO2 concentration, and the given density of 
CO2 at standard conditions.
    For the calculation in the proposed paragraph 40 CFR 98.424(c), 
standard conditions under subpart PP would be a temperature and an 
absolute pressure of 60[deg]F and 1 atmosphere. Note that this would be 
different than the standard conditions defined in subpart A (40 CFR 
98.6), which are 68[deg]F and 14.7 psia. It is our understanding that 
60[deg]F and 1 atmosphere (which is equivalent to 14.7 psia) are more 
commonly used by the industries covered by subpart PP, and we seek 
comment on this conclusion. Given these conditions, we are proposing 
that reporters must use 0.0018704 metric tons per standard cubic meter 
as a density value for CO2 at standard conditions if this is 
the industry standard practice used to determine density.
    The current subpart PP regulatory text also requires that an 
appropriate method published by a consensus-based standards 
organization be used to measure density if such a method exists. Where 
no such method exists, an industry standard practice must be followed. 
We have been unable to identify any method published by a consensus-
based standards organization that accounts for the approach for 
determining density described above and have concluded that it would be 
categorized as an industry standard practice. Therefore, we are 
proposing to amend language in 40 CFR 98.424(a)(5) and (a)(5)(ii) to 
allow reporters to choose equally from between a method published by a 
consensus-based standards organization that is appropriate or an 
industry standard practice to determine density.
    We are proposing to amend the reference to the U.S. Food and Drug 
Administration food-grade specifications for CO2 in 40 CFR 
98.424(b)(2) to correct a typographical error. The correct reference is 
21 CFR 184.1240, not 21 CFR 184.1250.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order (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. The Office of Management and Budget (OMB) has previously 
approved the information collection requirements contained in the 
regulations promulgated on October 30, 2009, under 40 CFR Part 98 under 
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. 
and has assigned OMB control number 2060-0629. 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 Revisions Cost Memo (EPA-HQ-OAR-2008-0508).

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 Part 98 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.

[[Page 48781]]

    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)

    This proposed rule does 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. EPA has estimated that, overall, the proposed revisions do not 
significantly change the overall costs of compliance with Part 98. The 
proposed amendments include providing additional flexibility for 
reporters, clarifying existing reporting requirements, and requiring 
reporting of information already required to be collected under Part 
98. EPA estimates that the cost for all reporters in reviewing the 
proposed rule and determining if, and if so how, it applies to their 
facility, is approximately $2.5 million in the first year. Considering 
the additional flexibilities proposed, in sum, EPA has estimated that 
the proposed rule, if finalized, would reduce the burden to reporters 
as compared to the 2009 final rule. Thus, this rule is not subject to 
the requirements of sections 202 or 205 of UMRA. For more information 
on the cost analysis, please refer to the memorandum titled ``Mandatory 
Greenhouse Gas Reporting: Changes in National Cost Estimates Associated 
with the Proposed Notice of Revisions'' found in the docket at (EPA-HQ-
OAR-2008-0508).
    This proposed rule is also not subject to the requirements of 
section 203 of UMRA because it contains no regulatory requirements that 
might significantly or uniquely affect small governments. EPA 
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 published on October 30, 
2009 (i.e., calculating and reporting annual GHG emissions). EPA 
concluded in the preamble to that final rule that the rule ``* * * 
contains no regulatory requrements that might significantly or uniquely 
affect small governments'' (40 CFR 56260). Because the final rule was 
not determined to significantly or uniquely affect small governments, 
and because this proposed rule generally reduces the burden associated 
with the 2009 final rule, these rule amendments would not unfairly 
apply to small governments.

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 Part 98 (74 FR 16457 to 16461, April 10, 2009).
    These amendments apply directly to facilities that supply fuel or 
chemicals 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 or 
large stationary combustion source), 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 Part 98. A 
summary of EPA's consultations with State and local governments is 
provided in Section VIII.E of the preamble to the final Part 98 (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 rule. Thus, Executive Order 13175 does not apply to this 
action.
    Although Executive Order 13175 does not apply to this action, EPA 
sought opportunities to provide information to Tribal governments and 
representatives during the development of the rules promulgated on 
October 30, 2009. A summary of the EPA's consultations with Tribal 
officials is provided Sections VIII.E and VIII.F of the preamble to the 
final Part 98 (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 technical standards. No new test 
methods were developed for this proposed rule; rather, EPA identified 
existing means of monitoring, reporting, and keeping records of 
greenhouse gas emissions. EPA proposes to use two additional voluntary 
consensus standards from ASTM International. Part 98 includes the use 
of over 40 voluntary consensus standards from various consensus 
standards bodies, for example, ASTM International, the American Society 
of Chemical Engineers, Gas Processors Association, the American Gas 
Association, and the American Petroleum Institute. The proposed 
addition of these two

[[Page 48782]]

voluntary consensus standards from ASTM International to Part 98 will 
help petroleum refineries and petrochemical facilities monitor, report, 
and keep records of greenhouse gas emissions. The test methods are 
incorporated by reference into the proposed rule and are available as 
specified in proposed amendments to 40 CFR 98.7.
    By incorporating voluntary consensus standards into this proposed 
rule, EPA is both meeting the requirements of the NTTAA and presenting 
multiple options and flexibility for measuring greenhouse gas 
emissions.
    EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such 
standards should be used in this regulation.

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 in 40 CFR Part 98

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

    Dated: July 20, 2010.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is proposed to be amended as follows:

PART 98--[AMENDED]

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

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

Subpart A--[Amended]

    2. Section 98.2 is amended by revising paragraph (a)(4)(iii)(B) to 
read as follows:

Sec.  98.2  Who must report?

    (a) * * *
    (4) * * *
    (iii) * * *
    (B) Local natural gas distribution companies that deliver 460,000 
thousand standard cubic feet or more of natural gas per year.
* * * * *
    3. Section 98.3 is amended by:
    a. Revising paragraphs (c)(1), (c)(4)(i), (c)(4)(ii), (c)(4)(iii) 
introductory text, (c)(4)(iii)(A), (c)(4)(iii)(B), and (c)(5)(i).
    b. Revising the third sentence of paragraph (d)(3) introductory 
text.
    c. Revising the first sentence of paragraph (f).
    d. Revising paragraphs (g)(4), (g)(5)(iii).
    e. Revising paragraph (h).
    f. Revising paragraph (i).
    g. Adding paragraph (j).

Sec.  98.3  What are the general monitoring, reporting, recordkeeping 
and verification requirements of this part?

* * * * *
    (c) * * *
    (1) Facility name or supplier name (as appropriate), facility or 
supplier ID number, and physical street address of the facility or 
supplier, including the city, state, and zip code.
* * * * *
    (4) * * *
    (i) Annual emissions (including biogenic CO2) aggregated 
for all GHG from all applicable source categories in subparts C through 
JJ of this part and expressed in metric tons of CO2e 
calculated using Equation A-1 of this subpart.
    (ii) Annual emissions of biogenic CO2 aggregated for all 
applicable source categories in subparts C through JJ of this part in 
metric tons. Units that use the methodologies in part 75 of this 
chapter to calculate CO2 mass emissions are not required to 
separately report biogenic CO2 emissions, but may do so as 
an option.
    (iii) Annual emissions from each applicable source category in 
subparts C through JJ of this part, expressed in metric tons of each 
applicable GHG listed in this paragraph (4)(iii)(A) through 
(4)(iii)(E).
    (A) Biogenic CO2. Units that use the methodologies in 
part 75 of this chapter to calculate CO2 mass emissions are 
not required to separately report biogenic CO2 emissions, 
but may do so as an option.
    (B) CO2 (including biogenic CO2).
* * * * *
    (5) * * *
    (i) Total quantity of GHG aggregated for all GHG from all 
applicable supply categories in subparts KK through PP of this part and 
expressed in metric tons of CO2e calculated using Equation 
A-1 of this subpart. For fluorinated GHGs, calculate and report 
CO2e for only those fluorinated GHGs listed in Table A-1 of 
this subpart.
* * * * *
    (d) * * *
    (3) * * * An owner or operator that submits an abbreviated report 
must submit a full GHG report according to the requirements of 
paragraph (c) of this section beginning in calendar year 2012. * * *
* * * * *
    (f) Verification. To verify the completeness and accuracy of 
reported GHG emissions, the Administrator may review the certification 
statements described in paragraphs (c)(9) and (d)(3)(vi) of this 
section and any other credible evidence, in conjunction with a 
comprehensive review of the GHG reports and periodic audits of selected 
reporting facilities. * * *
    (g) * * *
    (4) Missing data computations. For each missing data event, also 
retain a record of the cause of the event and the corrective actions 
taken to restore malfunctioning monitoring equipment.
    (5) * * *
    (iii) The owner or operator shall revise the GHG Monitoring Plan as 
needed to reflect changes in production processes, monitoring 
instrumentation, and quality assurance procedures; or to improve 
procedures for the maintenance and repair of monitoring systems to 
reduce the frequency of monitoring equipment downtime.
* * * * *
    (h) Annual GHG report revisions.
    (1) The owner or operator shall submit a revised annual GHG report 
within 45 days of discovering that an annual GHG report that the owner 
or operator previously submitted contains one or more substantive 
errors. The revised report must correct all substantive errors.
    (2) The Administrator may notify the owner or operator in writing 
that an annual GHG report previously submitted by the owner or operator 
contains one or more substantive errors.

[[Page 48783]]

Such notification will identify each such substantive error. The owner 
or operator shall, within 45 days of receipt of the notification, 
either resubmit the report that, for each identified substantive error, 
corrects the identified substantive error (in accordance with the 
applicable requirements of this part) or provide information 
demonstrating that the previously submitted report does not contain the 
identified substantive error or that the identified error is not a 
substantive error.
    (3) A substantive error is an error that impacts the quantity of 
GHG emissions reported or otherwise prevents the reported data from 
being validated or verified.
    (4) Notwithstanding paragraphs (h)(1) and (h)(2) of this section, 
upon request by the owner or operator, the Administrator may provide 
reasonable extensions of the 45-day period for submission of the 
revised report or information under paragraphs (h)(1) and (h)(2) of 
this section. If the Administrator receives a request for extension of 
the 45-day period, by e-mail to an address prescribed by the 
Administrator, at least two business days prior to the expiration of 
the 45-day period, and the Administrator does not respond to the 
request by the end of such period, the extension request is deemed to 
be automatically granted for 30 more days. During the automatic 30-day 
extension, the Administrator will determine what extension, if any, 
beyond the automatic extension is reasonable and will provide any such 
additional extension.
    (5) The owner or operator shall retain documentation for 3 years to 
support any revision made to an annual GHG report.
    (i) Calibration and accuracy requirements. The owner or operator of 
a facility or supplier that is subject to the requirements of this part 
must meet the applicable flow meter calibration and accuracy 
requirements of this paragraph (i). The accuracy specifications in this 
paragraph (i) do not apply where either the use of company records (as 
defined in Sec.  98.6) or the use of ``best available information'' is 
specified in an applicable subpart of this part to quantify fuel usage 
and/or other parameters. Further, the provisions of this paragraph (i) 
do not apply to stationary fuel combustion units that use the 
methodologies in part 75 of this chapter to calculate CO2 
mass emissions.
    (1) Except as otherwise provided in paragraphs (i)(4) through 
(i)(6) of this section, flow meters that measure liquid and gaseous 
fuel feed rates, process stream flow rates, or feedstock flow rates and 
provide data for the GHG emissions calculations, shall be calibrated 
prior to April 1, 2010 using the procedures specified in this paragraph 
(i) when such calibration is specified in a relevant subpart of this 
part. Each of these flow meters shall meet the applicable accuracy 
specification in paragraph (i)(2) or (i)(3) of this section. All other 
measurement devices (e.g., weighing devices) that are required by a 
relevant subpart of this part, and that are used to provide data for 
the GHG emissions calculations, shall also be calibrated prior to April 
1, 2010; however, the accuracy specifications in paragraphs (i)(2) and 
(i)(3) of this section do not apply to these devices. Rather, each of 
these measurement devices shall be calibrated to meet the accuracy 
requirement specified for the device in the applicable subpart of this 
part, or, in the absence of such accuracy requirement, the device must 
be calibrated to an accuracy within the appropriate error range for the 
specific measurement technology, based on an applicable operating 
standard, including but not limited to industry standards and 
manufacturer's specifications. The procedures and methods used to 
quality-assure the data from each measurement device shall be 
documented in the written Monitoring Plan, pursuant to paragraph 
(g)(5)(i)(C) of this section.
    (i) All flow meters and other measurement devices that are subject 
to the provisions of this paragraph (i) must be calibrated according to 
one of the following. You may use the manufacturer's recommended 
procedures; an appropriate industry consensus standard method; or a 
method specified in a relevant subpart of this part. The calibration 
method(s) used shall be documented in the Monitoring Plan required 
under paragraph (g) of this section.
    (ii) For facilities and suppliers that become subject to this part 
after April 1, 2010, all flow meters and other measurement devices (if 
any) that are required by the relevant subpart(s) of this part to 
provide data for the GHG emissions calculations shall be installed no 
later than the date on which data collection is required to begin using 
the measurement device, and the initial calibration(s) required by this 
paragraph (i) (if any) shall be performed no later than that date.
    (iii) Except as otherwise provided in paragraphs (i)(4) through 
(i)(6) of this section, subsequent recalibrations of the flow meters 
and other measurement devices subject to the requirements of this 
paragraph (i) shall be performed at one of the following frequencies:
    (A) You may use the frequency specified in each applicable subpart 
of this part.
    (B) You may use the frequency recommended by the manufacturer or by 
an industry consensus standard practice, if no recalibration frequency 
is specified in an applicable subpart.
    (2) Perform all flow meter calibration at measurement points that 
are representative of the normal operating range of the meter. Except 
for the orifice, nozzle, and venturi flow meters described in paragraph 
(i)(3) of this section, calculate the calibration error at each 
measurement point using Equation A-2 of this section. The terms ``R'' 
and ``A'' in Equation A-2 must be expressed in consistent units of 
measure (e.g., gallons/minute, ft\3\/min). The calibration error at 
each measurement point shall not exceed 5.0 percent of the reference 
value.
[GRAPHIC] [TIFF OMITTED] TP11AU10.000

Where:

CE = Calibration error (%)
R = Reference value
A = Flow meter response to the reference value

    (3) For orifice, nozzle, and venturi flow meters, the initial 
quality assurance consists of in-situ calibration of the differential 
pressure (delta-P), total pressure, and temperature transmitters.
    (i) Calibrate each transmitter at a zero point and at least one 
upscale point. Fixed reference points, such as the freezing point of 
water, may be used for temperature transmitter calibrations. Calculate 
the calibration error of each transmitter at each measurement point, 
using Equation A-3 of this subpart. The terms ``R'', ``A'', and ``FS'' 
in Equation A-3 of this subpart must be in consistent units of measure 
(e.g., milliamperes, inches of water, psi, degrees). For each 
transmitter, the CE value at each measurement point shall not exceed 
2.0 percent of full-scale. Alternatively, the results are acceptable if 
the sum of the calculated CE values for the three transmitters at each 
calibration level (i.e., at the zero level and at each upscale level) 
does not exceed: 6.0 percent.

[[Page 48784]]

[GRAPHIC] [TIFF OMITTED] TP11AU10.001

Where:

CE = Calibration error (%)
R = Reference value
A = Transmitter response to the reference value
FS = Full-scale value of the transmitter

    (ii) In cases where there are only two transmitters (i.e., 
differential pressure and either temperature or total pressure) in the 
immediate vicinity of the flow meter's primary element (e.g., the 
orifice plate), or when there is only a differential pressure 
transmitter in close proximity to the primary element, calibration of 
these existing transmitters to a CE of 2.0 percent or less at each 
measurement point is still required, in accordance with paragraph 
(i)(3)(i) of this section; alternatively, when two transmitters are 
calibrated, the results are acceptable if the sum of the CE values for 
the two transmitters at each calibration level does not exceed 4.0 
percent. However, note that installation and calibration of an 
additional transmitter (or transmitters) at the flow monitor location 
to measure temperature or total pressure or both is not required in 
these cases. Instead, you may use assumed values for temperature and/or 
total pressure, based on measurements of these parameters at a remote 
location (or locations), provided that the following conditions are 
met:
    (A) You must demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions.
    (B) You must make all temperature and/or total pressure 
measurements in the demonstration described in paragraph (i)(3)(ii)(A) 
of this section with calibrated gauges, sensors, transmitters, or other 
appropriate measurement devices. At a minimum, calibrate each of these 
devices to an accuracy within the appropriate error range for the 
specific measurement technology, according to one of the following. You 
may calibrate using an industry consensus standards or a manufacturer's 
specification.
    (C) You must document the methods used for the demonstration 
described in paragraph (i)(3)(ii)(A) of this section in the written 
Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must 
also include the data from the demonstration, the mathematical 
correlation(s) between the remote readings and actual flow meter 
conditions derived from the data, and any supporting engineering 
calculations in the Monitoring Plan. You must maintain all of this 
information in a format suitable for auditing and inspection.
    (D) You must use the mathematical correlation(s) derived from the 
demonstration described in paragraph (i)(3)(ii)(A) of this section to 
convert the remote temperature or the total pressure readings, or both, 
to the actual temperature or total pressure at the flow meter, or both, 
on a daily basis. You shall then use the actual temperature and total 
pressure values to correct the measured flow rates to standard 
conditions.
    (E) You shall periodically check the correlation(s) between the 
remote and actual readings (at least once a year), and make any 
necessary adjustments to the mathematical relationship(s).
    (4) Fuel billing meters are exempted from the calibration 
requirements of this section and from the Monitoring Plan and 
recordkeeping provisions of paragraphs (g)(5)(i)(C) and (g)(7) of this 
section, provided that the fuel supplier and any unit combusting the 
fuel do not have any common owners and are not owned by subsidiaries or 
affiliates of the same company. Meters used exclusively to measure the 
flow rates of fuels that are used for unit startup or ignition are also 
exempted from the calibration requirements of this section.
    (5) For a flow meter that has been previously calibrated in 
accordance with paragraph (i)(1) of this section, an additional 
calibration is not required by the date specified in paragraph (i)(1) 
of this section if, as of that date, the previous calibration is still 
active (i.e., the device is not yet due for recalibration because the 
time interval between successive calibrations has not elapsed). In this 
case, the deadline for the successive calibrations of the flow meter 
shall be set according to one of the following. You may use either the 
manufacturer's recommended calibration schedule or you may use the 
industry consensus calibration schedule.
    (6) For units and processes that operate continuously with 
infrequent outages, it may not be possible to meet the April 1, 2010 
deadline for the initial calibration of a flow meter or other 
measurement device without disrupting normal process operation. In such 
cases, the owner or operator may postpone the initial calibration until 
the next scheduled maintenance outage. The best available information 
from company records may be used in the interim. The subsequent 
required recalibrations of the flow meters may be similarly postponed. 
Such postponements shall be documented in the monitoring plan that is 
required under paragraph(g)(5) of this section.
    (7) If the results of an initial calibration or a recalibration 
fail to meet the required accuracy specification, data from the flow 
meter shall be considered invalid, beginning with the hour of the 
failed calibration and continuing until a successful calibration is 
completed. You shall follow the missing data provisions provided in the 
relavant missing data sections during the period of data invalidation.
    (j) Measurement Device Installation.
    (1) General. If an owner or operator required to report under 
subpart P, subpart X or subpart Y of this part has process equipment or 
units that operate continuously and it is not possible to install a 
required flow meter or other measurement device by April 1, 2010, (or 
by any later date in 2010 approved by the Administrator as part of an 
extension of best available monitoring methods per paragraph (d) of 
this section) without process equipment or unit shutdown, or through a 
hot tap, the owner or operator may request an extension from the 
Administrator to delay installing the measurement device until the next 
scheduled process equipment or unit shutdown. If approval for such an 
extension is granted by the Administrator, the owner or operator must 
use best available monitoring methods during the extension period.
    (2) Requests for extension of the use of best available monitoring 
methods for measurement device installation. The owner or operator must 
first provide the Administrator an initial notification of the intent 
to submit an extension request for use of best available monitoring 
methods beyond December 31, 2010 (or an earlier date approved by EPA) 
in cases where measurement device installation would require a process 
equipment or unit shutdown, or could only be done through a hot tap. 
The owner or operator must follow-up this initial notification with the 
complete extension request containing the information specified in 
paragraph (j)(4) of this section.
    (3) Timing of request.

[[Page 48785]]

    (i) The initial notice of intent must be submitted no later than 
January 1, 2011, or by the end of the approved use of best available 
monitoring methods extension in 2010, whichever is earlier. The 
completed extension request must be submitted to the Administrator no 
later than February 15, 2011.
    (ii) Any subsquent extensions to the original request must be 
submitted to the Administrator within 4 weeks of the owner or operator 
identifying the need to extend the request, but in any event no later 
than 4 weeks before the date for the planned process equipment or unit 
shutdown that was provided in the original request.
    (4) Content of the request. Requests must contain the following 
information:
    (i) Specific measurement device for which the request is being made 
and the location where each measurement device will be installed.
    (ii) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) requiring the measurement 
device.
    (iii) A description of the reasons why the needed equipment could 
not be installed before April 1, 2010, or by the expiration date for 
the use of best available monitoring methods, in cases where an 
extension has been granted under Sec.  98.3(d).
    (iv) Supporting documentation showing that it is not practicable to 
isolate the process equipment or unit and install the measurement 
device without a full shutdown or a hot tap, and that there was no 
opportunity during 2010 to install the device. Include the date of the 
three most recent shutdowns for each relevant process equipment or 
unit, the frequency of shutdowns for each relevant process equipment or 
unit, and the date of the next planned process equipment or unit 
shutdown.
    (v) Include a description of the proposed best available monitoring 
method for estimating GHG emissions during the time prior to 
installation of the meter.
    (5) Approval criteria. The owner or operator must demonstrate to 
the Administrator's satisfaction that it is not reasonably feasible to 
install the measurement device before April 1, 2010 (or by the 
expiration date for the use of best available monitoring methods, in 
cases where an extension has been granted under paragraph(d) of this 
section) without a process equipment or unit shutdown, or through a hot 
tap, and that the proposed method for estimating GHG emissions during 
the time before which the measurement device will be installed is 
appropriate. The Administrator will not initially approve the use of 
the proposed best available monitoring method past December 31, 2013.
    (6) Measurement device installation deadline. Any owner or operator 
that submits both a timely initial notice of intent and a timely 
completed extension request under paragraph (j)(3) of this section to 
extend use of best available monitoring methods for measurement device 
installation must install all such devices by July 1, 2011 unless the 
extension request under this paragraph (j) is approved by the 
Administrator before July 1, 2011.
    (7) One time extension past December 31, 2013. If an owner or 
operator determines that a scheduled process equipment or unit shutdown 
will not occur by December 31, 2013, the owner or operator may re-apply 
to use best available monitoring methods for one additional time 
period, not to extend beyond December 31, 2015. To extend use of best 
available monitoring methods past December 31, 2013, the owner or 
operator must submit a new extension request by June 1, 2013 that 
contains the information required in paragraph (j)(4) of this section. 
The owner or operator must demonstrate to the Administrator's 
satisfaction that it continues to not be reasonably feasible to install 
the measurement device before December 31, 2013 without a process 
equipment or unit shutdown, or that installation of the measurement 
device could only be done through a hot tap, and that the proposed 
method for estimating GHG emissions during the time before which the 
measurement device will be installed is appropriate. An owner or 
operator that submits a request under this paragraph to extend use of 
best available monitoring methods for measurement device installation 
must install all such devices by December 31, 2013, unless the 
extension request under this paragraph is approved by the 
Administrator.
    4. Section 98.4 is amended by revising paragraphs (i)(2) and 
(m)(2)(i) to read as follows:

Sec.  98.4  Authorization and responsibilities of the designated 
representative.

* * * * *
    (i) * * *
    (2) The name, organization name (company affiliation-employer), 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of the designated representative and any 
alternate designated representative.
* * * * *
    (m) * * *
    (2) * * *
    (i) The name, organization name (company affiliation-employer) 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of such designated representative or 
alternate designated representative.
* * * * *
    5. Section 98.6 is amended by:
    a. Adding in alphabetical order definitions for ``Agricultural 
byproducts,'' ``Primary fuel,'' ``Solid byproducts,'' ``Waste oil,'' 
and ``Wood residuals.''
    b. Revising the definitions for ``Bulk natural gas liquid or NGL,'' 
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Municipal solid waste or 
MSW,'' ``Natural gas,'' and ``Natural gas liquids (NGLs).''
    c. Removing the definition for ``Fossil fuel-fired.''

Sec.  98.6  Definitions.

* * * * *
    Agricultural byproducts means those parts of arable crops that are 
not used for the primary purpose of producing food. Agricultural 
byproducts include, but are not limited to, oat, corn and wheat straws, 
bagasse, peanut shells, rice and coconut husks, soybean hulls, palm 
kernel cake, cottonseed and sunflower seed cake, and pomace.
* * * * *
    Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons 
that have been separated from natural gas as liquids through the 
process of absorption, condensation, adsorption, or other methods. 
Generally, such liquids consist of ethane, propane, butanes, and 
pentanes plus. Bulk NGL is sold to fractionators or to refineries and 
petrochemical plants where the fractionation takes place.
* * * * *
    Distillate Fuel Oil means a classification for one of the petroleum 
fractions produced in conventional distillation operations and from 
crackers and hydrotreating process units. The generic term distillate 
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels 
(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, 
No. 2, and No. 4).
* * * * *
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material, for purpose 
of creating useful heat.
* * * * *
    Municipal solid waste or MSW means solid phase household, 
commercial/retail, and/or institutional waste. Household waste includes 
material discarded by single and multiple

[[Page 48786]]

residential dwellings, hotels, motels, and other similar permanent or 
temporary housing establishments or facilities. Commercial/retail waste 
includes material discarded by stores, offices, restaurants, 
warehouses, non-manufacturing activities at industrial facilities, and 
other similar establishments or facilities. Institutional waste 
includes material discarded by schools, nonmedical waste discarded by 
hospitals, material discarded by non-manufacturing activities at 
prisons and government facilities, and material discarded by other 
similar establishments or facilities. Household, commercial/retail, and 
institutional waste does not include used oil, wood pellets, 
construction, renovation, and demolition wastes (which includes, but is 
not limited to, railroad ties and telephone poles), clean wood, 
industrial process or manufacturing wastes, medical waste, or motor 
vehicles (including motor vehicle parts or vehicle fluff). Household, 
commercial/retail, and institutional wastes include yard waste, refuse-
derived fuel, and motor vehicle maintenance materials, limited to 
vehicle batteries and tires, except where a single waste stream 
consisting of tires is combusted in a unit.
* * * * *
    Natural gas means a naturally occurring mixture of hydrocarbon and 
non-hydrocarbon gases found in geologic formations beneath the earth's 
surface, of which the principal constituent is methane. Natural gas may 
be field quality or pipeline quality. Natural gas is composed of at 
least 70 percent methane by volume or has a high heat value between 910 
and 1150 Btu per standard cubic foot.
    Natural gas liquids (NGLs) means those hydrocarbons in natural gas 
that are separated from the gas as liquids through the process of 
absorption, condensation, adsorption, or other methods. Generally, such 
liquids consist of ethane, propane, butanes, and pentanes plus. Bulk 
NGLs refers to mixtures of NGLs that are sold or delivered as 
undifferentiated product from natural gas processing plants.
* * * * *
    Primary fuel means the fuel that provides the greatest percentage 
of the annual heat input to a stationary fuel combustion unit.
* * * * *
    Solid byproducts means plant matter such as vegetable waste, animal 
materials/wastes, and other solid biomass, except for wood, wood waste, 
and sulphite lyes (black liquor).
* * * * *
    Waste oil means a petroleum-derived or synthetically-derived oil 
whose physical properties have changed as a result of storage, handling 
or use, such that the oil cannot be used for its original purpose. 
Waste oil consists primarily of automotive oils (e.g., used motor oil, 
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial 
oils (e.g., industrial engine oils, metalworking oils, process oils, 
industrial grease, etc).
* * * * *
    Wood residuals means wood waste recovered from three principal 
sources: Municipal solid waste (MSW); construction and demolition 
debris; and primary timber processing. Wood residuals recovered from 
MSW include wooden furniture, cabinets, pallets and containers, scrap 
lumber (from sources other than construction and demolition 
activities), and urban tree and landscape residues. Wood residuals from 
construction and demolition debris originate from the construction, 
repair, remodeling and demolition of houses and non-residential 
structures. Wood residuals from primary timber processing include bark, 
sawmill slabs and edgings, sawdust, and peeler log cores. Other sources 
of wood residuals include, but are not limited to, railroad ties, 
telephone and utility poles, pier and dock timbers, wastewater process 
sludge from paper mills, and logging residues.
* * * * *
    6. Section 98.7 is amended by:
    a. Removing and reserving paragraph (b).
    b. Revising paragraphs (d)(1) and (d)(2).
    c. Removing and reserving paragraph (d)(3).
    d. Revising paragraphs (d)(4) and (d)(5).
    e. Removing and reserving paragraph (d)(6).
    f. Revising paragraphs (d)(7) and (d)(8).
    g. Removing and reserving paragraph (d)(9).
    h. Revising paragraph (d)(10).
    i. Removing and reserving paragraph (d)(11).
    j. Revising paragraph (e)(4).
    k. Removing and reserving paragraph (e)(7).
    l. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14), (e)(15), 
(e)(19), (e)(20), (e)(24) through (e)(27).
    m. Removing and reserving paragraph (e)(28).
    n. Revising paragraph (e)(30), (e)(33), and (e)(36).
    o. Adding paragraphs (e)(43) and (e)(44).
    p. Removing and reserving paragraph (f)(1) and (g)(3).
    q. Revising paragraph (f)(2)
    r. Removing and reserving paragraph (g)(3).
    s. Adding paragraph (m)(3).

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

* * * * *
    (d) * * *
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved 
for Sec.  98.344(c) and Sec.  98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters, IBR approved for Sec.  98.344(c) and Sec.  98.364(e).
    (3) [Reserved]
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters, IBR approved for Sec.  98.344(c) and Sec.  
98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.  
98.344(c) and Sec.  98.364(e).
    (6) [Reserved]
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters, IBR approved for Sec.  98.344(c).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters, IBR approved for Sec.  98.344(c) and Sec.  
98.364(e).
    (9) [Reserved]
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable 
Area Meters, IBR approved for Sec.  98.344(c), and Sec.  98.364(e).
    (11) [Reserved]
    (e) * * *
    (4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR 
approved for Sec.  98.254(e).
* * * * *
    (7) [Reserved]
    (8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter, IBR approved for Sec.  98.254(e).
* * * * *
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, IBR approved for Sec.  98.74(c), Sec.  
98.164(b), Sec.  98.244(b), Sec.  98.254(d), and Sec.  98.344(b).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography,

[[Page 48787]]

IBR approved for Sec.  98.74(c), Sec.  98.164(b), Sec.  98.254(d), 
Sec.  98.344(b), and Sec.  98.364(c).
* * * * *
    (14) ASTM D2502-04 Standard Test Method for Estimation of Mean 
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, 
IBR approved for Sec.  98.74(c).
    (15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec.  
98.74(c).
* * * * *
    (19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method, IBR approved for Sec.  98.74(c) and 
Sec.  98.164(b).
    (20) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, IBR approved for Sec.  98.254(e).
* * * * *
    (24) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR 
approved for Sec.  98.254(e).
    (25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, IBR approved for Sec.  98.254(e).
    (26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, IBR approved for Sec.  98.74(c), 
Sec.  98.164(b), Sec.  98.244(b), and Sec.  98.254(i).
    (27) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal, IBR approved for Sec.  98.74(c), Sec.  98.114(b), Sec.  
98.164(b), Sec.  98.174(b), Sec.  98.184(b), Sec.  98.244(b), Sec.  
98.254(i), Sec.  98.274(b), Sec.  98.284(c), Sec.  98.284(d), Sec.  
98.314(c), Sec.  98.314(d), Sec.  98.314(f), and Sec.  98.334(b).
    (28) [Reserved]
* * * * *
    (30) ASTM D6348-03 Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy, IBR approved for Sec.  98.54(b),Sec.  
98.224(b), and Sec.  98.414(n).
* * * * *
    (33) ASTM D6866-08 Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using 
Radiocarbon Analysis, IBR approved for Sec.  98.34(d), Sec.  98.34(e), 
and Sec.  98.36(e).
* * * * *
    (36) ASTM D7459-08 Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved 
for Sec.  98.34(d), Sec.  98.34(e), and Sec.  98.36(e).
* * * * *
    (43) ASTM D2503-92(2007) Standard Test Method for Relative 
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric 
Measurement of Vapor Pressure, IBR approved for Sec.  98.254(d).
    (44) ASTM D2593-93(2009) Standard Test Method for Butadiene Purity 
and Hydrocarbon Impurities by Gas Chromatography, IBR approved for 
Sec.  98.244(b).
* * * * *
    (f) * * *
    (1) [Reserved]
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, IBR approved for Sec.  98.164(b), Sec.  
98.254(d), and Sec.  98.344(b).
* * * * *
    (g) [Reserved]
* * * * *
    (k) The following material is available from the U.S. Environmental 
Protection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C. 
20460, (202) 272-0167, www.epa.gov.
    (1) Protocol for Measuring Destruction or Removal Efficiency (DRE) 
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003.

Subpart C--[Amended]

    7. Section 98.30 is amended by:
    a. Revising paragraph (b)(4).
    b. Revising paragraph (c) introductory text.
    c. Adding paragraph (d).

Sec.  98.30  Definition of the source category.

    (b) * * *
    (4) Flares, unless otherwise required by provisions of another 
subpart of this part to use methodologies in this subpart.
* * * * *
    (c) For a unit that combusts hazardous waste (as defined in Sec.  
261.3 of this chapter), reporting of GHG emissions is not required 
unless either of the following conditions apply:
* * * * *
    (d) You are not required to report GHG emissions from pilot lights. 
A pilot light is a small permanent auxiliary flame that ignites the 
burner of a combustion device when the control valve opens.
    8. Section 98.32 is revised to read as follows:

Sec.  98.32  GHGs to report.

    You must report CO2, CH4, and N2O 
mass emissions from each stationary fuel combustion unit, except as 
otherwise indicated in this subpart.
    9. Section 98.33 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(1).
    b. Revising the definition of ``HHV'' in Equation C-2a of paragraph 
(a)(2)(i).
    c. Revising and the first two sentences of paragraph (a)(2)(ii) 
introductory text.
    d. In paragraph (a)(2)(ii)(A), revising the first sentence and the 
definitions of ``(HHV)i,'' ``(Fuel)i,'' and ``n'' 
in Equation C-2b.
    e. Revising paragraph (a)(2)(ii)(B).
    f. Revising the definitions of ``CC'' and ``MW'' in Equation C-5 of 
paragraph (a)(3)(iii).
    g. Revising paragraphs (a)(3)(iv), (a)(4)(iii), and (a)(4)(iv).
    h. Adding a new paragraph (a)(4)(viii).
    i. Revising paragraphs (a)(5) introductory text, (a)(5)(i) 
introductory text, (a)(5)(i)(A), (a)(5)(i)(B), (a)(5)(ii) introductory 
text, (a)(5)(ii)(A), (a)(5)(iii) introductory text, (a)(5)(iii)(A), 
(a)(5)(iii)(B).
    j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv), 
and revising newly designated paragraph (a)(5)(iv).
    k. Revising paragraph (b)(1)(iv).
    l. Adding paragraph (b)(1)(v).
    m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii) 
introductory text, and (b)(3)(iii)(B).
    n. Adding paragraph (b)(3)(iv).
    o. Adding a second sentence to paragraph (b)(4)(i).
    p. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), (b)(4)(ii)(E), 
(b)(4)(ii)(F), and (b)(4)(iii) introductory text.
    q. Adding a new paragraph (b)(4)(iv).
    r. Revising paragraph (b)(5) and the third sentence of paragraph 
(b)(6).
    s. In paragraph (c)(1), revising the second sentence, and revising 
the definition of ``HHV'' in Equation C-8.
    t. Revising the second sentence of paragraph (c)(2).
    u. In paragraph (c)(4) introductory text, revising the only 
sentence and revising the definition of ``(HI)A'' in 
Equation C-10.
    v. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
    w. Adding a new paragraph (c)(6).
    x. In paragraph (d)(1), revising the first sentence, adding a 
second sentence, and revising the definition of ``R'' in Equation C-11.

[[Page 48788]]

    y. Revising paragraphs (d)(2), (e) introductory text, (e)(1), and 
(e)(2) introductory text.
    z. Revising the definition of ``Fc'' in Equation C-13 of 
paragraph (e)(2)(iii).
    aa. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
    bb. Reserving paragraph (e)(4).
    cc. Revising the first sentence of paragraph (e)(5).

Sec.  98.33  Calculating GHG emissions.

* * * * *
    (a) CO2 emissions from fuel combustion. Calculate 
CO2 mass emissions by using one of the four calculation 
methodologies in paragraphs (a)(1) through (a)(4) of this section, 
subject to the applicable conditions, requirements, and restrictions 
set forth in paragraph (b) of this section. Alternatively, for units 
that meet the conditions of paragraph (a)(5) of this section, you may 
use CO2 mass emissions calculation methods from part 75 of 
this chapter, as described in paragraph (a)(5) of this section. For 
units that combust both biomass and fossil fuels, you must calculate 
and report CO2 emissions from the combustion of biomass 
separately using the methods in paragraph (e) of this section, except 
as otherwise provided in paragraphs (a)(5)(iv) and (e) of this section 
and in Sec.  98.36(d).
    (1) Tier 1 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using Equation 
C-1 or C-1a of this section (as applicable).
    (i) Use Equation C-1 except when natural gas billing records are 
used to quantify fuel usage and gas consumption is expressed in units 
of therms. In that case, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TP11AU10.002

Where:

CO2 = Annual CO2 mass emissions for the 
specific fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company 
records as defined in Sec.  98.6 (express mass in short tons for 
solid fuel, volume in standard cubic feet for gaseous fuel, and 
volume in gallons for liquid fuel).
HHV = Default high heat value of the fuel, from Table C-1 of this 
subpart (mmBtu per mass or mmBtu per volume, as applicable).
EF = Fuel-specific default CO2 emission factor, from 
Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (ii) If natural gas consumption is obtained from billing records 
and fuel usage is expressed in therms, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TP11AU10.003

Where:

CO2 = Annual CO2 mass emissions from natural 
gas combustion (metric tons).
Gas = Annual natural gas consumption, from billing records (therms).
EF = Fuel-specific default CO2 emission factor for 
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric 
tons.
(2) * * *
(i) * * *
HHV = Annual average high heat value of the fuel (mmBtu per mass or 
volume). The average HHV shall be calculated according to the 
requirements of paragraph (a)(2)(ii) of this section.
* * * * *

    (ii) The minimum required sampling frequency for determining the 
annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot) 
is specified in Sec.  98.34. The method for computing the annual 
average HHV is a function of unit size and how frequently you perform 
or receive from the fuel supplier the results of fuel sampling for HHV. 
* * *
    (A) If the results of fuel sampling are received monthly or more 
frequently, then for each unit with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr (or for a group of units that 
includes at least one unit of that size), the annual average HHV shall 
be calculated using Equation C-2b of this section. * * *
* * * * *
(HHV)i = Measured high heat value of the fuel, for month 
``i'', or, if applicable, an appropriate substitute data value 
(mmBtu per mass or volume).
(Fuel)i = Mass or volume of the fuel combusted during 
month ``i,'' from company records (express mass in short tons for 
solid fuel, volume in standard cubic feet for gaseous fuel, and 
volume in gallons for liquid fuel).
n = Number of months in the year that the fuel is burned in the 
unit.

(B) If the results of fuel sampling are received less frequently than 
monthly, or, for a unit with a maximum rated heat input capacity less 
than 100 mmBtu/hr (or a group of such units) regardless of the HHV 
sampling frequency, the annual average HHV shall be computed as the 
arithmetic average HHV for all values for the year (including valid 
samples and substitute data values under Sec.  98.35).
* * * * *
    (3) * * *
    (iii) * * *
CC = Annual average carbon content of the gaseous fuel (kg C per kg 
of fuel). The annual average carbon content shall be determined 
using the same procedures as specified for HHV in paragraph 
(a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-
mole). The annual average molecular weight shall be determined using 
the same procedures as specified for HHV in paragraph (a)(2)(ii) of 
this section.
* * * * *

    (iv) Fuel flow meters that measure mass flow rates may be used for 
liquid or gaseous fuels, provided that the fuel density is used to 
convert the readings to volumetric flow rates. The density shall be 
measured at the same frequency as the carbon content. For liquid fuels, 
you must measure the density using one of the following appropriate 
methods. You may use a method published by a consensus standards 
organization, if such a method exists, or you may use industry standard 
practice. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International, the American National 
Standards Institute (ANSI), the American Gas Association (AGA), the 
American Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB). 
The method(s) used shall be documented in the Monitoring Plan required 
under Sec.  98.3(g)(5). Alternatively, for fuel oil, you may use

[[Page 48789]]

an applicable default density value provided in paragraph (a)(3)(v) of 
this section. For gaseous fuels, you may determine the density using 
any of the following methods. You may use a density meter calibrated 
according to the manufacturer's instructions, a method published by a 
consensus standards organization, or an industry standard practice. 
Document the method used to determine the fuel density in the 
Monitoring Plan under Sec.  98.3(g)(5).
* * * * *
    (4) * * *
    (iii) If the CO2 concentration is measured on a dry 
basis, a correction for the stack gas moisture content is required. You 
shall either continuously monitor the stack gas moisture content as 
described in Sec.  75.11(b)(2) of this chapter or use an appropriate 
default moisture percentage. For coal, wood, and natural gas 
combustion, you may use the default moisture values specified in Sec.  
75.11(b)(1) of this chapter. Alternatively, for any type of fuel, you 
may determine an appropriate site-specific default moisture value (or 
values), using measurements made with EPA Method 4--Determination Of 
Moisture Content In Stack Gases, in appendix A-3 to part 60 of this 
chapter. If this option is selected, the site-specific moisture default 
value(s) must represent the fuel(s) or fuel blends that are combusted 
in the unit during normal, stable operation, and must account for any 
distinct difference(s) in the stack gas moisture content associated 
with different process operating conditions. For each site-specific 
default moisture percentage, at least nine Method 4 runs are required. 
Moisture data from the relative accuracy test audit (RATA) of a CEMS 
may be used for this purpose. Calculate each site-specific default 
moisture value by taking the arithmetic average of the Method 4 runs. 
Each site-specific moisture default value shall be updated whenever the 
owner or operator believes the current value is non-representative, due 
to changes in unit or process operation, but in any event no less 
frequently than annually. Use the updated moisture value in the 
subsequent CO2 emissions calculations. For each unit 
operating hour, a moisture correction must be applied to Equation C-6 
of this section as follows:
[GRAPHIC] [TIFF OMITTED] TP11AU10.004

Where:

CO2* = Hourly CO2 mass emission rate, 
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from 
Equation C-6 of this section, uncorrected (metric tons/hr).
%H2O = Hourly moisture percentage in the stack gas 
(measured or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in 
lieu of a CO2 concentration monitor to determine the hourly 
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the 
effluent gas stream monitored by the CEMS consists solely of combustion 
products (i.e., no process CO2 emissions or CO2 
emissions from sorbent are mixed with the combustion products) and if 
only fuels that are listed in Table 1 in section 3.3.5 of appendix F to 
part 75 of this chapter are combusted in the unit. If the O2 
monitoring option is selected, the F-factors used in Equations F-14a 
and F-14b shall be determined according to section 3.3.5 or section 
3.3.6 of appendix F to part 75 of this chapter, as applicable. If 
Equation F-14b is used, the hourly moisture percentage in the stack gas 
shall be determined in accordance with paragraph (a)(4)(iii) of this 
section.
* * * * *
    (viii) If a portion of the flue gases generated by a unit subject 
to Tier 4 (e.g., a slip stream) is continuously diverted from the main 
flue gas exhaust system for the purpose of heat recovery or some other 
similar process, and then exhausts through a stack that is not equipped 
with the continuous emission monitors to measure CO2 mass 
emissions, provided that the CO2 concentration in the 
diverted stream is not altered in any way (e.g., by chemical reaction 
or dilution) before the diverted stream exits to the atmosphere, an 
estimate of the hourly average volumetric flow rate (scfh) of the 
diverted gas stream shall be made at the point where it exits the main 
exhaust system, by using the best available information (e.g., 
correlations of operating parameters versus flow measurements made with 
EPA Method 2 in appendix A-2 to part 60 of this chapter, engineering 
analysis, or other methods). Each hourly average volumetric flow rate 
(scfh) measured at the main flue gas stack shall then be added to the 
corresponding estimate of the hourly average flow rate of the diverted 
gas stream, to determine the total hourly average stack gas volumetric 
flow rate ``Q'', for use in Equation C-6 of this section. The method 
use to estimate the hourly flow rate of the diverted portion of the 
flue gas exhaust stream shall be documented in the Monitoring Plan 
required under Sec.  98.3(g)(5).
    (5) Alternative methods for certain units subject to Part 75 of 
this chapter. Certain units that are not subject to subpart D of this 
part and that report data to EPA according to part 75 of this chapter 
may qualify to use the alternative methods in this paragraph (a)(5), in 
lieu of using any of the four calculation methodology tiers.
    (i) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to appendix D to part 75 of this chapter, but 
is not required by the applicable part 75 program to report 
CO2 mass emissions data, calculate the annual CO2 
mass emissions for the purposes of this part as follows:
    (A) Use the hourly heat input data from appendix D to part 75 of 
this chapter, together with Equation G-4 in appendix G to part 75 of 
this chapter to determine the hourly CO2 mass emission 
rates, in units of tons/hr;
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapterto calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons; and
* * * * *
    (ii) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to Sec.  75.19 of this chapter but is not 
required by the applicable part 75 program to report CO2 
mass emissions data, calculate the annual CO2 mass emissions 
for the purposes of this part as follows:
    (A) Calculate the hourly CO2 mass emissions, in units of 
short tons, using Equation LM-11 in Sec.  75.19(c)(4)(iii) of this 
chapter.
* * * * *
    (iii) For a unit that is not subject to subpart D of this part, 
uses flow rate and CO2 (or O2) CEMS to report 
heat input data year-round according to part 75 of

[[Page 48790]]

this chapter, but is not required by the applicable part 75 program to 
report CO2 mass emissions data, calculate the annual 
CO2 mass emissions as follows:
    (A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 
75 of this chapter to calculate the hourly CO2 mass emission 
rates from the CEMS data. If an O2 monitor is used, convert 
the hourly average O2 readings to CO2 using 
Equation F-14a or F-14b in appendix F to part 75 of this chapter (as 
applicable), before applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapter to calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons.
* * * * *
    (iv) For units that qualify to use the alternative CO2 
emissions calculation methods in paragraphs (a)(5)(i) through 
(a)(5)(iii) of this section, if both biomass and fossil fuel are 
combusted during the year, separate calculation and reporting of the 
biogenic CO2 mass emissions (as described in paragraph (e) 
of this section) is optional.
    (b) * * *
    (1) * * *
    (iv) May not be used if you routinely perform fuel sampling and 
analysis for the fuel high heat value (HHV) or routinely receive the 
results of HHV sampling and analysis from the fuel supplier at the 
minimum frequency specified in Sec.  98.34(a), or at a greater 
frequency. In such cases, Tier 2 shall be used. This restriction does 
not apply to paragraphs (b)(1)(ii) and (b)(1)(v) of this section.
    (v) May be used for natural gas combustion in a unit of any size, 
in cases where the annual natural gas consumption is obtained from fuel 
billing records in units of therms.
    (2) * * *
    (ii) May be used in a unit with a maximum rated heat input capacity 
greater than 250 mmBtu/hr for the combustion of natural gas and/or 
distillate fuel oil.
* * * * *
    (3) * * *
    (ii) * * *
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs 
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.
* * * * *
    (iii) Shall be used for a fuel not listed in Table C-1 of this 
subpart if the fuel is combusted in a unit with a maximum rated heat 
input capacity greater than 250 mmBtu/hr (or, pursuant to Sec.  
98.36(c)(3), in a group of units served by a common supply pipe, having 
at least one unit with a maximum rated heat input capacity greater than 
250 mmBtu/hr), provided that both of the following conditions apply:
* * * * *
    (B) The fuel provides 10% or more of the annual heat input to the 
unit or, if Sec.  98.36(c)(3) applies, to the group of units served by 
a common supply pipe.
    (iv) Shall be used when specified in another applicable subpart of 
this part, regardless of unit size.
    (4) * * *
    (i) * * * Tier 4 may also be used for any group of stationary fuel 
combustion units, process units, or manufacturing units that share a 
common stack or duct.
    (ii) * * *
    (A) The unit has a maximum rated heat input capacity greater than 
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a 
maximum rated input capacity greater than 600 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW as the primary fuel.
* * * * *
    (E) The installed CEMS include a gas monitor of any kind or a stack 
gas volumetric flow rate monitor, or both and the monitors have been 
certified, either in accordance with the requirements of part 75 of 
this chapter, part 60 of this chapter, or an applicable State 
continuous monitoring program.
    (F) The installed gas or stack gas volumetric flow rate monitors 
are required, either by an applicable Federal or State regulation or by 
the unit's operating permit, to undergo periodic quality assurance 
testing in accordance with either appendix B to part 75 of this 
chapter, appendix F to part 60 of this chapter, or an applicable State 
continuous monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input 
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal 
solid waste with a maximum rated input capacity of 600 tons of MSW per 
day or less, if the unit meets all of the following three conditions:
* * * * *
    (iv) May apply to common stack or duct configurations where:
    (A) The combined effluent gas streams from two or more stationary 
fuel combustion units are vented through a monitored common stack or 
duct. In this case, Tier 4 shall be used if all of the conditions in 
paragraph (b)(4)(iv)(A)(1) of this section or all of the conditions in 
paragraph (b)(4)(iv)(A)(2) of this section are met.
    (1) At least one of the units meets the requirements of paragraphs 
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS 
installed at the common stack (or duct) meet the requirements of 
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
    (2) At least one of the units and the monitors installed at the 
common stack or duct meet the requirements of paragraph (b)(4)(iii) of 
this section.
    (B) The combined effluent gas streams from a process or 
manufacturing unit and a stationary fuel combustion unit are vented 
through a monitored common stack or duct. In this case, Tier 4 shall be 
used if the combustion unit and the monitors installed at the common 
stack or duct meet the applicability criteria specified in paragraph 
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
    (C) The combined effluent gas streams from two or more 
manufacturing or process units are vented through a common stack or 
duct. In this case, if any of the units is required by an applicable 
subpart of this part to use Tier 4, the CO2 mass emissions 
may either be monitored at each individual unit, or the combined 
CO2 mass emissions may be monitored at the common stack or 
duct. However, if it is not feasible to monitor the individual units, 
the combined CO2 mass emissions shall be monitored at the 
common stack or duct.
    (5) The Tier 4 Calculation Methodology shall be used:
    (i) Starting on January 1, 2010, for a unit that is required to 
report CO2 mass emissions beginning on that date, if all of 
the monitors needed to measure CO2 mass emissions have been 
installed and certified by that date.
    (ii) No later than January 1, 2011, for a unit that is required to 
report CO2 mass emissions beginning on January 1, 2010, if 
all of the monitors needed to measure CO2 mass emissions 
have not been installed and certified by January 1, 2010. In this case, 
you may use Tier 2 or Tier 3 to report GHG emissions for 2010. However, 
if the required CEMS are certified some time in 2010, you need not wait 
until January 1, 2011 to begin using Tier 4. Rather, you may switch 
from Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing 
is successfully completed. If this reporting option is chosen, you must 
document the change in CO2 calculation methodology in the 
Monitoring Plan required under Sec.  98.3(g)(5) and in the GHG 
emissions report under Sec.  98.3(c). Data recorded by the CEMS during 
a certification test period in 2010 may be used for reporting under 
this part, provided that the following two conditions are met:
    (A) The certification tests are passed in sequence, with no test 
failures.

[[Page 48791]]

    (B) No unscheduled maintenance or repair of the CEMS is performed 
during the certification test period.
    (iii) No later than 180 days following the date on which a change 
is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) 
or (b)(4)(iii) of this section (e.g., a change in the primary fuel, 
manner of unit operation, or installed continuous monitoring 
equipment).
    (6) * * * However, for units that use either the Tier 4 or the 
alternative calculation methodology specified in paragraph (a)(5)(iii) 
of this section, CO2 emissions from the combustion of all 
fuels shall be based solely on CEMS measurements.
    (c) * * *
    (1) * * * Use the same values for fuel consumption that you use for 
the Tier 1 or Tier 3 calculation.
* * * * *
HHV = Default high heat value of the fuel from Table C-1 of this 
subpart; alternatively, for Tier 3, if actual HHV data are available 
for the reporting year, you may average these data using the 
procedures specified in paragraph (a)(2)(ii) of this section, and 
use the average value in Equation C-8 (mmBtu per mass or volume).
* * * * *

    (2) * * * Use the same values for fuel consumption and HHV that you 
use for the Tier 2 calculation.
* * * * *
    (4) Use Equation C-10 of this section for: units subject to subpart 
D of this part; units that qualify for and elect to use the alternative 
CO2 mass emissions calculation methodologies described in 
paragraph (a)(5) of this section; and units that use the Tier 4 
Calculation Methodology.
* * * * *
(HI)A = Cumulative annual heat input from combustion of 
the fuel (mmBtu).
* * * * *

    (i) If only one type of fuel listed in Table C-2 of this subpart is 
combusted during the reporting year, substitute the cumulative annual 
heat input from combustion of the fuel into Equation C-10 of this 
section to calculate the annual CH4 or N2O 
emissions. For units in the Acid Rain Program and units that report 
heat input data to EPA year-round according to part 75 of this chapter, 
obtain the cumulative annual heat input directly from the electronic 
data reports required under Sec.  75.64 of this chapter. For Tier 4 
units, use the best available information, as described in paragraph 
(c)(4)(ii)(C) of this section, to estimate the cumulative annual heat 
input (HI)A.
    (ii) If more than one type of fuel listed in Table C-2 of this 
subpart is combusted during the reporting year, use Equation C-10 of 
this section separately for each type of fuel, except as provided in 
paragraph (c)(4)(ii)(B) of this section. Determine the appropriate 
values of (HI)A as follows:
    (A) For units in the Acid Rain Program and other units that report 
heat input data to EPA year-round according to part 75 of this chapter, 
obtain (HI)A for each type of fuel from the electronic data 
reports required under Sec.  75.64 of this chapter, except as otherwise 
provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.
    (B) For a unit that uses CEMS to monitor hourly heat input 
according to part 75 of this chapter, the value of (HI)A 
obtained from the electronic data reports under Sec.  75.64 of this 
chapter may be attributed exclusively to the fuel with the highest F-
factor, when the reporting option in 3.3.6.5 of appendix F to part 75 
of this chapter is selected and implemented.
    (C) For Tier 4 units, use the best available information (e.g., 
fuel feed rate measurements, fuel heating values, engineering analysis) 
to estimate the value of (HI)A for each type of fuel. 
Instrumentation used to make these estimates is not subject to the 
calibration requirements of Sec.  98.3(i) or to the QA requirements of 
Sec.  98.34.
    (D) Units in the Acid Rain Program and other units that report heat 
input data to EPA year-round according to part 75 of this chapter may 
use the best available information described in paragraph (c)(4)(ii)(C) 
of this section, to estimate (HI)A for each fuel type, 
whenever fuel-specific heat input values cannot be directly obtained 
from the electronic data reports under Sec.  75.64 of this chapter.
* * * * *
    (6) Calculate the annual CH4 and N2O mass 
emissions from the combustion of blended fuels as follows:
    (i) If the mass or volume of each component fuel in the blend is 
measured before the fuels are mixed and combusted, calculate and report 
CH4 and N2O emissions separately for each 
component fuel, using the applicable procedures in this paragraph (c).
    (ii) If the mass or volume of each component fuel in the blend is 
not measured before the fuels are mixed and combusted, a reasonable 
estimate of the percentage composition of the blend, based on best 
available information, is required. Perform the following calculations 
for each component fuel, ``i,'' that is listed in Table C-2:
    (A) Multiply (% Fuel)i, the estimated mass or volume 
percentage (decimal fraction) of component fuel ``i,'' by the total 
annual mass or volume of the blended fuel combusted during the 
reporting year, to obtain an estimate of the annual consumption of 
component ``i;''
    (B) Multiply the result from paragraph (c)(6)(ii)(A) of this 
section by the HHV of the fuel (default value or, if available, the 
measured annual average value), to obtain an estimate of the annual 
heat input from component ``i;''
    (C) Calculate the annual CH4 and N2O 
emissions from component ``i,'' using Equation C-8, C-9a, or C-10 of 
this section, as applicable;
    (D) Sum the annual CH4 emissions across all component 
fuels to obtain the annual CH4 emissions for the blend. 
Similarly sum the annual N2O emissions across all component 
fuels to obtain the annual N2O emissions for the blend. 
Report these annual emissions totals.
    (d) * * *
    (1) When a unit is a fluidized bed boiler, is equipped with a wet 
flue gas desulfurization system, or uses other acid gas emission 
controls with sorbent injection to remove acid gases, if the chemical 
reaction between the acid gas and the sorbent produces CO2 
emissions, use Equation C-11 of this section to calculate the 
CO2 emissions from the sorbent, except when those 
CO2 emissions are monitored by CEMS. When a sorbent other 
than CaCO3 is used, determine site-specific values of R and 
MWS.
* * * * *
R = The number of moles of CO2 released upon capture of 
one mole of the acid gas species being removed (R = 1.00 when the 
sorbent is CaCO3 and the targeted acid gas species is 
SO2).
* * * * *
    (2) The total annual CO2 mass emissions reported for the 
unit shall include the CO2 emissions from the combustion 
process and the CO2 emissions from the sorbent.
    (e) Biogenic CO2 emissions from combustion of biomass 
with other fuels. Use the applicable procedures of this paragraph (e) 
to estimate biogenic CO2 emissions from units that combust a 
combination of biomass and fossil fuels (i.e., either co-fired or 
blended fuels). Separate reporting of biogenic CO2 emissions 
from the combined combustion of biomass and fossil fuels is required 
for those biomass fuels listed in Table C-1 of this section and for 
municipal solid waste. In addition, when a biomass fuel that is not 
listed in Table C-1 is combusted in a unit that has a maximum rated 
heat input greater than 250 mmBtu/hr, if the biomass fuel accounts for 
10% or more of the annual heat input to the unit, and if the unit

[[Page 48792]]

does not use CEMS to quantify its annual CO2 mass emissions, 
then, pursuant to Sec.  98.33(b)(3)(iii), Tier 3 must be used to 
determine the carbon content of the biomass fuel and to calculate the 
biogenic CO2 emissions from combustion of the fuel. 
Notwithstanding these requirements, separate reporting of biogenic 
CO2 emissions is optional for units subject to subpart D of 
this part and for units that use the CO2 mass emissions 
calculation methodologies in part 75 of this chapter, pursuant to 
paragraph (a)(5) of this section; however, if the owner or operator 
opts to report biogenic CO2 emissions separately for these 
units, the appropriate method(s) in this paragraph (e) shall be used. 
Separate reporting of biogenic CO2 emissions from the 
combustion of tires is also optional, but may be reported by following 
the provisons of paragraph (e)(3) of this section.
    (1) You may use Equation C-1 of this subpart to calculate the 
annual CO2 mass emissions from the combustion of the biomass 
fuels listed in Table C-1 of this subpart (except MSW and tires), in a 
unit of any size, including units equipped with a CO2 CEMS, 
except when the use of Tier 2 is required as specified in paragraph 
(b)(1)(iv) of this section. Determine the quantity of biomass combusted 
using one of the following procedures in this paragraph (e)(1), as 
appropriate, and document the selected procedures in the Monitoring 
Plan under Sec.  98.3(g):
    (i) Company records.
    (ii) The procedures in paragraph (e)(5) of this section.
    (iii) The best available information for premixed fuels that 
contain biomass and fossil fuels (e.g., liquid fuel mixtures containing 
biodiesel).
    (2) You may use the procedures of this paragraph if the following 
three conditions are met: first, a CO2 CEMS (or a surrogate 
O2 monitor) and a stack gas flow rate monitor are used to 
determine the annual CO2 mass emissions (either according to 
part 75 of this chapter, the Tier 4 Calculation Methodology, or the 
alternative calculation methodology specified in paragraph (a)(5)(iii) 
of this section); second, neither MSW nor tires is combusted in the 
unit during the reporting year; and third, the CO2 emissions 
consist solely of combustion products (i.e., no process or sorbent 
emissions included).
* * * * *
    (iii) * * *

Fc = Fuel-specific carbon based F-factor, either a 
default value from Table 1 in section 3.3.5 of appendix F to part 75 
of this chapter, or a site-specific value determined under section 
3.3.6 of appendix F to part 75 (scf CO2/mmBtu).
* * * * *

    (iv) Subtract Vff from Vtotal to obtain 
Vbio, the annual volume of CO2 from the 
combustion of biomass.
* * * * *
    (vi) * * *
    (C) From the electronic data report required under Sec.  75.64 of 
this chapter, for units in the Acid Rain Program and other units using 
CEMS to monitor and report CO2 mass emissions according to 
part 75 of this chapter. However, before calculating the annual 
biogenic CO2 mass emissions, multiply the cumulative annual 
CO2 mass emissions by 0.91 to convert from short tons to 
metric tons.
    (3) You must use the procedures in paragraphs (e)(3)(i) through 
(e)(3)(iii) of this section to determine the annual biogenic 
CO2 emissions from the combustion of MSW. These procedures 
also may be used for any unit that co-fires biomass and fossil fuels, 
including units equipped with a CO2 CEMS, and units for 
which optional separate reporting of biogenic CO2 emissions 
from the combustion of tires is selected.
    (i) Use an applicable CO2 emissions calculation method 
in this section to quantify the total annual CO2 mass 
emissions from the unit.
    (ii) Determine the relative proportions of biogenic and non-
biogenic CO2 emissions in the flue gas on a quarterly basis 
using the method specified in Sec.  98.34(d) (for units that combust 
MSW as the primary fuel or as the only fuel with a biogenic component) 
or in Sec.  98.34(e) (for other units, including units that combust 
tires).
    (iii) Determine the annual biogenic CO2 mass emissions 
from the unit by multiplying the total annual CO2 mass 
emissions by the annual average biogenic decimal fraction obtained from 
Sec.  98.34(d) or Sec.  98.34(e), as applicable.
    (4) [Reserved]
    (5) If Equation C-1 or Equation C-2a of this section is selected to 
calculate the annual biogenic mass emissions for wood, wood waste, or 
other solid biomass-derived fuel, Equation C-15 of this section may be 
used to quantify biogenic fuel consumption, provided that all of the 
required input parameters are accurately quantified. * * *
* * * * *
    10. Section 98.34 is amended by:
    a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) introductory 
text, (b)(1)(i) introductory text, (b)(1)(i)(A), (b)(1)(i)(B), 
(b)(1)(i)(C), (b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), and 
(b)(3)(v).
    b. Removing paragraph (b)(4).
    c. Redesignating paragraph (b)(5) as (b)(4).
    d. Revising newly designated paragraph (b)(4).
    e. Revising paragraphs (c) introductory text, (c)(1)(i), 
(c)(1)(ii), (c)(2), (c)(3), and (c)(4).
    f. Adding paragraphs (c)(6) and (c)(7).
    g. Revising paragraphs (d), (e), (f) introductory text, (f)(1), 
(f)(3), and (f)(5).
    h. Adding new paragraphs (f)(7) and (f)(8).
    i. Removing paragraph (g).

Sec.  98.34  Monitoring and QA/QC requirements.

* * * * *
    (a) * * *
    (2) The minimum required frequency of the HHV sampling and analysis 
for each type of fuel or fuel mixture (blend) is specified in this 
paragraph. When the specified frequency for a particular fuel or blend 
is based on a specified time period (e.g., week, month, quarter, or 
half-year), fuel sampling and analysis is required only for those time 
periods in which the fuel or blend is combusted. The owner or operator 
may perform fuel sampling and analysis more often than the minimum 
required frequency, in order to obtain a more representative annual 
average HHV.
    (i) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at 
least four months apart).
    (ii) For coal and fuel oil, and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the unit's storage tank. Flow proportional sampling, continuous 
drip sampling, or daily manual oil sampling may also be used, in lieu 
of sampling each fuel lot. For the purposes of this section, a fuel lot 
is defined as either:
    (A) A shipment or delivery of a single fuel (e.g., ship load, barge 
load, group of trucks, group of railroad cars, oil delivery via 
pipeline from a tank farm, etc.); or
    (B) If multiple deliveries of a particular type of fuel are 
received from the same supply source in a given calendar month, the 
deliveries for that month are considered, collectively, to comprise a 
fuel lot, requiring only one representative sample.
    (iii) For liquid fuels other than fuel oil, and for gaseous fuels 
other than natural gas (including biogas), sampling and analysis is 
required at least once per calendar quarter. To the extent

[[Page 48793]]

practicable, consecutive quarterly samples shall be taken at least 30 
days apart.
    (iv) For other solid fuels (except MSW), weekly sampling is 
required to obtain composite samples, which are then analyzed monthly.
    (v) For fuel blends that are received already mixed, as described 
in paragraph (a)(3)(ii) of this section, determine the HHV of the blend 
as follows. For blends of solid fuels (except MSW), weekly sampling is 
required to obtain composite samples, which are analyzed monthly. For 
blends of liquid or gaseous fuels, sampling and analysis is required at 
least once per calendar quarter. More frequent sampling is recommended 
if the composition of the blend varies significantly during the year.
    (3) Special Considerations for Blending of Fuels. In situations 
where different types of fuel listed in Table C-1 of this subpart (for 
example, different ranks of coal or different grades of fuel oil) are 
in the same state of matter (i.e., solid, liquid, or gas), and are 
blended prior to combustion, use the following procedures to determine 
the appropriate CO2 emission factor and HHV for the blend.
    (i) If the fuels to be blended are received separately, and if the 
quantity (mass or volume) of each fuel is measured before the fuels are 
mixed and combusted, then, for each component of the blend, calculate 
the CO2 mass emissions separately. Substitute into Equation 
C-2a of this subpart the total measured mass or volume of the component 
fuel (from company records), together with the appropriate default 
CO2 emission factor from Table C-1, and the annual average 
HHV, calculated according to Sec.  98.33(a)(2)(ii). In this case, the 
fact that the fuels are blended prior to combustion is of no 
consequence.
    (ii) If the fuel is received as a blend (i.e., already mixed), a 
reasonable estimate of the relative proportions of the components of 
the blend must be made, using the best available information (e.g., the 
approximate annual average mass or volume percentage of each fuel, 
based on the typical or expected range of values). Determine the 
appropriate CO2 emission factor and HHV for use in Equation 
C-2a of this subpart, as follows:
    (A) Consider the blend to be the ``fuel type,'' measure its HHV at 
the frequency prescribed in paragraph (a)(2)(v) of this section, and 
determine the annual average HHV value for the blend according to Sec.  
98.33(a)(2)(ii).
    (B) Calculate a heat-weighted CO2 emission factor, 
(EF)B, for the blend, using Equation C-16 of this section. 
The heat-weighting in Equation C-16 is provided by the default HHVs 
(from Table C-1) and the estimated mass or volume percentages of the 
components of the blend.
    (C) Substitute into Equation C-2a of this subpart, the annual 
average HHV for the blend (from paragraph (a)(3)(ii)(A) of this 
section) and the calculated value of (EF)B, along with the 
total mass or volume of the blend combusted during the reporting year, 
to determine the annual CO2 mass emissions from combustion 
of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.005

    Where:

(EF)B = Heat-weighted CO2 emission factor for 
the blend (kg CO2/mmBtu)
(HHV)I = Default high heat value for fuel ``i'' in the 
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel 
``i'' (mass % or volume %, as applicable, expressed as a decimal 
fraction; e.g., 25% = 0.25)
(EF)I = Default CO2 emission factor for fuel 
``i'' from Table C-1 (mmBtu per mass or volume)
(HHV)B = Annual average high heat value for the blend, 
calculated according to Sec.  98.33(a)(2)(ii) (mmBtu per mass or 
volume)

    (iii) Note that for the case described in paragraph (a)(3)(ii) of 
this section, if measured HHV values for the individual fuels in the 
blend or for the blend itself are not routinely received at the minimum 
frequency prescribed in paragraph (a)(2) of this section (or at a 
greater frequency), and if the unit qualifies to use Tier 1, calculate 
(HHV)B*, the heat-weighted default HHV for the blend, using 
Equation C-17 of this section. Then, use Equation C-16 of this section, 
replacing the term (HHV)B with (HHV)B* in the 
denominator, to determine the heat-weighted CO2 emission 
factor for the blend. Finally, substitute into Equation C-1 of this 
subpart, the calculated values of (HHV)B* and 
(EF)B, along with the total mass or volume of the blend 
combusted during the reporting year, to determine the annual 
CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.006

    Where:

(HHV)B* = Heat-weighted default high heat value for the 
blend (mmBtu per mass or Volume)
(HHV)I = Default high heat value for fuel ``i'' in the 
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel 
``i'' in the blend (mass % or volume %, as applicable, expressed as 
a decimal fraction)

    (iv) If the fuel blend described in paragraph (a)(3)(ii) of this 
section consists of a mixture of fuel(s) listed in Table C-1 of this 
subpart and one or more fuels not listed in Table C-1, calculate 
CO2 and other GHG emissions only for the Table C-1 fuel(s), 
using the best available estimate of the mass or volume percentage(s) 
of the Table C-1 fuel(s) in the blend. In this case, Tier 1 shall be 
used, with the following modifications to Equations C-17 and C-1, to 
account for the fact that not all of the fuels in the blend are listed 
in Table C-1:
    (A) In Equation C-17, apply the term (Fuel)i only to the 
Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will be 
the estimated mass or volume percentage of the fuel in the blend, 
divided by the sum of the mass or volume percentages of the Table C-1 
fuels. For example,

[[Page 48794]]

suppose that a blend consists of two Table C-1 fuels (``A'' and ``B'') 
and one fuel type (``C'') not listed in the Table, and that the volume 
percentages of fuels A, B, and C in the blend, expressed as decimal 
fractions, are, respectively, 0.50, 0.30, and 0.20. The term 
(Fuel)i in Equation C-17 for fuel A will be 0.50/(0.50 + 
0.30) = 0.625, and for fuel B, (Fuel)i will be 0.30/(0.50 + 
0.30) = 0.375.
    (B) In Equation C-1, the term ``Fuel'' will be equal to the total 
mass or volume of the blended fuel combusted during the year multiplied 
by the sum of the mass or volume percentages of the Table C-1 fuels in 
the blend. For the example in paragraph (a)(3)(iv)(A) of this section, 
``Fuel'' = (Annual volume of the blend combusted) (0.80).
* * * * *
    (6) You must use one of the following appropriate fuel sampling and 
analysis methods. You may use a method published by a consensus 
standards organization if such a method exists, or you may use industry 
consensus standard practice to determine the high heat values. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB). 
Alternatively, for gaseous fuels, the HHV may be calculated using 
chromatographic analysis together with standard heating values of the 
fuel constituents, provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer's 
instructions. The method(s) used shall be documented in the Monitoring 
Plan required under Sec.  98.3(g)(5).
    (b) * * *
    (1) You must calibrate each oil and gas flow meter according to 
Sec.  98.3(i) and the provisions of this paragraph (b)(1).
    (i) Perform calibrations using any of the test methods and 
procedures in this paragraph (b)(1)(i). The method(s) used shall be 
documented in the Monitoring Plan required under Sec.  98.3(g)(5).
    (A) You may use an appropriate flow meter calibration method 
published by a consensus standards organization, if such a method 
exists. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International, the American National 
Standards Institute (ANSI), the American Gas Association (AGA), the 
American Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB).
    (B) You may use the calibration procedures specified by the flow 
meter manufacturer.
    (C) You may use an industry-accepted or industry consensus standard 
calibration practice.
    (ii) In addition to the initial calibration required by Sec.  
98.3(i), recalibrate each fuel flow meter (except as otherwise provided 
in paragraph (b)(1)(iii) of this section) either annually, at the 
minimum frequency specified by the manufacturer, or at the interval 
specified by industry consensus standard practice.
    (iii) Fuel billing meters are exempted from the initial and ongoing 
calibration requirements of this paragraph and from the Monitoring Plan 
and recordkeeping requirements of Sec.  98.3(g)(5)(i)(C) and (g)(7), 
provided that the fuel supplier and the unit combusting the fuel do not 
have any common owners and are not owned by subsidiaries or affiliates 
of the same company. Meters used exclusively to measure the flow rates 
of fuels that are only used for unit startup or ignition are also 
exempted from the initial and ongoing calibration requirements of this 
paragraph.
* * * * *
    (vi) If a mixture of liquid or gaseous fuels is transported by a 
common pipe, you may either separately meter each of the fuels prior to 
mixing, using flow meters calibrated according to Sec.  98.3(i), or 
consider the fuel mixture to be the ``fuel type'' and meter the mixed 
fuel, using a flow meter calibrated according to Sec.  98.3(i).
* * * * *
    (3) * * *
    (ii) For each type of fuel, the minimum required frequency for 
collecting and analyzing samples for carbon content and (if applicable) 
molecular weight is specified in this paragraph. When the sampling 
frequency is based on a specified time period (e.g., week, month, 
quarter, or half-year), fuel sampling and analysis is required for only 
those time periods in which the fuel is combusted.
    (A) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at 
least four months apart).
    (B) For coal and fuel oil and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the storage tank. Flow proportional sampling, continuous drip 
sampling, or daily manual oil sampling may also be used, in lieu of 
sampling each fuel lot. For the purposes of this section, a fuel lot is 
defined as either of the following:
    (1) A shipment or delivery of a single fuel (e.g., ship load, barge 
load, group of trucks, group of railroad cars, oil delivery via 
pipeline from a tank farm, etc.).
    (2) If multiple deliveries of a particular type of fuel are 
received from the same supply source in a given calendar month, the 
deliveries for that month are considered, collectively, to comprise a 
fuel lot, requiring only one representative sample.
    (C) For liquid fuels other than fuel oil and for biogas; sampling 
and analysis is required at least once per calendar quarter. To the 
extent practicable, consecutive quarterly samples shall be taken at 
least 30 days apart.
    (D) For other solid fuels (except MSW), weekly sampling is required 
to obtain composite samples, which are then analyzed monthly.
    (E) For gaseous fuels other than natural gas and biogas (e.g., 
process gas), daily sampling and analysis to determine the carbon 
content and molecular weight of the fuel is required if continuous, on-
line equipment, such as a gas chromatograph, is in place to make these 
measurements. Otherwise, weekly sampling and analysis shall be 
performed.
    (F) For mixtures (blends) of solid fuels, weekly sampling is 
required to obtain composite samples, which are analyzed monthly. For 
blends of liquid fuels, and for gas mixtures consisting only of natural 
gas and biogas, sampling and analysis is required at least once per 
calendar quarter. For gas mixtures that contain gases other than 
natural gas (including biogas), daily sampling and analysis to 
determine the carbon content and molecular weight of the fuel is 
required if continuous, on-line equipment is in place to make these 
measurements. Otherwise, weekly sampling and analysis shall be 
performed.
* * * * *
    (v) To calculate the CO2 mass emissions from combustion 
of a blend of fuels in the same state of matter (solid, liquid, or 
gas), you may either:
    (A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) 
to each component of the blend, if the mass or volume, the carbon 
content, and (if applicable), the molecular weight of each component 
are accurately measured prior to blending; or
    (B) Consider the blend to be the ``fuel type.'' Then, at the 
frequency specified

[[Page 48795]]

in paragraph (b)(3)(ii)(F) of this section, measure the carbon content 
and, if applicable, the molecular weight of the blend and calculate the 
annual average value of each parameter in the manner described in Sec.  
98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel 
combusted during the reporting year. Substitute these measured values 
into Equation C-3, C-4, or C-5 of this subpart (as applicable).
    (4) You must use one of the following appropriate fuel sampling and 
analysis methods. You may use a method published by a consensus 
standards organization if such a method exists, or you may use industry 
consensus standard practice to determine the carbon content and 
molecular weight (for gaseous fuel) of the fuel. Consensus-based 
standards organizations include, but are not limited to, the following: 
ASTM International, the American National Standards Institute (ANSI), 
the American Gas Association (AGA), the American Society of Mechanical 
Engineers (ASME), the American Petroleum Institute (API), and the North 
American Energy Standards Board (NAESB). Alternatively, the results of 
chromatographic analysis of the fuel may be used, provided that the gas 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions. The method(s) used shall be documented in 
the Monitoring Plan required under Sec.  98.3(g)(5).
    (c) For the Tier 4 Calculation Methodology, the CO2, 
flow rate, and (if applicable) moisture monitors must be certified 
prior to the applicable deadline specified in Sec.  98.33(b)(5).
    (1) * * *
    (i) Sections 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this 
chapter and appendix A to part 75 of this chapter.
    (ii) The calibration drift test and relative accuracy test audit 
(RATA) procedures of Performance Specification 3 in appendix B to part 
60 of this chapter (for the CO2 concentration monitor) and 
Performance Specification 6 in appendix B to part 60 of this chapter 
(for the continuous emission rate monitoring system (CERMS)).
* * * * *
    (2) If an O2 concentration monitor is used to determine 
CO2 concentrations, the applicable provisions of part 75 of 
this chapter, part 60 of this chapter, or an applicable State 
continuous monitoring program shall be followed for initial 
certification and on-going quality assurance, and all required RATAs of 
the monitor shall be done on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures 
in either appendix B to part 75 of this chapter, appendix F to part 60 
of this chapter, or an applicable State continuous monitoring program. 
If appendix F to part 60 of this chapter is selected for on-going 
quality assurance, perform daily calibration drift assessments for both 
the CO2 monitor (or surrogate O2 monitor) and the 
flow rate monitor, conduct cylinder gas audits of the CO2 
concentration monitor in three of the four quarters of each year 
(except for non-operating quarters), and perform annual RATAs of the 
CO2 concentration monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow 
rate monitor RATAs required by appendix B to part 75 of this chapter 
and the annual RATAs of the CERMS required by appendix F to part 60 of 
this chapter need only be done at one operating level, representing 
normal load or normal process operating conditions, both for initial 
certification and for ongoing quality assurance.
* * * * *
    (6) For certain applications where combined process emissions and 
combustion emissions are measured, the CO2 concentrations in 
the flue gas may be considerably higher than for combustion emissions 
alone. In such cases, the span of the CO2 monitor may, if 
necessary, be set higher than the specified levels in the applicable 
regulations. If the CO2 span value is set higher than 20 
percent CO2, the cylinder gas audits of the CO2 
monitor under appendix F to part 60 of this chapter may be performed at 
40 to 60 percent and 80 to 100 percent of span, in lieu of the 
prescribed calibration levels of 5 to 8 percent CO2 and 10 
to 14 percent CO2.
    (7) Hourly average data from the CEMS shall be validated in a 
manner consistent with one of the following: Sec. Sec.  60.13(h)(2)(i) 
through (h)(2)(vi) of this chapter; Sec.  75.10(d)(1) of this chapter; 
or the hourly data validation requirements of an applicable State CEM 
regulation.
    (d) When municipal solid waste (MSW) is either the primary fuel 
combusted in a unit or the only fuel with a biogenic component 
combusted in the unit, determine the biogenic portion of the 
CO2 emissions using ASTM D6866-08 Standard Test Methods for 
Determining the Biobased Content of Solid, Liquid, and Gaseous Samples 
Using Radiocarbon Analysis (incorporated by reference, see Sec.  98.7) 
and ASTM D7459-08 Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources (incorporated 
by reference, see Sec.  98.7). Perform the ASTM D7459-08 sampling and 
the ASTM D6866-08 analysis at least once in every calendar quarter in 
which MSW is combusted in the unit. Collect each gas sample during 
normal unit operating conditions for at least 24 consecutive hours or 
for as long as is deemed necessary to obtain a representative sample. 
One suggested alternative sampling approach would be to collect an 
integrated sample by extracting a small amount of flue gas (e.g., 1 to 
5 cc) in each unit operating hour during the quarter. Separate the 
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions 
of all samples analyzed during the reporting year. Express the results 
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2 
is biogenic). When MSW is the primary fuel for multiple units at the 
facility, and the units are fed from a common fuel source, testing at 
only one of the units is sufficient.
    (e) For other units that combust combinations of biomass fuel(s) 
(or heterogeneous fuels that have a biomass component, e.g., tires) and 
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
08 and ASTM D7459-08 may be used to determine the biogenic portion of 
the CO2 emissions. Perform the ASTM D7459-08 sampling and 
the ASTM D6866-08 analysis in every calendar quarter in which biomass 
and non-biogenic fuels are co-fired in the unit. Collect each gas 
sample using ASTM D7459-08 during normal unit operation for at least 24 
consecutive hours or for as long as is necessary to obtain a 
representative sample. If the types of fuels combusted in the unit and 
their relative proportions are not consistent throughout the quarter, 
more frequent, periodic sampling of the flue gas should be considered. 
For example, an integrated sample could be collected by extracting a 
small amount of the flue gas (e.g., 1 to 5 cc) in each unit operating 
hour of the quarter. If the primary fuel for multiple units at the 
facility consists of tires, and the units are fed from a common fuel 
source, testing at only one of the units is sufficient.
    (f) The records required under Sec.  98.3(g)(2)(i) shall include an 
explanation of how the following parameters are determined from company 
records (or, if applicable, from the best available information):
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation 
Methodologies

[[Page 48796]]

are used, including cases where Sec.  98.36(c)(4) applies.
* * * * *
    (3) Fossil fuel consumption when Sec.  98.33(e)(2) applies to a 
unit that uses CEMS to quantify CO2 emissions and that 
combusts both fossil and biomass fuels.
* * * * *
    (5) Quantity of steam generated by a unit when Sec.  
98.33(a)(2)(iii) applies.
* * * * *
    (7) Fuel usage for CH4 and N2O emissions 
calculations under Sec.  98.33(c)(4)(ii).
    (8) Mass of biomass combusted, for premixed fuels that contain 
biomass and fossil fuels under Sec.  98.33(e)(1)(iii).
    11. Section 98.35 is amended by revising paragraph (a) to read as 
follows:

Sec.  98.35  Procedures for estimating missing data.

* * * * *
    (a) For all units subject to the requirements of the Acid Rain 
Program, and all other stationary combustion units subject to the 
requirements of this part that monitor and report emissions and heat 
input data in accordance with part 75 of this chapter, the missing data 
substitution procedures in part 75 of this chapter shall be followed 
for CO2 concentration, stack gas flow rate, fuel flow rate, 
high heating value, and fuel carbon content.
* * * * *
    12. Section 98.36 is amended by:
    a. Revising paragraph (b)(5).
    b. Removing paragraphs (b)(9) and (b)(10).
    c. Redesignating paragraphs (b)(6) through (b)(8) as paragraphs 
(b)(8) through (b)(10), respectively.
    d. Revising newly designated paragraphs (b)(8) and (b)(9).
    e. Adding new paragraphs (b)(6) and (b)(7).
    f. Revising paragraphs (c)(1)(ii), (c)(1)(vi), and (c)(1)(vii).
    g. Redesignating paragraph (c)(1)(viii) as paragraph (c)(1)(x), and 
revising newly designated paragraph (c)(1)(x).
    h. Removing paragraph (c)(1)(ix).
    i. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix).
    j. Revising paragraphs (c)(2) introductory text, (c)(2)(ii), 
(c)(2)(iii), and (c)(2)(v).
    k. Removing paragraph (c)(2)(viii).
    l. Redesignating paragraphs (c)(2)(vi) and (c)(2)(vii) as 
paragraphs (c)(2)(viii) and (c)(2)(ix), and revising newly designated 
paragraphs (c)(2)(viii) and (c)(2)(ix).
    m. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii).
    n. Revising paragraphs (c)(3) introductory text, (c)(3)(ii), 
(c)(3)(iii), and (c)(3)(vii).
    o. Removing paragraph (c)(3)(viii).
    p. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), and (c)(4).
    q. Revising paragraph (d).
    r. Revising paragraphs (e)(1)(iii), (e)(2)(i), (e)(2)(ii)(C), 
(e)(2)(ii)(D), (e)(2)(iii), and (e)(2)(iv)(A), (e)(2)(iv)(C).
    s. Adding new paragraphs (e)(2)(iv)(F) and (e)(2)(v)(E).
    t. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) introductory 
text, and (e)(2)(x) introductory text.
    u. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C).
    v. Redesignating paragraph (e)(2)(x)(D) as (e)(2)(x)(B), and 
revising newly designated paragraph (e)(2)(x)(B).
    w. Revising paragraph (e)(2)(xi).

Sec.  98.36  Data reporting requirements.

* * * * *
    (b) * * *
    (5) The methodology (i.e., tier) used to calculate the 
CO2 emissions for each type of fuel combusted (i.e., Tier 1, 
2, 3, or 4).
    (6) The methodology start date, for each fuel type.
    (7) The methodology end date, for each fuel type.
    (8) For a unit that uses Tiers 1, 2, or 3:
    (i) The annual CO2 mass emissions (including biogenic 
CO2), and the annual CH4, and N2O mass 
emissions for each type of fuel combusted during the reporting year, 
expressed in metric tons of each gas and in metric tons of 
CO2e; and
    (ii) Metric tons of biogenic CO2 emissions (if 
applicable).
    (9) For a unit that uses Tier 4:
    (i) If the total annual CO2 mass emissions measured by 
the CEMS consists entirely of non-biogenic CO2 (i.e., 
CO2 from fossil fuel combustion plus, if applicable, 
CO2 from sorbent and/or process CO2), report the 
total annual CO2 mass emissions, expressed in metric tons. 
You are not required to report the combustion CO2 emissions 
by fuel type.
    (ii) If the total annual CO2 mass emissions measured by 
the CEMS includes both biogenic and non-biogenic CO2, 
separately report the annual non-biogenic CO2 mass emissions 
and the annual CO2 mass emissions from biomass combustion, 
each expressed in metric tons. You are not required to report the 
combustion CO2 emissions by fuel type.
    (iii) An estimate of the heat input from each type of fuel listed 
in Table C-2 of this subpart that was combusted in the unit during the 
report year, and the annual CH4 and N2O emissions 
for each of these fuels, expressed in metric tons of each gas and in 
metric tons of CO2e.
* * * * *
    (c) * * *
    (1) * * *
    (ii) The number of units in the group.
* * * * *
    (vi) Annual CO2 mass emissions and annual 
CH4, and N2O mass emissions, aggregated for each 
type of fuel combusted in the group of units during the report year, 
expressed in metric tons of each gas and in metric tons of 
CO2e. If any of the units burn both fossil fuels and 
biomass, report also the annual CO2 emissions from 
combustion of all fossil fuels combined and annual CO2 
emissions from combustion of all biomass fuels combined, expressed in 
metric tons.
    (vii) The methodology (i.e., tier) used to calculate the 
CO2 mass emissions for each type of fuel combusted in the 
units (i.e., Tier 1, Tier 2, or Tier 3).
    (viii) The methodology start date, for each fuel type.
    (ix) The methodology end date, for each fuel type.
    (x) The calculated CO2 mass emissions (if any) from 
sorbent expressed in metric tons.
    (2) Monitored common stack or duct configurations. When the flue 
gases from two or more stationary fuel combustion units at a facility 
are combined together in a common stack or duct before exiting to the 
atmosphere and if CEMS are used to continuously monitor CO2 
mass emissions at the common stack or duct according to the Tier 4 
Calculation Methodology, you may report the combined emissions from the 
units sharing the common stack or duct, in lieu of separately reporting 
the GHG emissions from the individual units. This monitoring and 
reporting alternative may also be used when process off-gases or a 
mixture of combustion products and process gases are combined together 
in a common stack or duct before exiting to the atmosphere. Whenever 
the common stack or duct monitoring option is applied, the following 
information shall be reported instead of the information in paragraph 
(b) of this section:
* * * * *
    (ii) Number of units sharing the common stack or duct. Report ``1'' 
when the flue gas flowing through the common stack or duct includes 
both combustion products and process off-gases, and all of the effluent 
comes from a single unit (e.g., a furnace, kiln, or smelter).
    (iii) Combined maximum rated heat input capacity of the units 
sharing the

[[Page 48797]]

common stack or duct (mmBtu/hr). This data element is required only 
when all of the units sharing the common stack are stationary fuel 
combustion units.
* * * * *
    (v) The methodology (tier) used to calculate the CO2 
mass emissions, i.e., Tier 4.
    (vi) The methodology start date.
    (vii) The methodology end date.
    (viii) Total annual CO2 mass emissions measured by the 
CEMS, expressed in metric tons. If any of the units burn both fossil 
fuels and biomass, separately report the annual non-biogenic 
CO2 mass emissions (i.e., CO2 from fossil fuel 
combustion plus, if applicable, CO2 from sorbent and/or 
process CO2) and the annual CO2 mass emissions 
from biomass combustion, each expressed in metric tons.
    (ix) An estimate of the heat input from each type of fuel listed in 
Table C-2 of this subpart that was combusted during the report year in 
the units sharing the common stack or duct during the report year, and, 
for each of these fuels, the annual CH4 and N2O 
mass emissions from the units sharing the common stack or duct, 
expressed in metric tons of each gas and in metric tons of 
CO2e.
    (3) Common pipe configurations. When two or more liquid-fired or 
gaseous-fired stationary combustion units at a facility combust the 
same type of fuel and the fuel is fed to the individual units through a 
common supply line or pipe, you may report the combined emissions from 
the units served by the common supply line, in lieu of separately 
reporting the GHG emissions from the individual units, provided that 
the total amount of fuel combusted by the units is accurately measured 
at the common pipe or supply line using a fuel flow meter. For Tier 3 
applications, the flow meter shall be calibrated in accordance with 
Sec.  98.34(b). If a portion of the fuel measured at the main supply 
line is diverted to either: A flare; or another stationary fuel 
combustion unit (or units), including units that use a CO2 
mass emissions calculation method in part 75 of this chapter; or a 
chemical or industrial process (where it is used as a raw material but 
not combusted), and the remainder of the fuel is distributed to a group 
of combustion units for which you elect to use the common pipe 
reporting option, you may use company records to subtract out the 
diverted portion of the fuel from the fuel measured at the main supply 
line prior to performing the GHG emissions calculations for the group 
of units using the common pipe option. If the diverted portion of the 
fuel is combusted, the GHG emissions from the diverted portion shall be 
accounted for in accordance with the applicable provisions of this 
part. When the common pipe option is selected, the applicable tier 
shall be used based on the maximum rated heat input capacity of the 
largest unit served by the common pipe configuration, except where the 
applicable tier is based on criteria other than unit size. For example, 
if the maximum rated heat input capacity of the largest unit is greater 
than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported 
through the common pipe is natural gas or distillate oil, in which case 
Tier 2 may be used, in accordance with Sec.  98.33(b)(2)(ii). As a 
second example, in accordance with Sec.  98.33(b)(1)(v), Tier 1 may be 
used regardless of unit size when natural gas is transported through 
the common pipe, if the annual fuel consumption is obtained from gas 
billing records in units of therms. When the common pipe reporting 
option is selected, the following information shall be reported instead 
of the information in paragraph (b) of this section:
* * * * *
    (ii) The number of units served by the common pipe.
    (iii) The highest maximum rated heat input capacity of any unit 
served by the common pipe (mmBtu/hr).
* * * * *
    (vii) Annual CO2 mass emissions and annual 
CH4 and N2O emissions from each fuel type for the 
units served by the common pipe, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (viii) Methodology start date.
    (ix) Methodology end date.
    (4) The following alternative reporting option applies to 
situations where a common liquid or gaseous fuel supply is shared 
between one or more large combustion units, such as boilers or 
combustion turbines (including units subject to subpart D of this 
part); and small combustion sources on-site, including but not limited 
to space heaters and hot water heaters. In this case, you may simplify 
reporting by attributing all of the GHG emissions from combustion of 
the shared fuel to the large combustion unit(s), provided that:
    (i) The total quantity of the fuel combusted during the report year 
in the units sharing the fuel supply is measured, either at the 
``gate'' to the facility or at a point inside the facility, using a 
fuel flow meter, billing meter, or tank drop measurements (as 
applicable);
    (ii) On an annual basis, at least 95 percent (by mass or volume) of 
the shared fuel is combusted in the large combustion unit(s), and the 
remainder is combusted in the small combustion sources. Company records 
may be used to determine the percentage distribution of the shared fuel 
to the large and small units; and
    (iii) The use of this reporting option is documented in the 
Monitoring Plan required under Sec.  98.3(g)(5). Indicate in the 
Monitoring Plan which units share the common fuel supply and the method 
used to demonstrate that this alternative reporting option applies. For 
the small combustion sources on-site, a description of the types of 
units and the approximate number of units is sufficient.
    (d) Units subject to part 75 of this chapter.
    (1) For stationary combustion units that are subject to subpart D 
of this part, you shall report the following unit-level information:
    (i) Unit or stack identification numbers. Use exact same unit, 
common stack, common pipe, or multiple stack identification numbers 
that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, 
etc.) that are reported under Sec.  75.64 of this chapter.
    (ii) Annual CO2 emissions at each monitored location, 
expressed in both short tons and metric tons. Reporting of biogenic 
CO2 emissions under Sec.  98.3(c)(4)(ii) and Sec.  
98.3(c)(4)(iii)(A) is optional. Subpart D units are not required to 
report biogenic CO2 emissions under Sec. Sec.  
98.3(c)(4)(ii) and (c)(4)(iii)(A).
    (iii) Annual CH4 and N2O emissions at each 
monitored location, for each fuel type listed in Table C-2 that was 
combusted during the year (except as otherwise provided in Sec.  
98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
    (iv) The total heat input from each fuel listed in Table C-2 that 
was combusted during the year (except as otherwise provided in Sec.  
98.33(c)(4)(ii)(B)), expressed in mmBtu.
    (v) Identification of the Part 75 methodology used to determine the 
CO2 mass emissions.
    (vi) Methodology start date.
    (vii) Methodology end date.
    (viii) Acid Rain Program indicator.
    (ix) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons of CO2e (optional).
    (2) For units that use the alternative CO2 mass 
emissions calculation methods provided in Sec.  98.33(a)(5), you shall 
report the following unit-level information:
    (i) Unit, stack, or pipe ID numbers. Use exact same unit, common 
stack,

[[Page 48798]]

common pipe, or multiple stack identification numbers that represent 
the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are 
reported under Sec.  75.64 of this chapter.
    (ii) For units that use the alternative methods specified in Sec.  
98.33(a)(5)(i) and (ii) to monitor and report heat input data year-
round according to appendix D to part 75 of this chapter or Sec.  75.19 
of this chapter:
    (A) Each type of fuel combusted in the unit during the reporting 
year.
    (B) The methodology used to calculate the CO2 mass 
emissions for each fuel type.
    (C) Methodology start date.
    (D) Methodology end date.
    (E) A code or flag to indicate whether heat input is calculated 
according to appendix D to part 75 of this chapter or Sec.  75.19 of 
this chapter.
    (F) Annual CO2 emissions at each monitored location, 
across all fuel types, expressed in metric tons of CO2e.
    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emisions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec.  98.33(c)(4)(ii)(D)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e (optional).
    (iii) For units with continuous monitoring systems that use the 
alternative method for units with continuous monitoring systems in 
Sec.  98.33(a)(5)(iii) to monitor heat input year-round according to 
part 75 of this chapter:
    (A) Each type of fuel combusted during the reporting year.
    (B) Methodology used to calculate the CO2 mass 
emissions.
    (C) Methodology start date.
    (D) Methodology end date.
    (E) A code or flag to indicate that the heat input data is derived 
from CEMS measurements.
    (F) The total annual CO2 emissions at each monitored 
location, expressed in metric tons of CO2e.
    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emisions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec.  98.33(c)(4)(ii)(B)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e (optional).
    (e) * * *
    (1) * * *
    (iii) Are not in the Acid Rain Program, but are required to monitor 
and report CO2 mass emissions and heat input data year-
round, in accordance with part 75 of this chapter.
    (2) * * *
    (i) For the Tier 1 Calculation Methodology, report the total 
quantity of each type of fuel combusted in the unit or group of 
aggregated units (as applicable) during the reporting year, in short 
tons for solid fuels, gallons for liquid fuels and standard cubic feet 
or, if applicable, therms for gaseous fuels.
    (ii) * * *
    (C) The high heat values used in the CO2 emissions 
calculations for each type of fuel combusted during the reporting year, 
in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid 
fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each 
calendar month in which HHV determination is required. If multiple 
values are obtained in a given month, report the arithmetic average 
value for the month. Indicate whether each reported HHV is a measured 
value or a substitute data value.
    (D) If Equation C-2c of this subpart is used to calculate 
CO2 mass emissions, report the total quantity (i.e., pounds) 
of steam produced from MSW or solid fuel combustion during each month 
of the reporting year, and the ratio of the maximum rate heat input 
capacity to the design rated steam output capacity of the unit, in 
mmBtu per lb of steam.
    (iii) For the Tier 2 Calculation Methodology, keep records of the 
methods used to determine the HHV for each type of fuel combusted and 
the date on which each fuel sample was taken, except where fuel 
sampling data are received from the fuel supplier. In that case, keep 
records of the dates on which the results of the fuel analyses for HHV 
are received.
    (iv) * * *
    (A) The quantity of each type of fuel combusted in the unit or 
group of units (as applicable) during each month of the reporting year, 
in short tons for solid fuels, gallons for liquid fuels, and scf for 
gaseous fuels.
* * * * *
    (C) The carbon content and, if applicable, gas molecular weight 
values used in the emission calculations (including both valid and 
substitute data values). For each calendar month of the reporting year 
in which carbon content and, if applicable, molecular weight 
determination is required, report a value of each parameter. If 
multiple values of a parameter are obtained in a given month, report 
the arithmetic average value for the month. Express carbon content as a 
decimal fraction for solid fuels, kg C per gallon for liquid fuels, and 
kg C per kg of fuel for gaseous fuels. Express the gas molecular 
weights in units of kg per kg-mole.
* * * * *
    (F) The annual average HHV, when measured HHV data, rather than a 
default HHV from Table C-1 of this subpart, are used to calculate 
CH4 and N2O emissions for a Tier 3 unit, in 
accordance with Sec.  98.33(c)(1).
    (v) * * *
    (E) The date on which each fuel sample was taken, except where fuel 
sampling data are received from the fuel supplier. In that case, keep 
records of the dates on which the results of the fuel analyses for 
carbon content and (if applicable) molecular weight are received.
* * * * *
    (vii) * * *
    (A) Whether the CEMS certification and quality assurance procedures 
of part 75 of this chapter, part 60 of this chapter, or an applicable 
State continuous monitoring program were used.
* * * * *
    (ix) For units that combust both fossil fuel and biomass, when 
biogenic CO2 is determined according to Sec.  98.33(e)(2), 
you shall report the following additional information, as applicable:
* * * * *
    (x) When ASTM methods D7459-08 and D6866-08 are used to determine 
the biogenic portion of the annual CO2 emissions from MSW 
combustion, as described in Sec.  98.34(d), report:
* * * * *
    (B) The annual biogenic CO2 mass emissions from MSW 
combustion, in metric tons.
    (xi) When ASTM methods D7459-08 and D6866-08 are used in accordance 
with Sec.  98.34(e) to determine the biogenic portion of the annual 
CO2 emissions from a unit that co-fires biogenic fuels (or 
partly-biogenic fuels, including tires if you are electing to report 
biogenic CO2 emissions from tire combustion) and non-
biogenic fuels, you shall report the results of each quarterly sample 
analysis, expressed as a decimal fraction (e.g., if the biogenic 
fraction of the CO2 emissions is 30 percent, report 0.30).
* * * * *
    13. Table C-1 of Supart C of Part 98 is amended by:

[[Page 48799]]

    a. Revising the title to read ``Table C-1 to Subpart C--Default 
CO2 Emission Factors and High Heat Values for Various Types 
of Fuel.''
    b. Revising the entry for ``Pipeline (Weighted U.S. Average).''
    c. Removing the entry for ``Still Gas.''
    d. Adding an entry for ``Waste Oil'' to follow the entry for 
``Residual Fuel Oil No. 6.''
    e. Adding an entry for ``Ethanol'' to follow the entry for 
``Ethane.''
    f. Revising the entry for ``Fossil fuel-derived fuels (solid).''
    g. Revising the entry for ``Municipal Solid Waste.''
    h. Adding entries for ``Plastics'' and ``Petroleum Coke'' to follow 
the entry for ``Tires.''
    i. Revising the entry for ``Fossil fuel-derived fuels (gaseous).''
    j. Adding entries for ``Propane Gas'' and ``Fuel Gas'' to follow 
the entry for ``Coke Oven Gas.''
    k. Revising the entry for ``Biomass fuels--solid.''
    l. Revising the entry for ``Biomass fuels--liquid'' by centering 
``Biomass fuels--liquid.''
    m. Revising the entries for ``Ethanol'' and ``Biodiesel'' that 
follow the entry for ``Biomass fuels--liquid.''
    n. Revising footnote ``1.''
    o. Adding a new footnote ``2.''

   Table C-1 to Subpart C--Default CO2 Emission Factors and High Heat
                    Values for Various Types of Fuel
------------------------------------------------------------------------
                                Default high heat   Default CO2 emission
           Fuel type                  value                factor
------------------------------------------------------------------------

                              * * * * * * *
(Weighted U.S. Average).......  1.028 x 10-3.....  53.02.

                              * * * * * * *
Waste Oil.....................  0.135............  74.00.

                              * * * * * * *
Ethanol.......................  0.084............  68.44.

                              * * * * * * *
Other fuels (solid)...........  mmBtu/short ton..  kg CO2/mmBtu.
Municipal Solid Waste.........  9.95 \1\.........  90.7.

                              * * * * * * *
Plastics......................  38.00............  75.00.
Petroleum Coke................  30.00............  102.41.
Other fuels (gaseous).........  mmBtu/scf........  kg CO2/mmBtu.

                              * * * * * * *
Propane Gas...................  2.516 x 10-3.....  61.46.
Fuel Gas \2\..................  1.388 x 10-3.....  59.00.
Biomass fuels--solid..........  mmBtu/short ton..  kg CO2/mmBtu.

                              * * * * * * *
Ethanol.......................  0.084............  68.44.
Biodiesel.....................  0.128............  73.84.

                              * * * * * * *
------------------------------------------------------------------------
\1\ Use of this default HHV is allowed only for units that combust MSW,
  do not generate steam, and are allowed to use Tier 1.
\2\ Reporters subject to subpart X of this part that are complying with
  Sec.   98.243(d) or subpart Y of this part may only use the default
  HHV and the default CO2 emission factor for fuel gas combustion under
  the conditions prescribed in Sec.   98.243(d)(2)(i) and (d)(2)(ii) and
  Sec.   98.252(a)(1) and (a)(2), respectively. Otherwise, Tier 3
  (Equation C-5) or Tier 4 must be used.

    14. The first Table C-2 is removed, and the second Table C-2 is 
revised to read as follows:

             Table C-2 to Subpart C--Default CH4 and N2O Emission Factors for Various Types of Fuel
----------------------------------------------------------------------------------------------------------------
                                                                  Default CH4 emission     Default N2O emission
                           Fuel type                             factor  (kg CH4/mmBtu)   factor  (kg N2O/mmBtu)
----------------------------------------------------------------------------------------------------------------
Coal and Coke (All fuel types in Table C-1)...................              1.1 x 10-02              1.6 x 10-03
Natural Gas...................................................              1.0 x 10-03              1.0 x 10-04
Petroleum (All fuel types in Table C-1).......................              3.0 x 10-03              6.0 x 10-04
Municipal Solid Waste.........................................              3.2 x 10-02              4.2 x 10-03
Tires.........................................................              3.2 x 10-02              4.2 x 10-03
Blast Furnace Gas.............................................              2.2 x 10-05              1.0 x 10-04
Coke Oven Gas.................................................              4.8 x 10-04              1.0 x 10-04
Biomass Fuels--Solid (All fuel types in Table C-1)............              3.2 x 10-02              4.2 x 10-03
Biogas........................................................              3.2 x 10-03              6.3 x 10-04

[[Page 48800]]

Biomass Fuels--Liquid (All fuel types in Table C-1)...........              1.1 x 10-03              1.1 x 10-04
----------------------------------------------------------------------------------------------------------------
Note: Those employing this table are assumed to fall under the IPCC definitions of the ``Energy Industry'' or
  ``Manufacturing Industries and Construction''. In all fuels except for coal the values for these two
  categories are identical. For coal combustion, those who fall within the IPCC ``Energy Industry'' category may
  employ a value of 1 g of CH4/MMBtu.

Subpart D--[Amended]

    15. Section 98.40 is amended by revising paragraph (a) to read as 
follows:

Sec.  98.40  Definition of the source category.

    (a) The electricity generation source category comprises 
electricity generating units that are subject to the requirements of 
the Acid Rain Program and any other electricity generating units that 
are required to monitor and report to EPA CO2 mass emissions 
year-round according to 40 CFR part 75.
* * * * *
    16. Section 98.46 is revised to read as follows:

Sec.  98.46  Data reporting requirements.

    The annual report shall comply with the data reporting requirements 
specified in Sec.  98.36(d)(1).
    17. Section 98.47 is revised to read as follows:

Sec.  98.47  Records that must be retained.

    You shall comply with the recordkeeping requirements of Sec. Sec.  
98.3(g) and 98.37. Records retained under Sec.  75.57(h) of this 
chapter for missing data events satisfy the recordkeeping requirements 
of Sec.  98.3(g)(4) for those same events.

Subpart F--[Amended]

    18. Section 98.62 is amended by revising paragraphs (a) and (b) to 
read as follows:

Sec.  98.62  GHGs to report.

* * * * *
    (a) Perfluoromethane (CF4), and perfluoroethane 
(C2F6) emissions from anode effects in all 
prebake and S[oslash]derberg electrolysis cells.
    (b) CO2 emissions from anode consumption during 
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
* * * * *
    19. Section 98.63 is amended by:
    a. In paragraph (a), revising the only sentence and the definitions 
of ``EPFC,'' and ``Em'' in Equation F-1.
    b. Revising the only sentence of paragraph (b).
    c. Revising paragraph (c).

Sec.  98.63  Calculating GHG emissions.

    (a) The annual value of each PFC compound (CF4, 
C2F6) shall be estimated from the sum of monthly 
values using Equation F-1 of this section:
* * * * *
EPFC = Annual emissions of each PFC compound from aluminum 
production (metric tons PFC).
Em = Emissions of the individual PFC compound from aluminum 
production for the month ``m'' (metric tons PFC).

    (b) Use Equation F-2 of this section to estimate CF4 
emissions from anode effect duration or Equation F-3 of this section to 
estimate CF4 emissions from overvoltage, and use Equation F-
4 of this section to estimate C2F6 emissions from 
anode effects from each prebake and S[oslash]derberg electrolysis cell.
* * * * *
    (c) You must calculate and report the annual process CO2 
emissions from anode consumption during electrolysis and anode baking 
of prebake cells using either the procedures in paragraph (d) of this 
section, the procedures in paragraphs (e) and (f) of this section, or 
the procedures in paragraph (g) of this section.
* * * * *
    20. Section 98.64 is amended by revising the first sentence of 
paragraph (a); and by revising paragraph (b) to read as follows:

Sec.  98.64  Monitoring and QA/QC requirements.

    (a) Effective one year after publication of the rule for smelters 
with no prior measurement or effective three years after publication 
for facilities with historic measurements, the smelter-specific slope 
coefficients, overvoltage emission factors, and weight fractions used 
in Equations F-2, F-3, and F-4 of this subpart must be measured in 
accordance with the recommendations of the EPA/IAI Protocol for 
Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane 
(C2F6) Emissions from Primary Aluminum Production 
(2008), except the minimum frequency of measurement shall be every 10 
years unless a change occurs in the control algorithm that affects the 
mix of types of anode effects or the nature of the anode effect 
termination routine. * * *
    (b) The minimum frequency of the measurement and analysis is 
annually except as follows:
    (1) Monthly for anode effect minutes per cell day (or anode effect 
overvoltage and current efficiency).
    (2) Monthly for aluminum production.
    (3) Smelter-specific slope coefficients, overvoltage emission 
factors, and weight fractions according to paragraph (a) of this 
section.
* * * * *
    21. Section 98.65 is amended by revising the only sentence of 
paragraph (a) to read as follows:

Sec.  98.65  Procedures for estimating missing data.

* * * * *
    (a) Where anode or paste consumption data are missing, 
CO2 emissions can be estimated from aluminum production per 
Equation F-8 of this section.
* * * * *
    22. Section 98.66 is amended by revising paragraph (c)(1) to read 
as follows:

Sec.  98.66  Data reporting requirements.

* * * * *
    (c) * * *
    (1) Perfluoromethane emissions and perfluoroethane emissions from 
anode effects in all prebake and all S[oslash]derberg electrolysis 
cells combined.
* * * * *
    23. In the table to Supart F of Part 98, revise Table F-1 to read 
as follows:

[[Page 48801]]

  Table F-1 to Subpart F--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions from Aluminum
                                                   Production
----------------------------------------------------------------------------------------------------------------
                                                           CF4 slope
                                                       coefficient  [(kg    CF4 overvoltage     Weight fraction
                     Technology                       CF4/metric ton Al)/  coefficient  [(kg  C2F6/CF4 [(kg C2F6/
                                                        (AE-Mins/cell-    CF4/metric ton Al)/      kg CF4)]
                                                             day)]               (mV)]
----------------------------------------------------------------------------------------------------------------
Center Worked Prebake (CWPB)........................               0.143                1.16               0.121
Side Worked Prebake (SWPB)..........................               0.272                3.65               0.252
Vertical Stud S[oslash]derberg (VSS)................               0.092                  NA               0.053
Horizontal Stud S[oslash]derberg (HSS)..............               0.099                  NA               0.085
----------------------------------------------------------------------------------------------------------------

    24. Table F-2 is amended by revising the entry for ``CO2 
Emissions from Pitch Volatiles Combustion (VSS and HSS)'' to read as 
follows:

Table F-2 to Subpart F--Default Data Sources for Parameters Used for CO2
                                Emissions
------------------------------------------------------------------------
               Parameter                           Data source
------------------------------------------------------------------------
            CO2 Emissions from Prebake Cells (CWPB and SWPB)
------------------------------------------------------------------------

                              * * * * * * *
------------------------------------------------------------------------
      CO2 Emissions from Pitch Volatiles Combustion (CWPB and SWPB)
------------------------------------------------------------------------

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

Subpart G--[Amended]

    25. Section 98.72 is amended by revising paragraphs (a) and (b) to 
read as follows:

Sec.  98.72  GHGs to report.

* * * * *
    (a) CO2 process emissions from steam reforming of a 
hydrocarbon or the gasification of solid and liquid raw material, 
reported for each ammonia manufacturing process unit following the 
requirements of this subpart (CO2 process emissions reported 
under this subpart may include CO2 that is later consumed 
on-site for urea production, and therefore is not released to the 
ambient air from the ammonia manufacturing process unit).
    (b) CO2, CH4, and N2O emissions 
from each stationary fuel combustion unit. You must report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources), by following the requirements of subpart C, except 
that for ammonia manufacturing processes subpart C does not apply to 
any CO2 resulting from combustion of the waste recycle 
stream (commonly referred to as the purge gas stream).
* * * * *
    26. Section 98.73 is amended by:
    a. Revising paragraph (b) introductory text.
    b. Revising the definition of ``CO2,G'' in Equation G-1 
of paragraph (b)(1).
    c. Revising the definition of ``CO2,L'' in Equation G-2 
of paragraph (b)(2).
    d. Revising the definition of ``CO2,S'' in Equation G-3 
of paragraph (b)(3).
    e. Revising the definition of ``CO2'' in Equation G-5 of 
paragraph (b)(5).
    f. Removing paragraph (b)(6).

Sec.  98.73  Calculating GHG emissions.

* * * * *
    (b) Calculate and report under this subpart process CO2 
emissions using the procedures in paragraphs (b)(1) through (b)(5) of 
this section for gaseous feedstock, liquid feedstock, or solid 
feedstock, as applicable.
    (1) * * *

CO2,G,k = Annual CO2 emissions arising from 
gaseous feedstock consumption (metric tons).
* * * * *
    (2) * * *
CO2,L,k = Annual CO2 emissions arising from 
liquid feedstock consumption (metric tons).
* * * * *
    (3) * * *
CO2,S,k = Annual CO2 emissions arising from 
solid feedstock consumption (metric tons).
* * * * *
    (5) * * *
CO2 = Annual combined CO2 emissions from all 
ammonia processing units (metric tons) (CO2 process 
emissions reported under this subpart may include CO2 
that is later consumed on-site for urea production, and therefore is 
not released to the ambient air from the ammonia manufacturing 
process unit(s)).
* * * * *
    27. Section 98.74 is amended by revising paragraph (d) and by 
removing and reserving paragraph (f) to read as follows:

Sec.  98.74  Monitoring and QA/QC requirements.

* * * * *
    (d) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes and flow rates (except for gas 
billing meters) according to the monitoring and QA/QC requirements for 
the Tier 3 methodology in Sec.  98.34(b)(1). Perform oil tank drop 
measurements (if used to quantify feedstock volumes) according to Sec.  
98.34(b)(2).
* * * * *
    28. Section 98.75 is amended by revising the first sentence of 
paragraph (a); and by revising paragraph (b) to read as follows:

Sec.  98.75  Procedures for estimating missing data.

* * * * *
    (a) For missing data on monthly carbon contents of feedstock, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that carbon content in the month preceding and the 
month immediately following the missing data incident. * * *

[[Page 48802]]

    (b) For missing feedstock supply rates used to determine monthly 
feedstock consumption, you must determine the best available 
estimate(s) of the parameter(s), based on all available process data.
    29. Section 98.76 is amended by:
    a. Revising paragraphs (a) introductory text and (b)(6).
    b. Removing paragraphs (b)(12) through (b)(15).
    c. Redesignating paragraph (b)(16) as paragraph (b)(12).
    c. Adding a new paragraph (b)(13).
    d. Removing paragraphs (b)(17) and (c).

Sec.  98.76  Data reporting requirements.

* * * * *
    (a) 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 and the following information in this 
paragraph (a):
* * * * *
    (b) * * *
    (6) Sampling analysis results of carbon content of feedstock as 
determined for QA/QC of supplier data under Sec.  98.74(e).
* * * * *
    (12) Annual urea production (metric tons) and method used to 
determine urea production.
    (13) CO2 from the steam reforming of a hydrocarbon or 
the gasification of solid and liquid raw material at the ammonia 
manufacturing process unit used to produce urea and the method used to 
determine the CO2 consumed in urea production.

Subpart P--[Amended]

    30. Section 98.164 is amended by revising paragraph (b)(1) to read 
as follows:

Sec.  98.164  Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (1) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes (except for gas billing meters) 
according to the monitoring and QA/QC requirements for the Tier 3 
methodology in Sec.  98.34(b)(1). Perform oil tank drop measurements 
(if used to quantify liquid fuel or feedstock consumption) according to 
Sec.  98.34(b)(2). Calibrate all solids weighing equipment according to 
the procedures in Sec.  98.3(i).
* * * * *

Subpart V--[Amended]

    31. Section 98.226 is amended by removing paragraph (o).

Subpart X--[Amended]

    32. Section 98.240 is amended by revising paragraph (a); and by 
adding paragraph (g) to read as follows:

Sec.  98.240  Definition of the source category.

    (a) The petrochemical production source category consists of all 
processes that produce acrylonitrile, carbon black, ethylene, ethylene 
dichloride, ethylene oxide, or methanol, except as specified in 
paragraphs (b) through (g) of this section. The source category 
includes processes that produce the petrochemical as an intermediate in 
the onsite production of other chemicals as well as processes that 
produce the petrochemical as an end product for sale or shipment 
offsite.
* * * * *
    (g) A process that solely distills or recycles waste solvent that 
contains a petrochemical is not part of the petrochemical production 
source category.
    33. Section 98.242 is amended by revising paragraph (a)(1) and 
paragraph (b) introductory text to read as follows:

Sec.  98.242  GHGs to report.

* * * * *
    (a) * * *
    (1) If you comply with Sec.  98.243(b) or (d), report under this 
subpart the calculated CO2, CH4, and 
N2O emissions for each stationary combustion source and 
flare that burns any amount of petrochemical process off-gas. If you 
comply with Sec.  98.243(b), also report under this subpart the 
measured CO2 emissions from process vents routed to stacks 
that are not associated with stationary combustion units.
* * * * *
    (b) CO2, CH4, and N2O combustion 
emissions from stationary combustion units.
* * * * *
    34. Section 98.243 is amended by:
    a. Revising the second sentence of paragraph (b).
    b. Revising the definition of ``MVC'' in Equation X-1 in paragraph 
(c)(5)(i).
    c. Revising paragraph (d).

Sec.  98.243  Calculating GHG emissions.

* * * * *
    (b) * * * For each stack (except flare stacks) that includes 
emissions from combustion of petrochemical process off-gas, calculate 
CH4 and N2O emissions in accordance with subpart 
C of this part (use the Tier 3 methodology, emission factors for 
``Petroleum'' in Table C-2 of subpart C of this part, and either the 
default high heat value for fuel gas in Table C-1 of subpart C of this 
part or a calculated HHV, as allowed in Equation C-8 of subpart C of 
this part). * * *
    (c) * * *
    (5) * * *
    (i) * * *

MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68 
[deg]F and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole 
at 60 [deg]F and 14.7 pounds per square inch absolute).
* * * * *
    (d) Optional combustion methodology for ethylene production 
processes. For each ethylene production process, calculate GHG 
emissions from each combustion unit that burns fuel that contains any 
off-gas from the ethylene process as specified in paragraphs (d)(1) 
through (d)(5) of this section.
    (1) Except as specified in paragraphs (d)(2) and (d)(5) of this 
section, calculate CO2 emissions using the Tier 3 or Tier 4 
methodology in subpart C of this part.
    (2) You may use either Equation C-1 or Equation C-2a in subpart C 
of this part to calculate CO2 emissions from combustion of 
any ethylene process off-gas streams that meet either of the conditions 
in paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default 
values in the calculation, use the defaults for fuel gas in Table C-1 
of subpart C of this part). Follow the otherwise applicable procedures 
in subpart C to calculate emissions from combustion of all other fuels 
in the combustion unit.
    (i) The annual average flow rate of fuel gas (that contains 
ethylene process off-gas) in the fuel gas line to the combustion unit, 
prior to any split to individual burners or ports, does not exceed 345 
standard cubic feet per minute at 60[deg]F and 14.7 pounds per square 
inch absolute, and a flow meter is not installed at any point in the 
line supplying fuel gas or an upstream common pipe. Calculate the 
annual average flow rate using company records assuming total flow is 
evenly distributed over 525,600 minutes per year.
    (ii) The combustion unit has a maximum rated heat input capacity of 
less than 30 MMBtu/hr, and a flow meter is not installed at any point 
in the line supplying fuel gas (that contains ethylene process off-gas) 
or an upstream common pipe.
    (3) Except as specified in paragraph (d)(5) of this section, 
calculate CH4 and N2O emissions using the 
applicable procedures in Sec.  98.33(c) for the same tier methodology 
that you used for calculating CO2 emissions.
    (i) For all gaseous fuels that contain ethylene process off-gas, 
use the emission factors for ``Petroleum'' in Table C-2 of subpart C of 
this part

[[Page 48803]]

(General Stationary Fuel Combustion Sources).
    (ii) For Tier 3, use either the default high heat value for fuel 
gas in Table C-1 of subpart C of this part or a calculated HHV, as 
allowed in Equation C-8 of subpart C of this part.
    (4) You are not required to use the same Tier for each stationary 
combustion unit that burns ethylene process off-gas.
    (5) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec.  
98.253(b)(1) through (b)(3).
    35. Section 98.244 is amended by revising paragraphs (b)(1) through 
(b)(3) and (b)(4) introductory text; and by adding paragraphs 
(b)(4)(xi) through (b)(4)(xiii) to read as follows:

Sec.  98.244  Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (1) Operate, maintain, and calibrate belt scales or other weighing 
devices as described in Specifications, Tolerances, and Other Technical 
Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009) 
(incorporated by reference, see Sec.  98.7), or follow procedures 
specified by the measurement device manufacturer. You must recalibrate 
each weighing device according to one of the following frequencies. You 
may recalibrate either biennially (i.e., once every two years) or at 
the minimum frequency specified by the manufacturer.
    (2) Operate and maintain all flow meters used for gas and liquid 
feedstocks and products according to the manufacturer's recommended 
procedures. You must calibrate each of these flow meters according to 
one of the following. You may use either an industry consensus standard 
method or methods specified by the flow meter manufacturer. Each flow 
meter must meet the applicable accuracy specification in Sec.  98.3(i), 
except as otherwise specified in Sec.  98.3(i)(4) through (i)(6). You 
must recalibrate each flow meter according to one of the following 
frequencies. You may recalibrate either biennially, at the minimum 
frequency specified by the manufacturer, or at the interval specified 
by the industry consensus standard practice used.
    (3) You must perform tank level measurements (if used to determine 
feedstock or product flows) according to one of the following methods. 
You may use any standard method published by a consensus-based 
standards organization (e.g., ASTM, API, etc.) or you may use industry 
standard practice.
    (4) Use any applicable methods specified in paragraphs (b)(4)(i) 
through (b)(4)(xiii) of this section to determine the carbon content or 
composition of feedstocks and products and the average molecular weight 
of gaseous feedstocks and products. Calibrate instruments in accordance 
with paragraphs (b)(4)(i) through (b)(4)(xiii), as applicable. For coal 
used as a feedstock, the samples for carbon content determinations 
shall be taken at a location that is representative of the coal 
feedstock used during the corresponding monthly period. For carbon 
black products, samples shall be taken of each grade or type of product 
produced during the monthly period. Samples of coal feedstock or carbon 
black product for carbon content determinations may be either grab 
samples collected and analyzed monthly or a composite of samples 
collected more frequently and analyzed monthly. Analyses conducted in 
accordance with methods specified in paragraphs (b)(4)(i) through 
(b)(4)(xiii) of this section may be performed by the owner or operator, 
by an independent laboratory, or by the supplier of a feedstock.
* * * * *
    (xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, 
(incorporated by reference, see Sec.  98.7), effective as of January 1, 
2010.
    (xii) An industry standard practice for carbon black feedstock oils 
and carbon black products, effective as of January 1, 2010.
    (xiii) Modifications of existing analytical methods or other 
analytical methods that are applicable to your process provided that 
the methods listed in Sec.  98.244(b)(4)(i) through Sec.  
98.244(b)(4)(xii) are not appropriate because the relevant compounds 
cannot be detected, the quality control requirements are not 
technically feasible, or use of the method would be unsafe, effective 
as of January 1, 2010.
    36. Section 98.246 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(4).
    b. Removing and reserving paragraph (a)(7).
    c. Revising paragraph (a)(10).
    d. Adding paragraph (a)(11).
    e. Revising paragraphs (b) introductory text, and (b)(1) through 
(b)(5).
    f. Revising paragraph (c).

Sec.  98.246  Data reporting requirements.

* * * * *
    (a) If you use the mass balance methodology in Sec.  98.243(c), you 
must report the information specified in paragraphs (a)(1) through 
(a)(11) of this section for each type of petrochemical produced, 
reported by process unit.
* * * * *
    (4) Each of the monthly volume, mass, and carbon content values 
used in Equations X-1 through X-3 of this subpart (i.e., the directly 
measured values, substitute values, or the calculated values based on 
other measured data such as tank levels or gas composition) and the 
molecular weights for gaseous feedstocks and products used in Equation 
X-1 of this subpart, and the temperture (in [deg]F) at which the 
gaseous feedstock and product volumes used in Equation X-1 of this 
subpart were determined. Indicate whether you used the alternative to 
sampling and analysis specified in Sec.  98.243(c)(4).
* * * * *
    (10) You may elect to report the flow and carbon content of 
wastewater, and you may elect to report the annual mass of carbon 
released in fugitive emissions and in process vents that are not 
controlled with a combustion device. These values may be estimated 
based on engineering analyses. These values are not to be used in the 
mass balance calculation.
    (11) If you determine carbon content or composition of a feedstock 
or product using a method under Sec.  98.244(b)(4)(xiii), report the 
information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of 
this section. Include the information in paragraph (a)(11)(i) of this 
section in each annual report. Include the information in paragraphs 
(a)(11)(ii) and (a)(11)(iii) of this section only in the first 
applicable annual report, and provide any changes to this information 
in subsequent annual reports.
    (i) Name or title of the analytical method.
    (ii) A copy of the method. If the method is a modification of a 
method listed in Sec.  98.244(b)(4)(i) through (xii), you may provide a 
copy of only the sections that differ from the listed method.
    (iii) An explanation of why an alternative to the methods listed in 
Sec.  98.244(b)(4)(i) through (xii) is needed.
    (b) If you measure emissions in accordance with Sec.  98.243(b), 
then you must report the information listed in paragraphs (b)(1) 
through (b)(8) of this section.
    (1) The petrochemical process unit ID or other appropriate 
descriptor, and the type of petrochemical produced.
    (2) For CEMS used on stacks for stationary combustion units, report 
the relevant information required under Sec.  98.36 for the Tier 4 
calculation

[[Page 48804]]

methodology. Section 98.36(b)(9)(iii) does not apply for the purposes 
of this subpart.
    (3) For CEMS used on stacks that are not used for stationary 
combustion units, report the information required under Sec.  
98.36(e)(2)(vi).
    (4) The CO2 emissions from each stack and the combined 
CO2 emissions from all stacks (except flare stacks) that 
handle process vent emissions and emissions from stationary combustion 
units that burn process off-gas for the petrochemical process unit. For 
each stationary combustion unit (or group of combustion units monitored 
with a single CO2 CEMS) that burns petrochemical process 
off-gas, provide an estimate based on engineering judgment of the 
fraction of the total emissions that is attributable to combustion of 
off-gas from the petrochemical process unit.
    (5) For stationary combustion units that burn process off-gas from 
the petrochemical process unit, report the information related to 
CH4 and N2O emissions as specified in paragraphs 
(b)(5)(i) through (b)(5)(iv) of this section.
    (i) The CH4 and N2O emissions from each stack 
that is monitored with a CO2 CEMS, expressed in metric tons 
of each gas and in metric tons of CO2e. For each stack 
provide an estimate based on engineering judgment of the fraction of 
the total emissions that is attributable to combustion of off-gas from 
the petrochemical process unit.
    (ii) The combined CH4 and N2O emissions from 
all stationary combustion units, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (iii) The quantity of each type of fuel used in Equation C-8 in 
Sec.  98.33(c) for each stationary combustion unit or group of units 
(as applicable) during the reporting year, expressed in short tons for 
solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
    (iv) The HHV (either default or annual average from measured data) 
used in Equation C-8 in Sec.  98.33(c) for each stationary combustion 
unit or group of combustion units (as applicable).
* * * * *
    (c) If you comply with the combustion methodology specified in 
Sec.  98.243(d), you must report under this subpart the information 
listed in paragraphs (c)(1) through (c)(5) of this section.
    (1) The ethylene process unit ID or other appropriate descriptor.
    (2) For each stationary combustion unit that burns ethylene process 
off-gas (or group of stationary sources with a common pipe), except 
flares, the relevant information listed in Sec.  98.36 for the 
applicable Tier methodology. For each stationary combustion unit or 
group of units (as applicable) that burns ethylene process off-gas, 
provide an estimate based on engineering judgment of the fraction of 
the total emissions that is attributable to combustion of off-gas from 
the ethylene process unit.
    (3) Information listed in Sec.  98.256(e) of subpart Y of this part 
for each flare that burns ethylene process off-gas.
    (4) Name and annual quantity of each feedstock.
    (5) Annual quantity of ethylene produced from each process unit 
(metric tons).
    37. Section 98.247 is amended by:
    a. Revising paragraph (a).
    b. Adding paragraph (b)(4).
    c. Revising paragraph (c).

Sec.  98.247  Records that must be retained.

* * * * *
    (a) If you comply with the CEMS measurement methodology in Sec.  
98.243(b), then you must retain under this subpart the records required 
for the Tier 4 Calculation Methodology in Sec.  98.37, records of the 
procedures used to develop estimates of the fraction of total emissions 
attributable to combustion of petrochemical process off-gas as required 
in Sec.  98.246(b), and records of any annual average HHV calculations.
    (b) * * *
    (4) The dates and results (e.g., percent calibration error) of the 
calibrations of each measurement device.
    (c) If you comply with the combustion methodology in Sec.  
98.243(d), then you must retain under this subpart the records required 
for the applicable Tier Calculation Methodologies in Sec.  98.37. If 
you comply with Sec.  98.243(d)(2), you must also keep records of the 
annual average flow calculations.

Subpart Y--[Amended]

    38. Section 98.252 is amended by revising paragraph (a) and the 
first sentence of paragraph (i) to read as follows:

Sec.  98.252  GHGs to report.

* * * * *
    (a) CO2, CH4, and N2O combustion 
emissions from stationary combustion units and from each flare. 
Calculate and report the emissions from stationary combustion units 
under subpart C of this part (General Stationary Fuel Combustion 
Sources) by following the requirements of subpart C, except for 
emissions from combustion of fuel gas. For CO2 emissions 
from combustion of fuel gas, use either Equation C-5 in subpart C of 
this part or the Tier 4 methodology in subpart C of this part, unless 
either of the conditions in paragraphs (a)(1) or (2) of this section 
are met, in which case use either Equations C-1 or C-2a in subpart C of 
this part. For CH4 and N2O emissions from 
combustion of fuel gas, use the applicable procedures in Sec.  98.33(c) 
for the same tier methodology that was used for calculating 
CO2 emissions. (Use the default CH4 and 
N2O emission factors for ``Petroleum (All fuel types in 
Table C-1)'' in Table C-2 of this part. For Tier 3, use either the 
default high heat value for fuel gas in Table C-1 of subpart C of this 
part or a calculated HHV, as allowed in Equation C-8 of subpart C of 
this part.) You may aggregate units, monitor common stacks, or monitor 
common (fuel) pipes as provided in Sec.  98.36(c) when calculating and 
reporting emissions from stationary combustion units. Calculate and 
report the emissions from flares under this subpart.
    (1) The annual average fuel gas flow rate in the fuel gas line to 
the combustion unit, prior to any split to individual burners or ports, 
does not exceed 345 standard cubic feet per minute at 60[deg]F and 14.7 
pounds per square inch absolute and either of the conditions in 
paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual 
average flow rate using company records assuming total flow is evenly 
distributed over 525,600 minutes per year.
    (i) A flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe.
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
    (2) The combustion unit has a maximum rated heat input capacity of 
less than 30 MMBtu/hr and either of the following conditions exist:
    (i) A flow meter is not installed at any point in the line 
supplying fuel gas or an upsteam common pipe; or
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
* * * * *
    (i) CO2 emissions from non-merchant hydrogen production 
process units (not including hydrogen produced from catalytic reforming 
units) under this subpart. * * *
    39. Section 98.253 is amended by:
    a. Revising paragraph (b)(1)(ii)(A).
    b. Revising the definition of ``MVC'' in Equation Y-3 in paragraph 
(b)(1)(iii)(C).

[[Page 48805]]

    c. Revising paragraph (c)(1)(ii).
    d. Revising the definition of ``MVC'' in Equation Y-6 in paragraph 
(c)(2)(i).
    e. Revising paragraph (c)(2)(ii).
    f. Revising the definition of ``CBQ'' and ``n'' in 
Equation Y-11 in paragraph (e)(3).
    g. Revising the first sentence of paragraph (f) introductory text 
and the last sentence of paragraph (f)(1).
    h. Revising the definition of ``MVC'' in Equation Y-12 in paragraph 
(f)(4).
    i. Revising the definition of ``Mdust'' in Equation Y-13 
in paragraph (g)(2).
    j. Revising paragraphs (h) introductory text and (h)(2).
    k. In paragraph (i)(1), revising the first two sentences and the 
definition of ``MVC'' in Equation Y-18.
    l. In paragraph (j), revising both sentences; and revising the 
definitions of ``(VR)p,'' ``(MFx)p,'' 
and ``MVC'' in Equation Y-19.
    m. In paragraph (k), revising the first sentence and the definition 
of ``MVC'' in Equation Y-20.
    n. Revising paragraph (m) introductory text.
    o. Revising the definitions of ``MFCH4'' and ``MVC'' in 
Equation Y-23 in paragraph (m)(2).
    p. Revising paragraph (n).

Sec.  98.253  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (A) If you monitor gas composition, calculate the CO2 
emissions from the flare using either Equation Y-1a or Equation Y-1b of 
this section. If daily or more frequent measurement data are available, 
you must use daily values when using Equation Y-1a or Equation Y-1b of 
this section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TP11AU10.007

Where:

CO2 = Annual CO2 emissions for a specific fuel 
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52 
(for weekly measurements); the maximum value for n is 366 (for daily 
measurements during a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Flare)p = Volume of flare gas combusted during 
measurement period (standard cubic feet per period, scf/period). If 
a mass flow meter is used, measure flare gas flow rate in kg/period 
and replace the term ``(MW)p/MVC'' with ``1''.
(MW)p = Average molecular weight of the flare gas 
combusted during measurement period (kg/kg-mole). If measurements 
are taken more frequently than daily, use the arithmetic average of 
measurement values within the day to calculate a daily average.
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 
[ordm]F and 14.7 pounds per square inch absolute (psia) or 836.6 
scf/kg-mole at 60 [ordm]F and 14.7 psia).
(CC)p = Average carbon content of the flare gas combusted 
during measurement period (kg C per kg flare gas). If measurements 
are taken more frequently than daily, use the arithmetic average of 
measurement values within the day to calculate a daily average.
[GRAPHIC] [TIFF OMITTED] TP11AU10.008

Where:

CO2 = Annual CO2 emissions for a specific fuel 
type (metric tons/year).
n = Number of measurement periods. The minimum value for n is 52 
(for weekly measurements); the maximum value for n is 366 (for daily 
measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during 
measurement period (standard cubic feet per period, scf/period). If 
a mass flow meter is used, you must determine the average molecular 
weight of the flare gas during the measurement period and convert 
the mass flow to a volumetric flow.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68[ordm]F 
and 14.7 psia or 836.6 scf/kg-mole at 60[ordm]F and 14.7 psia).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
(%CO2)p = Mole percent CO2 
concentration in the flare gas stream during the measurement period 
(mole percent = percent by volume).
y = Number of carbon-containing compounds other than CO2 
in the flare gas stream.
x = Index for carbon-containing compounds other than CO2.
0.98 = Assumed combustion efficiency of a flare (mole CO2 
per mole carbon).
(%Cx)p = Mole percent concentration of 
compound ``x'' in the flare gas stream during the measurement period 
(mole percent = percent by volume)
CMNx = Carbon mole number of compound ``x'' in the flare 
gas stream (mole carbon atoms per mole compound). E.g., CMN for 
ethane (C2H6) is 2; CMN for propane 
(C3H8) is 3.
* * * * *
    (iii) * * *
    (C)
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 
[ordm]F and 14.7 psia or 836.6 scf/kg-mole at 60 [ordm]F and 14.7 
psia).
* * * * *
    (c) * * *
    (1) * * *
    (ii) For catalytic cracking units whose process emissions are 
discharged through a combined stack with other CO2 emissions 
(e.g., co-mingled with emissions from a CO boiler) you must also 
calculate the other CO2 emissions using the applicable 
methods for the applicable subpart (e.g., subpart C of this part in the 
case of a CO boiler). Calculate the process emissions from the 
catalytic cracking unit or fluid coking unit as the difference in the 
CO2 CEMS emissions and the calculated emissions associated 
with the additional units discharging through the combined stack.
    (2) * * *
    (i)
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 
[ordm]F and 14.7 psia or 836.6 scf/kg-mole at 60 [ordm]F and 14.7 
psia).
* * * * *
    (ii) Either continuously monitor the volumetric flow rate of 
exhaust gas from

[[Page 48806]]

the fluid catalytic cracking unit regenerator or fluid coking unit 
burner prior to the combustion of other fossil fuels or calculate the 
volumetric flow rate of this exhaust gas stream using either Equation 
Y-7a or Equation Y-7b of this section.
[GRAPHIC] [TIFF OMITTED] TP11AU10.009

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner 
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
cracking unit regenerator or fluid coking unit burner, as determined 
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
fluid catalytic cracking unit regenerator or fluid coking unit 
burner as determined from control room instrumentation (dscfh).
%O2 = Hourly average percent oxygen concentration in 
exhaust gas stream from the fluid catalytic cracking unit 
regenerator or fluid coking unit burner (percent by volume--dry 
basis).
%Ooxy = O2 concentration in oxygen enriched 
gas stream inlet to the fluid catalytic cracking unit regenerator or 
fluid coking unit burner based on oxygen purity specifications of 
the oxygen supply used for enrichment (percent by volume--dry 
basis).
%CO2 = Hourly average percent CO2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas 
stream from the fluid catalytic cracking unit regenerator or fluid 
coking unit burner (percent by volume--dry basis). When no auxiliary 
fuel is burned and a continuous CO monitor is not required under 40 
CFR part 63 subpart UUU, assume %CO to be zero.
[GRAPHIC] [TIFF OMITTED] TP11AU10.010

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner 
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
cracking unit regenerator or fluid coking unit burner, as determined 
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
fluid catalytic cracking unit regenerator or fluid coking unit 
burner as determined from control room instrumentation (dscfh).
%N2,oxy = N2 concentration in oxygen enriched 
gas stream inlet to the fluid catalytic cracking unit regenerator or 
fluid coking unit burner based on measured value or maximum 
N2 impurity specifications of the oxygen supply used for 
enrichment (percent by volume--dry basis).
%N2,exhaust = Hourly average percent N2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
* * * * *
    (e) * * *
    (3) * * *

CBQ = Coke burn-off quantity per regeneration cycle or 
measurement period from engineering estimates (kg coke/cycle or kg 
coke/measurement period).
n = Number of regeneration cycles or measurement periods in the 
calendar year.
* * * * *
    (f) For on-site sulfur recovery plants and for sour gas sent off 
site for sulfur recovery, calculate and report CO2 process 
emissions from sulfur recovery plants according to the requirements in 
paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus 
sulfur recovery plants, according to the requirements in paragraph (j) 
of this section regardless of the concentration of CO2 in 
the vented gas stream. * * *
    (1) * * * Other sulfur recovery plants must either install a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C, or 
follow the requirements of paragraphs (f)(2) through (f)(5) of this 
section, or (for non-Claus sulfur recovery plants only) follow the 
requirements in paragraph (j) of this section to determine 
CO2 emissions for the sulfur recovery plant.
* * * * *
    (4) * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (g) * * *
    (2) * * *
Mdust = Annual mass of petroleum coke dust removed from 
the process through the dust collection system of the coke calcining 
unit from facility records (metric ton petroleum coke dust/year). 
For coke calcining units that recycle the collected dust, the mass 
of coke dust removed from the process is the mass of coke dust 
collected less the mass of coke dust recycled to the process.
* * * * *
    (h) For asphalt blowing operations, calculate CO2 and 
CH4 emissions according to the requirements in paragraph (j) 
of this section regardless of the CO2 and CH4 
concentrations or according to the applicable provisions in paragraphs 
(h)(1) and (h)(2) of this section.
* * * * *
    (2) For asphalt blowing operations controlled by thermal oxidizer 
or flare, calculate CO2 using either Equation Y-16a or 
Equation Y-16b of this section and calculate CH4 emissions 
using Equation Y-17 of this section, provided these emissions are not 
already included in the flare emissions calculated in paragraph (b) of 
this section or in the stationary combustion unit emissions required 
under subpart C of this part (General Stationary Fuel Combustion 
Sources).

[[Page 48807]]

[GRAPHIC] [TIFF OMITTED] TP11AU10.011

Where:

CO2 = Annual CO2 emissions from controlled 
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from 
facility-specific test data (metric tons C/MMbbl asphalt blown); 
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TP11AU10.012

Where:

CO2 = Annual CO2 emissions from controlled 
asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (MMbbl/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
EFAB,CO2 = Emission factor for CO2 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CO2/MMbbl asphalt blown); default = 1,100.
CEFAB = Carbon emission factor from asphalt blowing from 
facility-specific test data (metric tons C/MMbbl asphalt blown); 
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TP11AU10.013

Where:

CH4 = Annual methane emissions from controlled asphalt 
blowing (metric tons CH4/year).
0.02 = Fraction of methane uncombusted in thermal oxidizer or flare 
based on assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million barrels per 
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CH4/MMbbl asphalt blown); default = 580.
    (i) * * *
    (1) Use the process vent method in paragraph (j) of this section to 
calculate the CH4 emissions from the depressurization of the 
coke drum or vessel regardless of the CH4 concentration and 
also calculate the CH4 emissions from the subsequent opening 
of the vessel for coke cutting operations using Equation Y-18 of this 
section. If you have coke drums or vessels of different dimensions, use 
the process vent method in paragraph (j) of this section and Equation 
Y-18 for each set of coke drums or vessels of the same size and sum the 
resultant emissions across each set of coke drums or vessels to 
calculate the CH4 emissions for all delayed coking units.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (j) For each process vent not covered in paragraphs (a) through (i) 
of this section that can be reasonably expected to contain greater than 
2 percent by volume CO2 or greater than 0.5 percent by 
volume of CH4 or greater than 0.01 percent by volume (100 
parts per million) of N2O, calculate GHG emissions using the 
Equation Y-19 of this section. You must use Equation Y-19 of this 
section to calculate CH4 emissions for catalytic reforming 
unit depressurization and purge vents when methane is used as the purge 
gas or if you elected this method as an alternative to the methods in 
paragraphs (f), (h), or (k) of this section.
* * * * *
(VR)p = Average volumetric flow rate of process gas 
during the event (scf per hour) from measurement data, process 
knowledge, or engineering estimates.
(MFx)p = Mole fraction of GHG x in process 
vent during the event (kg-mol of GHG x/kg-mol vent gas) from 
measurement data, process knowledge, or engineering estimates.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (k) For uncontrolled blowdown systems, you must calculate CH4 
emissions either using the methods for process vents in paragraph (j) 
of this section regardless of the CH4 concentration or using 
Equation Y20 of this section. * * *
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (m) For storage tanks, except as provided in paragraph (m)(4) of 
this section, calculate CH4 emissions using the applicable 
methods in paragraphs (m)(1) through (m)(3) of this section.
    (2) * * *

MFCH4 = Average mole fraction of CH4 in vent 
gas from the unstabilized crude oil storage tanks from facility 
measurements (kg-mole CH4/kg-mole gas); use 0.27 as a 
default if measurement data are not available.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (n) For crude oil, intermediate, or product loading operations for 
which the vapor-phase concentration of methane is 0.5 volume percent or 
more, calculate CH4 emissions from loading operations using 
vapor-phase methane composition data (from measurement data or process 
knowledge) and the emission estimation procedures provided in Section 
5.2 of the AP-42: ``Compilation of Air Pollutant Emission Factors, 
Volume 1: Stationary Point and Area Sources.'' For loading operations 
in which the vapor-phase concentration of methane is less than 0.5 
volume percent, you may assume zero methane emissions.
    40. Section 98.254 is amended by:
    a. Revising paragraph (a).

[[Page 48808]]

    b. Revising paragraph (b).
    c. Revising paragraph (c).
    d. Revising paragraphs (d) introductory text and (d)(6).
    e. Adding a new paragraph (d)(6).
    f. Revising paragraph (e) introductory text.
    g. Revising paragraph (f) introductory text and (f)(1).
    h. Removing and reserving paragraph (f)(2).
    i. Removing paragraph (f)(4).
    j. Revising paragraph (g).
    k. Revising the second sentence of paragraph (h).
    l. Removing paragraph (l).

Sec.  98.254  Monitoring and QA/QC requirements.

    (a) Fuel flow meters, gas composition monitors, and heating value 
monitors that are associated with sources that use a CEMS to measure 
CO2 emissions according to subpart C of this part or that 
are associated with stationary combustion sources must meet the 
applicable monitoring and QA/QC requirements in Sec.  98.34.
    (b) All gas flow meters, gas composition monitors, and heating 
value monitors that are used to provide data for the GHG emissions 
calculations in this subpart for sources other than those subject to 
the requirements in paragraph (a) of this section shall be calibrated 
according to the procedures in the applicable methods specified in 
paragraphs (c) through (g) of this section or the procedures specified 
by the manufacturer. In the case of gas flow meters, all gas flow 
meters must meet the calibration accuracy requirements in Sec.  
98.3(i). You must recalibrate each gas flow meter according to one of 
the following frequencies. You may recalibrate either biennially (every 
two years), at the minimum frequency specified by the manufacturer, or 
at the interval specified by the industry consensus standard practice 
used. You must recalibrate each gas composition monitor and heating 
value monitor according to one of the following frequencies. You may 
recalibrate either annually, at the minimum frequency specified by the 
manufacturer, or at the interval specified by the industry consensus 
standard practice used.
    (c) For flare or sour gas flow meters, operate, calibrate, and 
maintain the flow meter according to one of the following. You may use 
a method published by a consensus-based standards organization or the 
procedures specified by the flow meter manufacturer. Consensus-based 
standards include, but are not limited to, the following: ASTM 
International, the American Society of Mechanical Engineers (ASME), and 
the American Gas Association (AGA).
    (d) Except as provided in paragraph (g) of this section, determine 
gas composition and, if required, average molecular weight of the gas 
using any of the following methods. Alternatively, the results of 
chromatographic analysis of the fuel may be used, provided that the gas 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions; and the methods used for operation, 
maintenance, and calibration of the gas chromatograph are documented in 
the written Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *
    (6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure (incorporated by 
reference, see Sec.  98.7).
    (e) Determine flare gas higher heating value using any of the 
following methods. Alternatively, the results of chromatographic 
analysis of the fuel may be used, provided that the gas chromatograph 
is operated, maintained, and calibrated according to the manufacturer's 
instructions; and the methods used for operation, maintenance, and 
calibration of the gas chromatograph are documented in the written 
Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *
    (f) For gas flow meters used to comply with the requirements in 
Sec.  98.253(c)(2)(ii) or Sec.  98.253(j), install, operate, calibrate, 
and maintain each gas flow meter according to the requirements in 40 
CFR 63.1572(c) and the following requirements.
    (1) Locate the flow monitor at a site that provides representative 
flow rates. Avoid locations where there is swirling flow or abnormal 
velocity distributions due to upstream and downstream disturbances.
* * * * *
    (g) For exhaust gas CO2/CO/O2 composition 
monitors used to comply with the requirements in Sec.  98.253(c)(2), 
install, operate, calibrate, and maintain exhaust gas composition 
monitors according to the the requirements in 40 CFR 60.105a(b)(2) or 
40 CFR 63.1572(c) or according to the manufacturer's specifications and 
requirements.
    (h) * * * Calibrate the measurement device according to the 
procedures specified by NIST handbook 44 or the procedures specified by 
the manufacturer. * * *
* * * * *
    41. Section 98.256 is amended by:
    a. Revising paragraph (e)(6).
    b. Redesignating paragraphs (e)(7) through (e)(9) as (e)(8) through 
(e)(10), respectively.
    c. Adding a new paragraph (e)(7).
    d. Revising newly designated paragraphs (e)(8) and (e)(9).
    e. Revising paragraphs (f)(6) through (f)(8).
    f. Redesignating paragraphs (f)(9) through (f)(12) as (f)(10) 
through (f)(13), respectively.
    g. Adding a new paragraph (f)(9).
    h. Revising newly designated paragraphs (f)(11) through (f)(13).
    i. Revising paragraphs (g)(5), (h)(2), (h)(4), and (h)(6).
    j. Adding paragraph (h)(7).
    k. Revising paragraphs (i)(5), (i)(6), (i)(8), and (j)(2).
    l. Redesignating paragraph (j)(8) as (j)(9).
    m. Adding a new paragraph (j)(8).
    n. Revising paragraphs (k)(1), (k)(3), (l) introductory text, 
(l)(5), and (m).
    o. Revising paragraph (o).

Sec.  98.256  Data reporting requirements.

* * * * *
    (e) * * *
    (6) If you use Equation Y-1a of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year) and the annual average molecular 
weight (in kg/kg-mole), the molar volume conversion factor (in scf/kg-
mole), and annual average carbon content of the flare gas (in kg carbon 
per kg flare gas).
    (7) If you use Equation Y-1b of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year), the molar volume conversion 
factor (in scf/kg-mole), the annual average CO2 
concentration (volume or mole percent), the number of carbon containing 
compounds other than CO2 in the flare gas stream, and for 
each of the carbon containing compounds other than CO2 in 
the flare gas stream:
    (i) The annual average concentration of the compound (volume or 
mole percent).
    (ii) The carbon mole number of the compound (moles carbon per mole 
compound).
    (8) If you use Equation Y-2 of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in million (MM) scf/year) and the annual 
average higher heating value of the flare gas (in MMBtu per MMscf).
    (9) If you use Equation Y-3 of this subpart, the annual volume of 
flare gas combusted (in MMscf/year) during

[[Page 48809]]

normal operations, the annual average higher heating value of the flare 
gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/
day, the volume of gas flared (in scf/event), the average molecular 
weight (in kg/kg-mole), the molar volume conversion factor (in scf/kg-
mole), and carbon content of the flare gas (in kg carbon per kg flare) 
for each SSM event over 500,000 scf/day.
* * * * *
    (f) * * *
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS (unadjusted to remove 
CO2 combustion emissions associated with additional units, 
if present) and the process CO2 emissions as calculated 
according to Sec.  98.253(c)(1)(ii). Report the CO2 annual 
emissions associated with sources other than those from the coke burn-
off in the applicable subpart (e.g., subpart C of this part in the case 
of a CO boiler).
    (7) If you use Equation Y-6 of this subpart, the annual average 
exhaust gas flow rate, %CO2, %CO, and the molar volume 
conversion factor (in scf/kg-mole).
    (8) If you use Equation Y-7a of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %O2, 
%Ooxy, %CO2, and %CO.
    (9) If you use Equation Y-7b of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %N2,oxy, and 
%N2,exhaust.
* * * * *
    (11) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for CH4 
emissions. If you use a unit-specific emission factor for 
CH4, report the unit-specific emission factor for 
CH4, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor.
    (12) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the unit-specific emission factor for 
N2O, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor.
    (13) If you use Equation Y-11 of this subpart, the number of 
regeneration cycles or measurement periods during the reporting year, 
the average coke burn-off quantity per cycle or measurement period, and 
the average carbon content of the coke.
    (g) * * *
    (5) If the GHG emissions for the low heat value gas are calculated 
at the flexicoking unit, also report the calculated annual 
CO2, CH4, and N2O emissions for each 
unit, expressed in metric tons of each pollutant emitted, and the 
applicable equation input parameters specified in paragraphs (f)(7) 
through (f)(13) of this section.
    (h) * * *
    (2) Maximum rated throughput of each independent sulfur recovery 
plant, in metric tons sulfur produced/stream day, a description of the 
type of sulfur recovery plant, and an indication of the method used to 
calculate CO2 annual emissions for the sulfur recovery plant 
(e.g., CO2 CEMS, Equation Y-12, or process vent method in 
Sec.  98.253(j)).
* * * * *
    (4) If you use Equation Y-12 of this subpart, the annual volumetric 
flow to the sulfur recovery plant (in scf/year), the molar volume 
conversion factor (in scf/kg-mole), and the annual average mole 
fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
* * * * *
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS and the annual process 
CO2 emissions calculated according to Sec.  98.253(f)(1). * 
* *
    (7) If you use the process vent method in Sec.  98.253(j) for a 
non-Claus sulfur recovery plant, the relevant information required 
under paragraph (l)(5) of this section.
    (i) * * *
    (5) If you use Equation Y-13 of this subpart, annual mass and 
carbon content of green coke fed to the unit, the annual mass and 
carbon content of marketable coke produced, the annual mass of coke 
dust removed from the process through dust collection systems, and an 
indication of whether coke dust is recycled to the unit (e.g., all dust 
is recycled, a portion of the dust is recycled, or none of the dust is 
recycled).
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS and the annual process 
CO2 emissions calculated according to Sec.  98.253(g)(1).
* * * * *
    (8) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the unit-specific emission factor for 
N2O, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor. (j) * * *
    (2) The quantity of asphalt blown (in Million bbl) at the unit in 
the reporting year.
* * * * *
    (8) If you use Equation Y-16b of this subpart, the CO2 
emission factor used and the basis for its value and the carbon 
emission factor used and the basis for its value.
* * * * *
    (k) * * *
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all delayed coking units at the facility.
* * * * *
    (3) The total number of delayed coking units at the facility, the 
total number of delayed coking drums at the facility, and for each coke 
drum or vessel: The dimensions, the typical gauge pressure of the 
coking drum when first vented to the atmosphere, typical void fraction, 
the typical drum outage (i.e., the unfilled distance from the top of 
the drum, in feet), the molar volume conversion factor (in scf/kg-
mole), and annual number of coke-cutting cycles.
* * * * *
    (l) For each process vent subject to Sec.  98.253(j), the owner or 
operator shall report:
* * * * *
    (5) The annual volumetric flow discharged to the atmosphere (in 
scf), and an indication of the measurement or estimation method, annual 
average mole fraction of each GHG above the concentration threshold or 
otherwise required to be reported and an indication of the measurement 
or estimation method, the molar volume conversion factor (in scf/kg-
mole), and for intermittent vents, the number of venting events and the 
cumulative venting time.
    (m) For uncontrolled blowdown systems, the owner or operator shall 
report:
    (1) An indication of whether the uncontrolled blowdown emission are 
reported under Sec.  98.253(k) or Sec.  98.253(j) or a statement that 
the facility does not have any uncontrolled blowdown systems.
    (2) The cumulative annual CH4 emissions (in metric tons 
of CH4) for uncontrolled blowdown systems.

[[Page 48810]]

    (3) For uncontrolled blowdown systems reporting under Sec.  
98.253(k), the total quantity (in Million bbl) of crude oil plus the 
quantity of intermediate products received from off-site that are 
processed at the facility in the reporting year, the methane emission 
factor used for uncontrolled blowdown systems, the basis for the value, 
and the molar volume conversion factor (in scf/kg-mole).
    (4) For uncontrolled blowdown systems reporting under Sec.  
98.253(j), the relevant information required under paragraph (l)(5) of 
this section.
* * * * *
    (o) * * *
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all storage tanks, except for those used to 
process unstabilized crude oil.
    (2) For storage tanks other than those processing unstabilized 
crude oil:
    (i) The method used to calculate the reported storage tank 
emissions for storage tanks other than those processing unstabilized 
crude (Section 7.1 of the AP-42: ``Compilation of Air Pollutant 
Emission Factors, Volume 1: Stationary Point and Area Sources'', 
including TANKS Model (Version 4.09D) or similar programs, or Equation 
Y-22 of this section, other).
    (ii) The total quantity (in MMbbl) of crude oil plus the quantity 
of intermediate products received from off-site that are processed at 
the facility in the reporting year.
    (3) The cumulative CH4 emissions (in metric tons of 
CH4) for storage tanks used to process unstabilized crude 
oil or a statement that the facility did not receive any unstabilized 
crude oil during the reporting year.
    (4) For storage tanks that process unstabilized crude oil:
    (i) The method used to calculate the reported unstabilized crude 
oil storage tank emissions .
    (ii) The quantity of unstabilized crude oil received during the 
calendar year (in MMbbl).
    (iii) The average pressure differential (in psi).
    (iv) The molar volume conversion factor (in scf/kg-mole).
    (v) The average mole fraction of CH4 in vent gas from 
unstabilized crude oil storage tanks and the basis for the mole 
fraction.
    (vi) If you did not use Equation Y-23, the tank-specific methane 
composition data and the gas generation rate data used to estimate the 
cumulative CH4 emissions for storage tanks used to process 
unstabilized crude oil.
* * * * *
    42. Section 98.257 is revised to read as follows:

Sec.  98.257  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records of all parameters monitored under Sec.  98.255. If 
you comply with the combustion methodology in Sec.  98.252(a), then you 
must retain under this subpart the records required for the Tier 3 and/
or Tier 4 Calculation Methodologies in Sec.  98.37 and you must keep 
records of the annual average flow calculations.

Subpart AA--[Amended]

    43. Section 98.273 is amended by:
    a. Revising paragraphs (a)(1) and (a)(2).
    b. Revising paragraphs (b)(1) and (b)(2).
    c. Revising paragraphs (c)(1) and (c)(2).

Sec.  98.273  Calculating GHG emissions.

    (a) * * *
    (1) Calculate fossil fuel-based CO2 emissions from 
direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 methodology for stationary combustion 
sources in Sec.  98.33(a)(1). A higher tier from Sec.  98.33(a) may be 
used to calculate fossil fuel-based CO2 emissions if the 
respective monitoring and QA/QC requirements described in Sec.  98.34 
are met.
    (2) Calculate fossil fuel-based CH4 and N2O 
emissions from direct measurement of fossil fuels consumed, default or 
site-specific HHV, and default emissions factors and convert to metric 
tons of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec.  98.33(c).
* * * * *
    (b) * * *
    (1) Calculate fossil CO2 emissions from fossil fuels 
from direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 Calculation Methodology for stationary 
combustion sources in Sec.  98.33(a)(1). A higher tier from Sec.  
98.33(a) may be used to calculate fossil fuel-based CO2 
emissions if the respective monitoring and QA/QC requirements described 
in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuels from direct measurement of fossil fuels consumed, default 
or site-specific HHV, and default emissions factors and convert to 
metric tons of CO2 equivalent according to the methodology 
for stationary combustion sources in Sec.  98.33(c).
* * * * *
    (c) * * *
    (1) Calculate CO2 emissions from fossil fuel from direct 
measurement of fossil fuels consumed and default HHV and default 
emissions factors, according to the Tier 1 Calculation Methodology for 
stationary combustion sources in Sec.  98.33(a)(1). A higher tier from 
Sec.  98.33(a) may be used to calculate fossil fuel-based 
CO2 emissions if the respective monitoring and QA/QC 
requirements described in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuel from direct measurement of fossil fuels consumed, default 
or site-specific HHV, and default emissions factors and convert to 
metric tons of CO2 equivalent according to the methodology 
for stationary combustion sources in Sec.  98.33(c); use the default 
HHV listed in Table C-1 of subpart C and the default CH4 and 
N2O emissions factors listed in Table AA-2 of this subpart.
* * * * *
    44. Section 98.276 is amended by revising the introductory text to 
read as follows:

Sec.  98.276  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c) and the 
applicable information required by Sec.  98.36, each annual report must 
contain the information in paragraphs (a) through (k) of this section 
as applicable:
* * * * *
    45. In the Tables to Subpart AA of Part 98, Table AA-2 is revised 
to read as follows:

[[Page 48811]]

   Table AA-2 of Subpart AA--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CH4 and N2O
----------------------------------------------------------------------------------------------------------------
                                                    Fossil fuel-based emissions factors (kg/mmBtu HHV)
                                         -----------------------------------------------------------------------
                  Fuel                             Kraft lime kilns                     Kraft calciners
                                         -----------------------------------------------------------------------
                                                 CH4               N2O               CH4               N2O
----------------------------------------------------------------------------------------------------------------
Residual Oil                              ................  ................  ................            0.0003
Distillate Oil                            ................  ................            0.0027            0.0004
Natural Gas                                         0.0027                 0  ................            0.0001
Biogas                                    ................  ................  ................            0.0001
Petroleum coke                            ................  ................                NA             \a\NA
----------------------------------------------------------------------------------------------------------------
\a\ Emission factors for kraft calciners are not available.

Subpart OO--[Amended]

    46. Section 98.410 is amended by revising paragraph (b) to read as 
follows:

Sec.  98.410  Definition of the source category.

* * * * *
    (b) To produce a fluorinated GHG means to manufacture a fluorinated 
GHG from any raw material or feedstock chemical. Producing a 
fluorinated GHG includes the manufacture of a fluorinated GHG as an 
isolated intermediate for use in a process that will result in its 
transformation either at or outside of the production facility. 
Producing a fluorinated GHG also includes the creation of a fluorinated 
GHG (with the exception of HFC-23) that is captured and shipped off 
site for any reason, including destruction. Producing a fluorinated GHG 
does not include the reuse or recycling of a fluorinated GHG, the 
creation of HFC-23 during the production of HCFC-22, the creation of 
intermediates that are created and transformed in a single process with 
no storage of the intermediates, or the creation of fluorinated GHGs 
that are released or destroyed at the production facility before the 
production measurement at Sec.  98.414(a).
* * * * *
    47. Section 98.414 is amended by:
    a. Adding a second and third sentence to paragraph (a).
    b. Revising paragraph (h).
    c. Removing and reserving paragraph (j).
    d. Adding new paragraphs (n) through (q).

Sec.  98.414  Monitoring and QA/QC requirements.

    (a) * * * If the measured mass includes more than one fluorinated 
GHG, the concentrations of each of the fluorinated GHGs, other than 
low-concentration constituents, shall be measured as set forth in 
paragraph (n) of this section. For each fluorinated GHG, the mean of 
the concentrations of that fluorinated GHG (mass fraction) measured 
under paragraph (n) of this section shall be multiplied by the mass 
measurement to obtain the mass of that fluorinated GHG coming out of 
the production process.
* * * * *
    (h) You must measure the mass of each fluorinated GHG that is fed 
into the destruction device and that was previously produced as defined 
at Sec.  98.410(b). Such fluorinated GHGs include but are not limited 
to quantities that are shipped to the facility by another facility for 
destruction and quantities that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore destroyed. You must use flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of one percent of full scale or better. If the measured mass 
includes more than trace concentrations of materials other than the 
fluorinated GHG being destroyed, you must estimate the concentrations 
of fluorinated GHG being destroyed considering current or previous 
representative concentration measurements and other relevant process 
information. You must multiply this concentration (mass fraction) by 
the mass measurement to obtain the mass of the fluorinated GHG 
destroyed.
* * * * *
    (n) If the mass coming out of the production process includes more 
than one fluorinated GHG, you shall measure the concentrations of all 
of the fluorinated GHGs, other than low-concentration constituents, as 
follows:
    (1) Analytical Methods. Use a quality-assured analytical 
measurement technology capable of detecting the analyte of interest at 
the concentration of interest and use a procedure validated with the 
analyte of interest at the concentration of interest. Where standards 
for the analyte are not available, a chemically similar surrogate may 
be used. Acceptable analytical measurement technologies include but are 
not limited to gas chromatography (GC) with an appropriate detector, 
infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic 
resonance (NMR). Acceptable methods include EPA Method 18 in Appendix 
A-1 of 40 CFR part 60; EPA Method 320 in Appendix A of 40 CFR part 63; 
the Protocol for Measuring Destruction or Removal Efficiency (DRE) of 
Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated 
by reference, see Sec.  98.7); ASTM D6348-03 Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by 
reference, see Sec.  98.7); or other analytical methods validated using 
EPA Method 301 in Appendix A of 40 CFR part 63 or some other 
scientifically sound validation protocol. The validation protocol may 
include analytical technology manufacturer specifications or 
recommendations.
    (2) Documentation in GHG Monitoring Plan. Describe the analytical 
method(s) used under paragraph (n)(1) of this section in the site GHG 
Monitoring Plan as required under Sec.  98.3(g)(5). At a minimum, 
include in the description of the method a description of the 
analytical measurement equipment and procedures, quantitative estimates 
of the method's accuracy and precision for the analytes of interest at 
the concentrations of interest, as well as a description of how these 
accuracies and precisions were estimated, including the validation 
protocol used.
    (3) Frequency of measurement. Perform the measurements at least 
once by October 12, 2010 if the fluorinated GHG product is being 
produced on August 11, 2010. Perform the measurements within 60 days of 
commencing production of any fluorinated GHG product that was not being 
produced on August 11, 2010.

[[Page 48812]]

Repeat the measurements if an operational or process change occurs that 
could change the identities or significantly change the concentrations 
of the fluorinated GHG constituents of the fluorinated GHG product. 
Complete the repeat measurements within 60 days of the operational or 
process change.
    (4) Measure all product grades. Where a fluorinated GHG is produced 
at more than one purity level (e.g., pharmaceutical grade and 
refrigerant grade), perform the measurements for each purity level.
    (5) Number of samples. Analyze a minimum of three samples of the 
fluorinated GHG product that have been drawn under conditions that are 
representative of the process producing the fluorinated GHG product. If 
the relative standard deviation of the measured concentrations of any 
of the fluorinated GHG constituents (other than low-concentration 
constituents) is greater than or equal to 15 percent, draw and analyze 
enough additional samples to achieve a total of at least six samples of 
the fluorinated GHG product.
    (o) All analytical equipment used to determine the concentration of 
fluorinated GHGs, including but not limited to gas chromatographs and 
associated detectors, IR, FTIR and NMR devices, shall be calibrated at 
a frequency needed to support the type of analysis specified in the 
site GHG Monitoring Plan as required under Sec.  98.414(n) and Sec.  
98.3(g)(5) of this part. Quality assurance samples at the 
concentrations of concern shall be used for the calibration. Such 
quality assurance samples shall consist of or be prepared from 
certified standards of the analytes of concern where available; if not 
available, calibration shall be performed by a method specified in the 
GHG Monitoring Plan.
    (p) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the monitoring requirements of this 
section.
    (q) Low-concentration constituents are exempt from the monitoring 
and QA/QC requirements of this section.
    48. Section 98.416 is amended by:
    a. Revising paragraph (a)(3).
    b. Removing and reserving paragraph (a)(4).
    c. Revising paragraph (a)(11).
    d. Revising paragraphs (c) introductory text and (c)(1).
    e. Revising paragraph (d) introductory text.
    f. Adding paragraphs (f) through (h).

Sec.  98.416  Data reporting requirements.

* * * * *
    (a) * * *
    (3) Mass in metric tons of each fluorinated GHG that is destroyed 
at that facility and that was previously produced as defined at Sec.  
98.410(b). Quantities to be reported under this paragraph (a)(3) of 
this section include but are not limited to quantities that are shipped 
to the facility by another facility for destruction and quantities that 
are returned to the facility for reclamation but are found to be 
irretrievably contaminated and are therefore destroyed.
* * * * *
    (11) Mass in metric tons of each fluorinated GHG that is fed into 
the destruction device and that was previously produced as defined at 
Sec.  98.410(b). Quantities to be reported under this paragraph (a)(11) 
of this section include but are not limited to quantities that are 
shipped to the facility by another facility for destruction and 
quantities that are returned to the facility for reclamation but are 
found to be irretrievably contaminated and are therefore destroyed.
* * * * *
    (c) Each bulk importer of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its imports at the corporate 
level, except for shipments including less than twenty-five kilograms 
of fluorinated GHGs or nitrous oxide, transshipments, and heels that 
meet the conditions set forth at Sec.  98.417(e). The report shall 
contain the following information for each import:
    (1) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG imported in bulk, including each fluorinated GHG constituent of the 
fluorinated GHG product that makes up between 0.5 percent and 100 
percent of the product by mass.
* * * * *
    (d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its exports at the corporate 
level, except for shipments including less than twenty-five kilograms 
of fluorinated GHGs or nitrous oxide, transshipments, and heels. The 
report shall contain the following information for each export:
* * * * *
    (f) By March 31, 2011, all fluorinated GHG production facilities 
shall submit a one-time report that includes the concentration of each 
fluorinated GHG constituent in each fluorinated GHG product as measured 
under Sec.  98.414(n). If the facility commences production of a 
fluorinated GHG product that was not included in the initial report or 
performs a repeat measurement under Sec.  98.414(n) that shows that the 
identities or concentrations of the fluorinated GHG constituents of a 
fluorinated GHG product have changed, then the new or changed 
concentrations, as well as the date of the change, must be reflected in 
a revision to the report. The revised report must be submitted to EPA 
by the March 31st that immediately follows the measurement under Sec.  
98.414(n).
    (g) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the reporting requirements of this 
section.
    (h) Low-concentration constituents are exempt from the reporting 
requirements of this section.
    49. Section 98.417 is amended by revising paragraph (a)(2); and by 
adding paragraphs (f) and (g) to read as follows:

Sec.  98.417  Records that must be retained.

    (a) * * *
    (2) Records documenting the initial and periodic calibration of the 
analytical equipment (including but not limited to GC, IR, FTIR, or 
NMR), weigh scales, flowmeters, and volumetric and density measures 
used to measure the quantities reported under this subpart, including 
the industry standards or manufacturer directions used for calibration 
pursuant to Sec.  98.414(m) and (o).
* * * * *
    (f) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the recordkeeping requirements of this 
section.
    (g) Low-concentration constituents are exempt from the 
recordkeeping requirements of this section.
    50. Section 98.418 is revised to read as follows:

Sec.  98.418  Definitions.

    Except as provided below, all of the terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part. If a conflict exists between a definition provided in this 
subpart and a definition provided in subpart A, the definition in this 
subpart shall take precedence for the reporting requirements in this 
subpart.
    Isolated intermediate means a product of a process that is stored 
before subsequent processing. An isolated intermediate is usually a 
product of chemical synthesis. Storage of an isolated intermediate 
marks the end of a process. Storage occurs at any time the intermediate 
is placed in equipment used solely for storage.
    Low-concentration constituent means, for purposes of fluorinated 
GHG production and export, a fluorinated GHG constituent of a 
fluorinated GHG product that occurs in the product in concentrations 
below 0.1 percent by mass. For purposes of fluorinated GHG

[[Page 48813]]

import, low-concentration constituent means a fluorinated GHG 
constituent of a fluorinated GHG product that occurs in the product in 
concentrations below 0.5 percent by mass. Low-concentration 
constituents do not include fluorinated GHGs that are deliberately 
combined with the product (e.g., to affect the performance 
characteristics of the product).

Subpart PP--[Amended]

    51. Section 98.422 is amended by revising paragraphs (a) and (b) to 
read as follows:

Sec.  98.422  GHGs to report.

    (a) Mass of CO2 captured from production process units.
    (b) Mass of CO2 extracted from CO2 production 
wells.
* * * * *
    52. Section 98.423 is amended by:
    a. Revising the first sentence of paragraph (a) introductory text.
    b. Revising the first sentence of paragraphs (a)(1) and (a)(2).
    c. Redesignating paragraph (b) as paragraph (c) and revising the 
only sentence in newly designated paragraph (c).
    d. Adding a new paragraph (b).

Sec.  98.423  Calculating CO2 Supply.

    (a) Except as allowed in paragraph (b) of this section, calculate 
the annual mass of CO2 captured, extracted, imported, or 
exported through each flow meter in accordance with the procedures 
specified in either paragraph (a)(1) or (a)(2) of this section. * * *
    (1) For each mass flow meter, you shall calculate quarterly the 
mass of CO2 in a CO2 stream in metric tons by 
multiplying the mass flow by the composition data, according to 
Equation PP-1 of this section. * * *
* * * * *
    (2) For each volumetric flow meter, you shall calculate quarterly 
the mass of CO2 in a CO2 stream in metric tons by 
multiplying the volumetric flow by the concentration and density data, 
according to Equation PP-2 of this section. * * *
* * * * *
    (b) As an alternative to paragraphs (a)(1) through (3) of this 
section for CO2 that is supplied in containers, calculate 
the annual mass of CO2 supplied in containers delivered by 
each CO2 stream in accordance with the procedures specified 
in either paragraph (b)(1) or (b)(2) of this section. If multiple 
CO2 streams are used to deliver CO2 to 
containers, you shall calculate the annual mass of CO2 
supplied in containers delivered by all CO2 streams 
according to the procedures specified in paragraph (b)(3) of this 
section.
    (1) For each CO2 stream that delivers CO2 to 
containers, for which mass is measured, you shall calculate 
CO2 supply in containers using Equation PP-1 of this 
section.

Where:

CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration 
measurement of CO2 stream u that delivers CO2 
to containers in quarter p (wt. %CO2).
Qp,u = Quarterly mass of contents supplied in all 
containers delivered by CO2 stream u in quarter p (metric 
tons).
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (2) For each CO2 stream that delivers to containers, for 
which volume is measured, you shall calculate CO2 supply in 
containers using Equation PP-2 of this section.

Where:

CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration 
measurement of CO2 stream u that delivers CO2 
to containers in quarter p (vol. %CO2).
Qp = Quarterly volume of contents supplied in all 
containers delivered by CO2 stream u in quarter p (metric 
tons) (standard cubic meters).
Dp = Quarterly CO2 stream density 
determination for CO2 stream u in quarter p (metric tons 
per standard cubic meter).
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (3) To aggregate data, sum the mass of CO2 supplied in 
containers delivered by all CO2 streams in accordance with 
Equation PP-3 of this section.

Where:

CO2 = Annual mass of CO2 (metric tons) 
supplied in containers delivered by all CO2 streams.
CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
u = CO2 stream that delivers to containers.

    (c) Importers or exporters that import or export CO2 in 
containers shall calculate the total mass of CO2 imported or 
exported in metric tons based on summing the mass in each 
CO2 container using weigh bills, scales, or load cells 
according to Equation PP-4 of this section.
* * * * *
    53. Section 98.424 is amended by revising paragraphs (a)(1), 
(a)(2), (a)(5)introductory text, (a)(5)(ii), the last sentence in 
paragraph (b)(2); and by adding paragraph (c) to read as follows:

Sec.  98.424  Monitoring and QA/QC requirements.

    (a) * * *
    (1) Reporters following the procedures in paragraph (a) of Sec.  
98.423 shall determine quantity using a flow meter or meters located in 
accordance with this paragraph.
    (i) If the CO2 stream is segregated such that only a 
portion is captured for commercial application or for injection, you 
must locate the flow meter after the point of segregation.
    (ii) Reporters that have a mass flow meter or volumetric flow meter 
installed to measure the flow of a CO2 stream that meets the 
requirements of paragraph (a)(1)(i) of this section shall base 
calculations in Sec.  98.423 of this subpart on the installed mass flow 
or volumetric flow meters.
    (iii) Reporters that do not have a mass flow meter or volumetric 
flow meter installed to measure the flow of the CO2 stream 
that meets the requirements of paragraph (a)(1)(i) of this section 
shall base calculations in Sec.  98.423 of this subpart on the flow of 
gas transferred off site using a mass flow meter or a volumetric flow 
meter located at the point of off-site transfer.
    (2) Reporters following the procedures in paragraph (b) of Sec.  
98.423 shall determine quantity in accordance with this paragraph.
    (i) Reporters that supply CO2 in containers using weigh 
bills, scales, or load cells shall measure the mass of contents of each 
CO2 container to which the CO2 stream delivered, 
sum the mass of contents supplied in all containers to which the 
CO2 stream delivered during each quarter, sample the 
CO2 stream delivering CO2 to containers on a 
quarterly basis to determine the composition of the CO2 
stream, and apply Equation PP-1.
    (ii) Reporters that supply CO2 in containers using 
loaded container volumes shall measure the volume of contents of each 
CO2 container to which the CO2 stream delivered, 
sum the volume of contents supplied in all containers to which the 
CO2 stream delivered during each quarter, sample the 
CO2 stream on a quarterly basis to determine the composition 
of the CO2 stream, determine the density quarterly, and 
apply Equation PP-2.
* * * * *
    (5) Reporters using Equation PP-2 of this subpart shall determine 
the density of the CO2 stream on a quarterly basis in order 
to calculate the mass of the CO2 stream according to one of 
the following procedures:
* * * * *
    (ii) You shall follow industry standard practices.

[[Page 48814]]

    (b) * * *
    (2) * * * Acceptable methods include U.S. Food and Drug 
Administration food-grade specifications for CO2 (see 21 CFR 
184.1240) and ASTM standard E1747-95(Reapproved 2005) Standard Guide 
for Purity of Carbon Dioxide Used in Supercritical Fluid Applications 
(incorporated by reference, see Sec.  98.7 of subpart A of this part).
    (c) If you measure the flow of the CO2 stream with a 
volumetric flow meter, you shall convert all measured volumes of carbon 
dioxide to the following standard industry temperature and pressure 
conditions: standard cubic meters at a temperature of 60 degrees 
Fahrenheit and at an absolute pressure of 1 atmosphere. If you apply 
the density value for CO2 at standard conditions, you must 
use must use 0.0018704 metric tons per standard cubic meter.
    54. Section 98.425 is amended by adding a new paragraph (d) to read 
as follows:

Sec.  98.425  Procedures for estimating missing data.

* * * * *
    (d) Whenever the quality assurance procedures in Sec.  98.424(a)(2) 
of this subpart cannot be followed to measure quarterly quantity of 
CO2 in containers, the most appropriate of the following 
missing data procedures shall be followed:
    (1) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during 
another representative quarter of the current reporting year.
    (2) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during the 
same quarter from the past reporting year.
    (3) The quarterly quantity of CO2 in containers recorded 
for purposes of product tracking and billing according to the 
reporter's established procedures may be substituted for any period 
during which measurement equipment is inoperable.
    55. Section 98.426 is amended by:
    a. Revising paragraphs (a) introductory text and (a)(2).
    b. Adding a new paragraph (a)(5).
    c. Revising paragraphs (b) introductory text and (b)(2).
    d. Adding a new paragraph (b)(7).
    e. Revising paragraphs (c) and (e)(1).

Sec.  98.426  Data reporting requirements.

* * * * *
    (a) If you use Equation PP-1 of this subpart, report the following 
information for each mass flow meter or CO2 stream that 
delivers CO2 to containers:
* * * * *
    (2) Quarterly mass in metric tons of CO2.
* * * * *
    (5) The location of the flow meter in your process chain in 
relation to the points of CO2 stream capture, deyhdration, 
compression, and other processing.
    (b) If you use Equation PP-2 of this subpart, report the following 
information for each volumetric flow meter or CO2 stream 
that delivers CO2 to containers:
* * * * *
    (2) Quarterly volume in standard cubic meters of CO2.
* * * * *
    (7) The location of the flow meter in your process chain in 
relation to the points of CO2 stream capture, deyhdration, 
compression, and other processing.
    (c) If you use Equation PP-3 of this subpart report the annual 
CO2 mass in metric tons from all flow meters and 
CO2 streams that delivers CO2 to containers.
* * * * *
    (e) * * *
    (1) The type of equipment used to measure the total flow of the 
CO2 stream or the total mass or volume in CO2 
containers.
* * * * *
[FR Doc. 2010-18354 Filed 8-10-10; 8:45 am]
BILLING CODE 6560-50-P
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