[Federal Register: August 11, 2010 (Volume 75, Number 154)]
[Proposed Rules]
[Page 48743-48814]
[DOCID:fr11au10-29]

-----------------------------------------------------------------------

Part II

Environmental Protection Agency

-----------------------------------------------------------------------

40 CFR Part 98

Mandatory Reporting of Greenhouse Gases; Proposed Rule

-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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<EMAIL_ADDRESS>Include docket ID No. EPA-
HQ-OAR-2008-0508 [and/or RIN number 2060-aq33] in the subject line of
the message.
     Fax:<PHONE_NUMBER>.
     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<PHONE_NUMBER>, and the telephone
number for the Air Docket is<PHONE_NUMBER>.

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:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; e-mail
address<EMAIL_ADDRESS>For technical information contact
the Greenhouse Gas Reporting Rule Hotline at telephone number: (877)
444-1188; or e-mail<EMAIL_ADDRESS>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<PHONE_NUMBER>.
    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<PHONE_NUMBER>, e-mail address:
<EMAIL_ADDRESS>    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:

                               Table 1--Examples of Affected Entities by Category
----------------------------------------------------------------------------------------------------------------
                  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.
----------------------------------------------------------------------------------------------------------------
\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.

    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.
---------------------------------------------------------------------------

    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
---------------------------------------------------------------------------

    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

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

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

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

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

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
<IP_ADDRESS> 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.

     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

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

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

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

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

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 (<= 250 mmBtu/hr or <= 600 tons/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

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 <IP_ADDRESS> of part 75, appendix F, the fuel-specific heat input
values cannot be determined from the emissions reports. This is because
section <IP_ADDRESS> 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

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

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